ARIZONA PUBLIC SERVICE CO - 10-K Annual Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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 any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).
Yes o No x

As of March 15, 2004, there were issued and outstanding 71,264,947 shares of the registrant’s common stock, $2.50 par value, all of which were held beneficially and of record by Pinnacle West Capital Corporation.

APS Energy Services – APS Energy Services Company, Inc., a subsidiary of Pinnacle West

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

GAAP – accounting principles generally accepted in the United States of America

Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation

1999 Settlement Agreement – comprehensive settlement agreement related to the implementation of retail electric competition

Pinnacle West – Pinnacle West Capital Corporation, parent company of the Company

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

PWEC Dedicated Assets – the following Pinnacle West Energy power plants, each of which is dedicated to serving our customers: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3

Salt River Project – Salt River Project Agricultural Improvement and Power District

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

Track A Order – ACC order dated September 10, 2002 regarding generation asset transfers and related issues

Track B Order – ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizona’s investor-owned electric utilities

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

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

We were incorporated in 1920 under the laws of Arizona and currently have more than 931,500 customers. Pinnacle West owns all of our outstanding common stock. We are a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Electricity is delivered through a distribution system that we own. We do not distribute any products. During 2003, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 4% of total electric revenues. Through our marketing and trading division, we generate, sell and deliver electricity to wholesale customers in the western United States. The marketing and trading division also sells, in the wholesale market, our and Pinnacle West Energy generation output that is not needed for our Native Load, which includes loads for retail customers and cost-of-service wholesale customers. The marketing and trading division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. Additionally, the marketing and trading division, subject to specific parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits.

At December 31, 2003, we employed approximately 6,000 people, which includes employees at jointly-owned generating facilities for which we serve as the generating facility manager. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).

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

	•		our regulated electricity segment (95% of operating revenues in 2003), which consists of traditional regulated retail and wholesale electricity businesses and related activities, and includes electricity generation, transmission and distribution; and

	•		our marketing and trading segment (5% of operating revenues in 2003), which consists of our competitive energy business activities, including wholesale marketing and trading.

See Note 15 of Notes to Financial Statements in Item 8 for financial information about our business segments.

We believe our general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3 of Notes to Financial Statements in Item 8, in this

rate case we have requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by us as part of the 1999 Settlement Agreement. In its filed testimony, 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 that our rate case requests are supported by, among other things, our demonstrated need for the PWEC Dedicated Assets; our need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in our high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.

This document contains forward-looking statements based on current expectations, and we assume no 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 “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 us. These factors include, but are not limited to:

	•		state and federal regulatory and legislative decisions and actions, including the outcome of the rate case we filed with the ACC on June 27, 2003 and the wholesale electric price mitigation plan adopted by the FERC;

	•		the outcome of regulatory, legislative and judicial proceedings relating to the restructuring;

	•		the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;

	•		market prices for electricity and natural gas;

	•		power plant performance and outages;

	•		weather variations affecting local and regional customer energy usage;

	•		energy usage;

	•		regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile purchased power and fuel costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;

	•		the cost of debt and equity capital and access to capital markets;

	•		our ability to compete successfully outside traditional regulated markets (including the wholesale market);

	•		the performance of our marketing and trading activities due to volatile market liquidity and deteriorating counterparty credit and the use of derivative contracts in

			our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

	•		changes in accounting principles generally accepted in the United States of America;

	•		regulatory issues associated with generation construction, such as permitting and licensing;

	•		the performance of the stock market and the changing interest rate environment, which affect the amount of our required contributions to our pension plan and nuclear decommissioning trust funds, as well as our reported costs of providing pension and other postretirement benefits;

	•		technological developments in the electric industry;

	•		conservation programs; and

	•		other uncertainties, all of which are difficult to predict and many of which are beyond our control.

The ACC regulates our retail electric rates and our issuance of securities. The ACC must also approve any transfer of our property used to provide retail electric service and approve or receive prior notification of certain transactions between us and affiliated parties. See Note 3 of Notes to Financial Statements in Item 8 for a discussion of the status of electric industry restructuring in Arizona.

The electric utility industry has undergone significant regulatory change in the last few years designed to encourage competition in the sale of electricity and related services. However, the experience in California with deregulation has caused many states, including Arizona, to reexamine retail electric competition.

As of January 1, 2001, all of our retail customers were eligible to choose an alternate energy supplier. However, 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. Also, regulatory developments and legal challenges to the ACC’s electric competition rules have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. See “Retail Electric Competition Rules” in Note 3 of Notes to Financial Statements in Item 8 for additional information.

We are 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 organizations (principally Salt River Project). We also face 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.

The FERC regulates rates for wholesale power sales and transmission services. During 2003, approximately 8% of our electric operating revenues resulted from such sales and services. In early 2003, the marketing and trading division was moved from Pinnacle West to us for all future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy (see “Track A Order” in Note 3 of Notes to Financial Statements in Item 8).

The marketing and trading division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. The division also sells, in the wholesale market, our and Pinnacle West Energy generation output that is not needed for our Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. See “Track B Order” in Note 3 of Notes to Financial Statements in Item 8 for information regarding an ACC-mandated process by which we must competitively procure energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emissions allowances and credits.

Federal 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 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. The 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 which are expected to be completed in 2004.

State The Rules also required the formation and implementation of an Arizona Independent Scheduling Administrator. The purpose of the AISA is to oversee the application of operating protocols to ensure statewide consistency for transmission access. The AISA is anticipated to be a temporary organization until the implementation of an independent system operator or RTO. We participated in the creation of the AISA, a not-for-profit entity, and the filing at the FERC for

approval of its operating protocols. The operating protocols were partially rejected and the remainder are currently under review. In its Track B Order, the ACC directed that a hearing be held on whether or not we should be required to continue funding the AISA.

See “Properties – Net Accredited Capacity” in Item 2 for information about our power plants by fuel types.

Our sources of energy during 2003 were: purchased power – 55.3% (approximately 75.0% of which was for wholesale power operations); coal – 24.5%; nuclear – 17.9%; gas – 2.2%; and other (includes oil, hydro and solar) – 0.1%.

Cholla Cholla is a coal-fired power plant located in northeastern Arizona. It is a jointly-owned facility operated by us. We purchase most of Cholla’s coal requirements from a coal supplier that mines all of the coal under a long-term lease of coal reserves owned by the Navajo Nation, the federal government and private landholders. Cholla has sufficient coal under current contracts to ensure a reliable fuel supply through 2007. This includes our expected requirements for low sulfur coal, which is required for limited operating conditions; however, if necessary, low sulfur coal may be purchased on the open market. We may purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options. Following expiration of current contracts, we believe that numerous competitive fuel supply options will exist to ensure the continued operation of Cholla for its useful life.

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 us. We purchase all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves owned by 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 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 plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. The lease provides for the potential to renegotiate the coal royalty in 2007 and 2017 and a five-year price review, each of which may impact the fuel price.

See “Properties – Net Accredited Capacity” in Item 2 for information about our ownership interests in Cholla, Four Corners and the Navajo Generating Station. See Note 10 of Notes to Financial Statements in Item 8 for information regarding our coal mine reclamation obligations.

See Note 10 of Notes to Financial Statements in Item 8 for a discussion of our natural gas requirements.

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 us. The fuel cycle for Palo Verde is comprised of the following stages:

	•		mining and milling of uranium ore to produce uranium concentrates;

	•		conversion of uranium concentrates to uranium hexafluoride;

	•		enrichment of uranium hexafluoride;

	•		fabrication of fuel assemblies;

	•		utilization of fuel assemblies in reactors; and

	•		storage and disposal of spent nuclear fuel.

The Palo Verde participants 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 and fuel assembly fabrication services until at least 2015.

Spent Nuclear Fuel and Waste Disposal See “Palo Verde Nuclear Generating Station” in Note 10 of Notes to Financial Statements in Item 8 for a discussion of spent nuclear fuel and waste disposal.

In addition to that available from our own generating capacity (see “Properties” in Item 2), we purchase 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 us is based in large part on customer demand within certain areas now served by us pursuant to a related territorial agreement. The generating capacity available to us pursuant to the contract was 343 MW from January through May 2003, and starting in June 2003, it changed to 350 MW. In 2003, we received approximately 952,146 MWh of energy under the contract and paid about $64.4 million for capacity availability and energy received. This contract may be canceled by Salt River Project on three years’ notice, given no earlier than December 31, 2003. To date, Salt River Project has not given any notice to cancel. We may also cancel the contract on five years’ notice, given no earlier than December 31, 2006.

In September 1990, we entered into a thirty-year seasonal capacity exchange agreement with PacifiCorp. Under this agreement, we receive electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and we return electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, we and PacifiCorp each have 480 MW of capacity and a related amount of energy available to us under the agreement for our respective seasons. In 2003, we received approximately 571,392 MWh of energy under the capacity exchange. We must also make additional offers of energy to PacifiCorp each year through October 31, 2020.

Pursuant to this requirement, during 2003, PacifiCorp received offers of 1,091,450 MWh and purchased about 168,000 MWh.

In December 2003, we issued a request for proposals for the purchase of at least 500 MW of long-term power supply resources for delivery beginning June 1, 2007 to be used for our anticipated retail load. For additional information, see “Request for Proposals” in Note 3 of Notes to Financial Statements in Item 8.

Consistent with the ACC’s Track B Order, we issued a request for proposals (“RFP”) in March 2003 and, as a result of that RFP, on or before May 6, 2003, we entered into contracts with three parties, including Pinnacle West Energy, to meet a portion of our capacity and energy requirements for the years 2003 through 2006. See “Track B Order” in Note 3 of Notes to Financial Statements in Item 8 for additional information about the contracts and the Track B Order.

During the years 2001 through 2003, we incurred approximately $1.4 billion in capital expenditures. Our capital expenditures for the years 2004 through 2006 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. Our capital expenditures were approximately $429 million in 2003. Our capital expenditures, including expenditures for environmental control facilities, for the years 2004 through 2006 have been estimated as follows:

The above amounts exclude capitalized interest costs and include capitalized property taxes and approximately $30 million per year for nuclear fuel. These amounts include only our generation (production) assets. We conduct a continuing review of our construction program.

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

Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These new regulations require states to submit, by 2008, implementation plans to eliminate all man-made emissions causing visibility impairment in certain specified areas, including Class I Areas in the Colorado Plateau, and to consider and potentially apply the best available retrofit technology 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. Five western states, including Arizona, have submitted proposed State Implementation Plans (SIPs) to the EPA to implement this alternative plan. If the EPA approves Arizona’s SIP, we do not anticipate any new emission reduction requirements for our Arizona plants through 2013.

With respect to hazardous air pollutants emitted by electric utility steam generating units, the EPA determined in 2000 that mercury emissions and other hazardous air pollutants from coal and oil-fired power plants should be regulated. The EPA recently proposed two alternatives to regulate mercury emissions from these plants. Under the first alternative, the EPA would promulgate a Maximum Achievable Control Technology (MACT) standard establishing mercury emission limitations for coal- and oil-fired power plants, effective 2008. We are currently assessing the need for additional controls to meet this proposed alternative. Under the second alternative, the EPA would rescind its 2000 finding requiring the establishment of a MACT standard for such plants, and would instead establish a two-phased mercury emissions trading program under the Clean Air Act’s new source performance standards provisions. If this second alternative is adopted, we do not anticipate any emission reduction requirements under the first phase of the program (from 2010 through 2018). Because the ultimate requirements that the EPA may impose are not yet known, we cannot currently estimate the capital expenditures, if any, which may be required.

Federal Implementation Plan In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and Four Corners. The FIP is similar to current Arizona regulation of the Navajo Generating Station and New Mexico regulation of Four Corners, with minor modifications. We do not currently expect the FIP to have a material adverse effect on our financial position, results of operations or liquidity.

Superfund The Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised us that the EPA considers us to be a “potentially responsible party” in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. We have facilities that are within this superfund site. The EPA has only recently begun to study the OU3 site. Because the ultimate remediation requirements the EPA may require are not yet known, we cannot currently estimate the expenditures, if any, which may be required.

Manufactured Gas Plant Sites We are currently investigating properties which we now own or which were previously owned by us or our corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. Where appropriate, we conduct clean-up activities for these sites. We do not expect these matters to have a material adverse effect on our financial position, results of operations or liquidity.

ADEQ issued two NOVs to us in 2001 alleging, among other things, the burning of unauthorized materials and storage of hazardous waste without a permit at the Cholla Power Plant. We, the Attorney General for the State of Arizona and ADEQ have reached an agreement (in the form of a Consent Judgment) to settle this matter. The Consent Judgment (No. CV2004-000731) was entered on January 26, 2004, and on February 2, 2004, pursuant to its terms, we paid a $200,000 penalty to the State of Arizona.

ADEQ issued an NOV to us in January 2004 alleging, among other things, that the discharge limit for lead was exceeded at the Saguaro Power Plant. We are in the process of investigating this matter.

Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. We are the Four Corners operating agent. We own a 100% interest in Four Corners Units 1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. We own a 14% interest in Navajo Generating Station Units 1, 2 and 3.

In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Nation as to Four Corners and Navajo Generating Station. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement. We cannot currently predict the outcome of this matter.

In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Indian tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants and the Navajo Generating Station participants that could limit the Navajo Nation’s environmental regulatory authority over the Navajo Generating Station and Four Corners. We believe that the Clean Air Act does not supersede these pre-existing agreements. We cannot currently predict the outcome of this matter.

In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. We believe the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo Generating Station participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. We cannot currently predict the outcome of this matter.

Assured supplies of water are important for our generating plants. At the present time, we have adequate water to meet our 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 our operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. We are 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. (State of New Mexico, in the relation of S.E. Reynolds, State Engineer vs. United States of America, City of Farmington, Utah International, Inc., et al., San Juan County, New Mexico, District Court No. 75-184). 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 a then-agreed upon cost, sufficient water from its allocation to offset the loss.

A summons served on us 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. (In re The General Adjudication of All Rights to Use Water in the Gila River System and Source, Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the geographic area subject to the summons. Our 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, we 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, we seek confirmation of such rights. Three of our other power plants and two of Pinnacle West Energy’s power plants are also located within the geographic area subject to the summons. Our claims dispute the court’s jurisdiction over our groundwater rights with respect to these plants. Alternatively, we seek 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 will continue in the trial court. No trial date concerning our water rights claims has been set in this matter.

We have also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court. (In re The General Adjudication of All Rights to Use Water in the Little Colorado River System and Source, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417). Our groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. Our claims dispute the court’s jurisdiction over our groundwater rights. Alternatively, we seek 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 our water rights claims has been set in this matter.

Although the above matters remain subject to further evaluation, we expect that the described litigation will not have a material adverse impact on our financial position, results of operations 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 in 2004, as well as later years if adequate moisture is not received in the watershed that supplies the area. We are negotiating agreements with various parties to provide backup supplies of water for 2004, if required, and are continuing to work with area stakeholders to implement additional agreements to minimize the effect, if any, on operations of the plant for 2005 and later years. The effect of the drought cannot be fully assessed at this time, and we 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.

Our 2003 peak one-hour demand on our electric system was recorded on July 14, 2003 at 6,332,400 kW, compared to the 2002 peak of 5,802,900 kW recorded on July 9, 2002. Firm purchases totaling 4,198,000 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 12.1%. Taking into account additional capacity then available to us under long-term purchase power contracts as well as our and Pinnacle West Energy’s generating capacity, our capability of meeting system demand on July 14, 2003 amounted to 6,371,600 kW, for an installed reserve margin of 1.0%. The power actually available to us from our resources fluctuates from time to time due in part to outages, both planned and unplanned, and technical problems. The available capacity from sources actually operable at the time of the 2003 peak amounted to 3,736,500 kW, for a margin of negative 50.4%.

See “Purchased Power Agreements” in Item 1 for information about certain of our long-term power agreements. See "Request for Proposals" in Note 3 of Notes to Financial Statements in Item 8 for information regarding a request for proposals issued by us in December 2003 for the purchase of at least 500 MW of long-term power supply resources for delivery beginning June 1, 2007.

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 we do not believe that the risk with respect to enforcement of these easements and leases is material. The majority of coal contracted for use in these plants and certain associated transmission lines are also located on Indian reservations. See “Purchased Power and Generating Fuel – Coal Supply” in Item 1.

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 us, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.

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 to recover certain types of ACC-approved 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 us, the customer will still have to pay this charge as part of the customer’s electric bill.

Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on the external sinking fund mechanism are not met. We currently rely on the external sinking fund mechanism to meet the NRC financial assurance requirements for our interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in our ACC jurisdictional rates. The Rules provide that decommissioning costs would be recovered through a non-bypassable “system benefits” charge, which would allow us to maintain our external sinking fund mechanism. See Note 11 of Notes to Financial Statements in Item 8 for additional information about our nuclear decommissioning costs.

See “Palo Verde Nuclear Generating Station” in Note 10 of Notes to Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including us, for Palo Verde.

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

(b)		Weighted average of interests.

In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. We account for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. See Notes 8 and 18 of Notes to Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale-leaseback transactions.

Our first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). See Note 6 of Notes to Financial Statements in Item 8 for information regarding our outstanding first mortgage bonds.

Our transmission facilities consist of approximately 5,000 pole miles of overhead lines and approximately 35 miles of underground lines, all of which are located within the State of Arizona. Our distribution facilities consist of approximately 12,000 pole miles of overhead lines and approximately 13,000 miles of underground lines, all of which are located within the State of Arizona. In June 2003 we energized a new 37-mile 500-kilovolt transmission line that runs from Palo Verde to the Phoenix area. See also “Regional Transmission Organizations” in Item 1.

See “Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of our power plants.

See “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 our construction program.

See “Environmental Matters” and “Water Supply” in Item 1 in regard to pending or threatened litigation and other disputes. See Note 3 of Notes to Financial Statements in Item 8 for a discussion of the ACC retail electric competition Rules, the Track A Order and related litigation.

See Note 10 of Notes to Financial Statements in Item 8 for information relating to the FERC proceedings on California energy market issues and a claim by Citizens that we overcharged Citizens under a power service agreement.

Our 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 our common stock.

The chart below sets forth the dividends declared on the Company’s common stock for each of the four quarters for 2003 and 2002.

After payment or setting aside for payment of cumulative dividends and mandatory sinking fund requirements, where applicable, on all outstanding issues of preferred stock, the holders of common stock are entitled to dividends when and as declared out of funds legally available therefor. As of December 31, 2003, we did not have any outstanding preferred stock.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the Financial Statements and the related Notes that appear in Item 8 of this report.

We are a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Through our marketing and trading division, we generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading division also sells, in the wholesale market, our and Pinnacle West Energy’s generation output that is not needed for our Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. Our service territory growth is about three times the national average and remains a fundamental driver of our revenues and earnings. We do not distribute any products. Pinnacle West owns all of our outstanding common stock.

Pinnacle West Energy is our unregulated generation affiliate. Pinnacle West formed Pinnacle West Energy in 1999 as a result of the ACC’s requirement that we transfer all of our competitive assets and services to an affiliate or to a third party by the end of 2002. We planned to transfer our generation assets to Pinnacle West Energy. Additionally, Pinnacle West Energy constructed several power plants to meet growing energy needs (1790 MW in Arizona and 570 MW in Nevada). In September 2002, the ACC issued the Track A Order, which prohibited us from transferring our generation assets to Pinnacle West Energy. As a result of the Track A Order, we are seeking to transfer the plants built by Pinnacle West Energy in Arizona to us to unite the Arizona generation under one common owner, as originally intended.

The earnings contributions of our marketing and trading segment decreased in 2002 due to the transfer of our marketing and trading division to Pinnacle West. In the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West). In 2003, the earnings contributions of our marketing and trading segment was negative due to low market liquidity and deteriorating counterparty credit in the wholesale power markets in the western United States. The marketing and trading division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. We currently expect contributions from our trading activities to be negligible for 2004 and approximately $10 million (pretax) annually thereafter.

We continue to focus on solid operational performance in our electricity generation and delivery activities. In the generation area, 2003 represented the twelfth consecutive year Palo Verde was the largest power producer in the United States. In the delivery area, we focus on superior reliability and expanding our transmission and distribution system to meet growth and sustain reliability.

We believe our general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3 in Item 8, in this rate case we have requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by us as part of the 1999 Settlement Agreement. In its filed testimony, 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 that our rate case requests are supported by, among other things, our demonstrated need for the PWEC Dedicated Assets; our need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in our high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.

Other factors affecting our past and future financial results include customer growth; purchased power and fuel costs; operations and maintenance expenses, including those relating to plant outages; weather variations; depreciation and amortization expenses, which are affected by net additions to existing utility plant and other property and changes in regulatory asset amortization.

We have two principal business segments (determined by services and the regulatory environment):

	•		our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses and related activities, and includes electricity generation, transmission and distribution; and

	•		our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading. During 2001, we transferred most of our marketing and trading activities to Pinnacle West. Thus, we did not have any significant marketing and trading activity in 2002. Conversely, in the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West). This latest move was a result of the ACC’s Track A Order prohibiting the previously-required transfer of our generating assets to Pinnacle West Energy.

The following table summarizes earnings by business segment for the years ended December 31, 2003, 2002, and 2001 (dollars in millions):

(a)		We recorded a $15 million after-tax charge in 2001 for the cumulative effect of a change in accounting for derivatives related to the adoption of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” See Note 16.

		See Note 15 for additional financial information regarding our business segments.

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 purchased power and fuel costs. In addition, we have reclassified certain prior period amounts to conform to our current period presentation, including netting of certain revenues and purchased power amounts as a result of the adoption of EITF 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3” (see Note 16).

Our net income for the year ended December 31, 2003 was $181 million compared with $199 million for the prior year. The $18 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:

•

Regulated Electricity Segment – Net income decreased $14 million due to higher purchased power and fuel costs resulting from higher prices for hedged gas and purchased power; higher replacement power costs from plant outages due to higher market prices and more unplanned outages (Unit 3 of the Cholla Power Plant experienced an unplanned outage from August 3, 2003 through November, 2003); higher operations and maintenance costs related to increased pension and other benefits; two retail electricity price reductions; and higher depreciation expense related to increased delivery and other assets. These negative factors were partially offset by higher retail sales primarily due to customer growth and favorable weather; lower operating costs primarily related to severance costs recorded in 2002; lower regulatory asset amortization; tax credits and favorable income tax adjustments related to prior years resolved in 2003; and higher income related to our return to the AFUDC method of capitalizing construction finance costs.

•

Marketing and Trading Segment –Net income decreased approximately $4 million primarily due to the higher payroll costs incurred related to the transfer of the marketing and trading division from Pinnacle West to us, partially offset by increased generation sales other than Native Load primarily due to higher sales volumes, partially offset by lower unit margins.

Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2003 compared with the prior year are contained in the following table (dollars in millions).

Regulated electricity segment revenues were $97 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:

	•		an $85 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

	•		a $21 million increase in retail revenues related to weather;

	•		a $6 million increase related to traditional wholesale sales as a result of higher prices and higher sales volumes;

	•		a $27 million decrease in retail revenues related to two reductions in retail electricity prices; and

	•		a $12 million net increase due to miscellaneous factors.

Marketing and trading segment revenues were $71 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:

	•		a $66 million increase from generation sales other than Native Load primarily due to higher prices and sales volumes, including sales from new power plants in service;

	•		a $5 million net increase due to miscellaneous factors.

Our net income for the year ended December 31, 2002 was $199 million compared with $265 million for the prior year. In 2001, we recognized a $15 million after-tax charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133 (see Note 16). Excluding the accounting changes, the $81 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:

	•		Regulated Electricity Segment – Income before accounting change increased $60 million primarily due to lower replacement power costs for power plants outages, retail customer growth, higher average customer usage and lower purchased power costs related to 2001 generation reliability program (the addition of generation capability to enhance reliability for the summer of 2001). These positive factors were partially offset by severance costs recorded in 2002 relating to voluntary workforce reductions, retail electricity price decreases, the effects of milder weather and higher costs for purchased power and gas due to higher hedged gas and power prices.

	•		Marketing and Trading Segment – Income before accounting change decreased $141 million primarily due to our transfer of the marketing and trading activities to Pinnacle West in 2001.

Additional details on the major factors that increased (decreased) income before accounting change and net income for the year ended December 31, 2002 compared with the prior year are contained in the following table (dollars in millions).

Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $82 million lower in the year ended December 31, 2002, compared with the prior year as a result of:

	•		a $64 million decrease in revenues related to traditional wholesale sales as a result of lower sales volumes and lower prices;

	•		a $69 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

	•		a $28 million decrease in retail revenues related to reductions in retail electricity prices;

	•		a $60 million decrease in retail revenues related to milder weather; and

	•		a $1 million net increase due to other miscellaneous factors.

Marketing and trading segment revenues were $334 million lower in the year ended December 31, 2002, compared with the prior year as a result of:

	•		$206 million of lower marketing and trading revenues as a result of our transfer of marketing and trading activities to Pinnacle West in 2001; and

	•		a $128 million decrease from generation sales other than Native Load primarily due to lower market prices partially offset by higher sales volumes.

The following table summarizes the actual capital expenditures for the year ended December 31, 2003 and estimated capital expenditures for the next three years.

(a)		As discussed in Note 3 under “General Rate Case and Retail Rate Adjustment Mechanisms,” as part of our 2003 general rate case, we requested rate base treatment of the PWEC Dedicated Assets. Pinnacle West Energy actual capital expenditures related to PWEC Dedicated Assets were $49 million for 2003 and are estimated to be $15 million in 2004, $21 million in 2005 and $4 million in 2006.

(b)		The other amounts relate to capital expenditures for our marketing and trading segment. In 2002, these costs were in the parent company.

Delivery capital expenditures are comprised of T&D 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 T&D lines and substations, line extensions to new residential and commercial developments and upgrades to customer information

systems. We completed The Southwest Valley transmission project in 2003 at a cost of approximately $70 million. Major transmission projects are driven by strong regional customer growth. We will begin major projects each year for the next several years, and expect to spend about $200 million on major transmission projects during the 2004 to 2006 time frame. These amounts are included in “Delivery” in the table above. Completion of these projects will stretch from 2005 through at least 2008.

Generation capital expenditures are comprised of various improvements to our existing fossil and nuclear plants and the replacement of Palo Verde steam generators. 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 $30 million annually for 2004 to 2006.

Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall outage of 2003 at a cost of approximately $70 million. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. These generators will be installed in Unit 1 (scheduled completion in 2005) and Unit 3 (scheduled completion in 2007). Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million which will be spent through 2008. In 2004 through 2006, approximately $90 million of the Unit 1 and Unit 3 costs are included in the generation capital expenditures table above and will be funded with internally-generated cash or external financings.

Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See Note 3 for discussion of the $500 million financing arrangement between us and Pinnacle West Energy approved by the ACC.

We pay for our capital requirements with cash from operations and, to the extent necessary, external financings. We have historically paid for our dividends to Pinnacle West with cash from operations. We must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce our common equity below that threshold. As defined in the Financing Order, 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, our common equity ratio was approximately 45.7%.

On April 7, 2003, we redeemed approximately $33 million of our First Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, we redeemed approximately $54 million of our First Mortgage Bonds, 7.25% Series due 2023.

On February 15, 2004, $125 million of our 5.875% Notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of our First Mortgage Bonds, 6.625% Series due 2004 were redeemed at maturity. We used cash from operations and short-term debt to redeem the maturing debt.

On May 12, 2003, we issued $500 million of debt as follows: $300 million aggregate principal amount of our 4.65% Notes due 2015 and $200 million aggregate principal amount of our 5.625% Notes due 2033. Also on May 12, 2003, we made a $500 million loan to Pinnacle West Energy.

Our outstanding debt was approximately $2.6 billion at December 31, 2003. At December 31, 2003, we had unused credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2003, we had no outstanding commercial paper or bank borrowings. We ended 2003 in an invested position.

Although provisions in our first mortgage bond indenture, articles of incorporation and ACC financing orders establish maximum amounts of additional first mortgage bonds, debt and preferred stock that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements.

We participate in a pension plan sponsored by Pinnacle West. Pinnacle West contributes 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. Pinnacle West elected to contribute cash to our pension plan in each of the last five years; our minimum required contributions during each of those years was zero. Specifically, Pinnacle West contributed $73 million for 2002 ($46 million of which was contributed in June 2003); $24 million for 2001; $44 million for 2000 ($20 million of which was contributed in 2001); and $25 million for 1999. We fund our share of the pension contribution. In 2003, we represented 89% of the total cost of this plan. The assets in the plan are mostly domestic common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. Under current law, Pinnacle West is required to contribute approximately $100 million to its pension plans and expects to contribute approximately $50 million to its other postretirement benefit plan in 2004. If currently pending legislation is enacted, Pinnacle West’s required pension contribution in 2004 would decrease to the $25 to $50 million range.

The following table summarizes contractual requirements as of December 31, 2003 (dollars in millions):

(a)		The long-term debt matures at various dates through fiscal year 2034 and bears interest principally at fixed rates. Interest on variable long-term debt is set at the December 31, 2003 rates.

(b)		If currently pending legislation is enacted, our share of the required pension contribution in 2004 would decrease to the $22 to $44 million range. Future pension contributions are not determinable for time periods after 2004.

(c)		Our purchase power and fuel commitments include purchases of coal, electricity, natural gas, and nuclear fuel (see Note 10).

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

In 2003, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities,” as it applies to special-purpose entities. FIN No. 46R requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. In 1986, we entered into agreements with three separate SPE 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. See Note 8 for further information about the sale leaseback transactions. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs. Certain provisions of FIN No. 46R have a future effective date. We do not expect these provisions to have a material impact on our financial statements.

We are exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that we do 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), we 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, 2003, we would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

We have entered into various agreements that require letters of credit for financial assurance purposes. We generally provide indemnifications relating to liabilities arising from or related to certain of our agreements, except with limited exceptions depending on the particular agreement. We have also provided indemnifications to the equity participants and other parties in the Palo Verde saleleaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnifications is likely and therefore no related liability has been recorded. See Note 19 for additional information about our guarantees and letters of credit.

The ratings of our securities as of March 11, 2004 are shown below and are considered to be “investment-grade” ratings. 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 our 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 16).

Our debt covenants related to our financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. We comply with such covenants and we anticipate we will continue to meet all the significant covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65%. At December 31, 2003, our ratio was approximately 53%. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements. Based on 2003 results, coverage is approximately 4 times for our bank financing agreements and 15 times for our mortgage indenture. 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.

Our financing agreements do not contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, we may be subject to increased interest costs under certain financing agreements.

All of our bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if we were to default under other agreements. Our credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in financial condition or financial prospects.

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. We had $165 million of regulatory assets on the Balance Sheets at December 31, 2003. See Notes 1 and 3 for more information about regulatory assets and our general rate case.

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 2003 projected benefit obligation, the 2003 reported pension liability on the Pinnacle West Consolidated Balance Sheets and the 2003 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Pinnacle West Consolidated Statements of Income (dollars in millions):

(a)

Each fluctuation assumes that the other assumptions of the calculation are held constant.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the 2003 accumulated other postretirement benefit obligation and the 2003 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on the Pinnacle West Consolidated Statements of Income (dollars in millions):

(a)		Each fluctuation assumes that the other assumptions of the calculation are held constant.

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

See Note 7 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, 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)). See “Market Risks – Commodity Price Risk” below for quantitative analysis. See Note 16 for a further discussion on derivative and energy trading 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. See “Market Risks – Commodity Price Risk” below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 16 for a further discussion on derivative and energy trading accounting.

We adopted EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provides guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs, reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows.

Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. We adopted the EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” in the fourth quarter of 2002. The impact of the guidance was immaterial to our financial statements.

In 2001, we adopted SFAS No. 133 and recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income), both as a cumulative effect of a change in accounting for derivatives.

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” The standard requires the fair value of asset retirement obligations to be recorded as a liability, along with an offsetting plant asset, when the obligation is incurred. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. (See Note 1 for more information regarding our previous accounting for removal costs.)

We determined that we have asset retirement obligations for our nuclear facilities (nuclear decommissioning) and certain other generation, transmission and distribution assets. On January 1, 2003, we recorded a liability of $219 million for our asset retirement obligations including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a regulatory liability of $40 million for our asset retirement obligations related to our regulated utility. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs

calculated in accordance with SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (see Note 1) and SFAS No. 143 (see Note 11). Adopting SFAS No. 143 had no impact on our Statements of Income or our Statements of Cash Flow.

See “Liquidity and Capital Resources – Off-Balance Sheet Arrangements” and Note 18 for discussion of VIEs.

We believe our general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3, in this rate case we have requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by us as part of the 1999 Settlement Agreement. In its filed testimony, 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 that our rate case requests are supported by, among other things, our demonstrated need for the PWEC Dedicated Assets; our need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in our high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.

The marketing and trading division, which Pinnacle West moved to us in early 2003 for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting our transfer of generating assets to Pinnacle West Energy, focuses primarily on managing our purchased power and fuel risks in connection with our cost in serving retail customer demand. Additionally, 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. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities. Based on the erosion in the market and on the market outlook, we currently expect contributions from our trading activities to be negligible for 2004, and approximately $10 million (pretax) annually thereafter.

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 expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity prices and variations in weather from period to period

Customer Growth Customer growth in our service territory averaged about 3.4% a year for the three years 2001 through 2003; we currently expect customer growth to average about 3.5% per year from 2004 to 2006. We currently estimate that total retail electricity sales in kilowatt-hours will grow 4.9% on average, from 2004 through 2006, before the retail effects of weather variations. The customer and sales growth referred to in this paragraph applies to Native Load customers. Customer growth for the year ended December 31, 2003 compared with the prior year period was 3.3%.

Retail Rate Changes As part of the 1999 Settlement Agreement, we agreed to a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. The final price reduction was implemented July 1, 2003. See “1999 Settlement Agreement” in Note 3 for further information. In addition, the Company has requested a 9.8% retail rate increase to be effective July 1, 2004. See “General Rate Case and Retail Rate Adjustment Mechanisms” in Note 3 for further information.

Purchased Power and Fuel Costs Purchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, prevailing market prices, new generating plants being placed in service and our hedging program for managing such costs. See “Natural Gas Supply” in Note 10 for more information on fuel costs.

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 existing utility plant and other property, changes in regulatory asset amortization and our generation construction program. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

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. Our average property tax rate was 9.3% of assessed value for 2003 and 9.7% for 2002.

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. As noted above, we placed new power plants in commercial operation in 2001, 2002 and 2003 and we expect to bring an additional plant on-line in 2004. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs. In addition, see Note 1 for a discussion of AFUDC.

Retail Competition The regulatory developments and legal challenges to the Rules discussed in Note 3 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 providing 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.

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

Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by the nuclear decommissioning trust fund and our pension plans.

Our major financial market risk exposure is 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 11). 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 changing market values of equity investments. Nuclear decommissioning costs are recovered in regulated electricity prices.

The table below presents contractual balances of our long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2003. The interest rates presented in the table below represent the weighted-average interest rates for the year ended December 31, 2003 (dollars in thousands):


						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
	Rates			Amount		Rates			Amount		Rates			Amount
2004		—	%	$	—		—	%	$	—		6.16	%	$	206,727
2005		—			—		—			—		7.27	%		402,259
2006		—			—		—			—		6.73	%		85,451
2007		—			—		—			—		5.55	%		1,134
2008		—			—		—			—		5.55	%		1,098
Years thereafter		—			—		1.51	%		386,860		5.83	%		1,547,775

Total				$					$	386,860				$	2,244,444

Fair value				$					$	386,906				$	2,365,821

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. The ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:

• Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements of our regulated electricity business segment; and

• Marketing and Trading – non-trading and trading derivative instruments of our competitive business segment.

The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions in 2003 and 2002 (dollars in millions):


	Regulated			Marketing
	Electricity			and Trading
Mark-to-market of net positions at December 31, 2002	$	(50	)	$	—
Change in mark-to-market losses for future period deliveries		—			(4	)
Changes in cash flow hedges recorded in OCI		37			3
Ineffective portion of changes in fair value recorded in earnings		7			—
Mark-to-market losses/(gains) realized during the year		6			(3	)

Mark-to-market of net positions at December 31, 2003	$	—		$	(4	)


	Regulated			Marketing
	Electricity			and Trading
Mark-to-market of net positions at December 31, 2001	$	(107	)	$	—
Change in mark-to-market losses for future period deliveries		(22	)		—
Changes in cash flow hedges recorded in OCI		64			—
Ineffective portion of changes in fair value recorded in earnings		8			—
Mark-to-market losses realized during the year		7			—

Mark-to-market of net positions at December 31, 2002	$	(50	)	$	—

The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2003 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Mark-to-Market Accounting,” for more discussion on our valuation methods.

Regulated Electricity


								Total
						Years		fair
Source of Fair Value	2004			2005		thereafter		value
Prices actively quoted	$	(4	)	$	3	$	—	$	(1	)
Prices provided by other external sources		2			—		—		2
Prices based on models and other valuation methods		(1	)		—		—		(1	)

Total by maturity	$	(3	)	$	3	$	—	$	—

Marketing and
Trading


									Total
							Years		fair
Source of Fair Value	2004			2005			thereafter		value
Prices actively quoted	$	(3	)	$	—		$	—	$	(3	)
Prices provided by other external sources		2			—			—		2
Prices based on models and other valuation methods		(2	)		(1	)		—		(3	)

Total by maturity	$	(3	)	$	(1	)	$	—	$	(4	)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on the Balance Sheets at December 31, 2003 (dollars in millions):


	December 31, 2003
	Gain (Loss)
Commodity	Price Up 10%			Price Down 10%
Mark-to-market changes reported in earnings (a):
Electricity	$	(2	)	$	2
Mark-to-market changes reported in OCI (b):
Electricity		5			(5	)
Natural gas		31			(30	)

Total	$	34		$	(33	)

(a) These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.

(b) These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. See Note 1, “Mark-to-Market Accounting” for a discussion of our credit valuation adjustment policy. See Note 16 for further discussion of credit risk.

Risk Factors

Exhibit 99.1, which is hereby incorporated by reference, contains a discussion of risk factors affecting the Company.

Forward-Looking Statements

• state and federal regulatory and legislative decisions and actions, including the outcome of the rate case we filed with the ACC on June 27, 2003 and the wholesale electric price mitigation plan adopted by the FERC;

• the outcome of regulatory, legislative and judicial proceedings relating to the restructuring;

• the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;

• market prices for electricity and natural gas;

• power plant performance and outages;

• weather variations affecting local and regional customer energy usage;

• energy usage;

• regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile purchased power and fuel costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;

• the cost of debt and equity capital and access to capital markets;

• our ability to compete successfully outside traditional regulated markets (including the wholesale market);

• the performance of our marketing and trading activities due to volatile market liquidity and deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

• changes in accounting principles generally accepted in the United States of America;

• regulatory issues associated with generation construction, such as permitting and licensing;

• the performance of the stock market and the changing interest rate environment, which affect the amount of our required contributions to our pension plan and nuclear decommissioning trust funds, as well as our reported costs of providing pension and other postretirement benefits;

• technological developments in the electric industry;

• conservation programs; and

• other uncertainties, all of which are difficult to predict and many of which are beyond our control.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS


Management’s Report on Internal Control Over Financial Reporting	44
Independent Accountants’ Report	45
Independent Auditors’ Report	46
Statements of Income for 2003, 2002 and 2001	47
Balance Sheets as of December 31, 2003 and 2002	48
Statements of Cash Flows for 2003, 2002 and 2001	50
Statements of Changes in Common Stock Equity for 2003, 2002 and 2001	51
Notes to Financial Statements	52
Financial Statement Schedule for 2003, 2002 and 2001 Schedule II – Reserve for Uncollectibles for 2003, 2002 and 2001	104

See Note 12 for the selected quarterly financial data required to be presented in this Item.

MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING

Management at APS has always understood and accepted responsibility for our financial statements and related disclosures and the effectiveness of internal control over financial reporting (“internal control”). Just as we do throughout all aspects of our business, we continuously strive to identify opportunities to enhance the effectiveness and efficiency of internal control.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act will require our 2004 Annual Report to contain a management’s report and an independent accountants’ report regarding the effectiveness of internal control. However, in this 2003 Annual Report, we chose to voluntarily include this report on internal control. As a basis for our report, we tested and evaluated the design, documentation, and operating effectiveness of internal control.

In early March 2004, the PCAOB issued its auditing standard, which may require changes to the processes we utilize to test and evaluate the design, documentation, and operating effectiveness of internal control and may affect our future internal control disclosures. Based on our assessment as of December 31, 2003, we make the following assertion:

• Management is responsible for establishing and maintaining effective internal control over financial reporting of Arizona Public Service Company (the “Company”). The internal control contains monitoring mechanisms, and actions are taken to correct deficiencies identified.

• There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

• Management evaluated the Company’s internal control over financial reporting as of December 31, 2003. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2003.

March 11, 2004

INDEPENDENT ACCOUNTANTS’ REPORT

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

We have examined the accompanying management’s assertion that Arizona Public Service Company (the “Company”) maintained effective internal control over financial reporting as of December 31, 2003, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting. Our responsibility is to express an opinion on management’s assertion based on our examination.

Our examination was conducted in accordance with attestation standards established by the American Institute of Certified Public Accountants (“AICPA”) and, accordingly, included obtaining an understanding of the internal control over financial reporting, testing and evaluating the design and operating effectiveness of the internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion.

Because of inherent limitations in any internal control, misstatements due to error or fraud may occur and not be detected. Also, projections of any evaluation of the internal control over financial reporting to future periods are subject to the risk that the internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assertion that the Company maintained effective internal control over financial reporting as of December 31, 2003 is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

An examination of management’s assertion regarding the effectiveness of internal control under AICPA standards may not be the same in scope as an audit of internal control under the current proposed standards of the Public Company Accounting Oversight Board (the “PCAOB”) and, accordingly, may not necessarily result in the same conclusion or disclose all matters in internal control that might ultimately be noted in performing an audit under PCAOB standards when they are finally adopted. Accordingly, our examination of the accompanying Management’s Report on Internal Control Over Financial Reporting is not intended to comply with, and should not be relied upon for compliance with, the U.S. Securities and Exchange Commission rule relating to Section 404 or Section 103 of the Sarbanes-Oxley Act of 2002.

DELOITTE & TOUCHE LLP

Phoenix, Arizona
March 11, 2004

INDEPENDENT AUDITORS’ REPORT

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

We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2003 and 2002 and the related statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Arizona Public Service Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 16 to the financial statements, in 2003 Arizona Public Service Company changed its method of accounting for non-trading derivatives in order to comply with the provisions of Emerging Issues Task Force Issue No. 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3.

As discussed in Note 16 to the financial statements, in 2001 Arizona Public Service Company changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.

DELOITTE & TOUCHE LLP

Phoenix, Arizona
March 11, 2004

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME


	Year Ended December 31,
	2003			2002			2001
	(dollars in thousands)
Electric Operating Revenues:
Regulated electricity segment	$	1,999,390		$	1,902,112		$	1,984,305
Marketing and trading segment		105,541			34,054			367,793

Total		2,104,931			1,936,166			2,352,098

Purchased Power and Fuel Costs:
Regulated electricity segment		606,251			438,141			649,405
Marketing and trading segment		97,180			32,662			132,544

Total		703,431			470,803			781,949

Operating Revenues less Purchased Power and Fuel Costs		1,401,500			1,465,363			1,570,149
Other Operating Expenses:
Operations and maintenance		513,604			495,845			465,561
Depreciation and amortization		389,240			399,640			420,893
Income taxes (Note 4)		91,646			132,953			183,640
Other taxes		108,852			107,925			101,077

Total		1,103,342			1,136,363			1,171,171

Operating Income		298,158			329,000			398,978

Other Income (Deductions):
Income taxes (Note 4)		4,792			6,148			504
Allowance for equity funds used during construction		14,240			—			—
Other income (Note 17)		20,277			5,149			20,207
Other expense (Note 17)		(12,962	)		(19,338	)		(20,790	)

Total		26,347			(8,041	)		(79	)

Interest Deductions:
Interest on long-term debt		142,706			128,462			126,118
Interest on short-term borrowings		4,904			5,416			4,407
Debt discount, premium and expense		3,337			2,888			2,650
Capitalized interest		(7,379	)		(15,150	)		(14,964	)

Total		143,568			121,616			118,211

Income Before Accounting Change		180,937			199,343			280,688
Cumulative Effect of Change in Accounting for Derivatives – net of income taxes of $9,892		—			—			(15,201	)

Net Income	$	180,937		$	199,343		$	265,487

See Notes to Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS


	December 31,
	2003			2002
	(dollars in thousands)
Utility Plant (Notes 1, 6, 8, 9 and 11)
Electric plants in service and held for future use	$	8,826,033		$	8,299,131
Less accumulated depreciation and amortization		3,089,645			2,885,798

Total		5,736,388			5,413,333
Construction work in progress		187,478			329,089
Intangible assets, net of accumulated amortization		94,181			93,259
Nuclear fuel, net of accumulated amortization of $58,053 and $59,163		52,011			51,124

Utility Plant – net		6,070,058			5,886,805

Investments and Other Assets
Notes Receivable from Pinnacle West Energy (Notes 1 and 3)		497,865			—
Decommissioning trust accounts (Note 11)		240,645			194,440
Assets from risk management and trading activities – long-term		18,001			31,622
Other assets		64,119			57,380

Total Investments and Other Assets		820,630			283,442

Current Assets:
Cash and cash equivalents		112,002			42,549
Accounts receivable:
Service customers		190,884			136,945
Other (Note 1)		67,540			202,597
Allowance for doubtful accounts		(3,743	)		(1,341	)
Accrued utility revenues		71,501			72,915
Materials and supplies (at average cost)		80,682			79,985
Fossil fuel (at average cost)		28,360			28,185
Deferred income taxes (Note 4)		—			4,094
Assets from risk management and trading activities		52,448			39,616
Other		6,969			7,945

Total Current Assets		606,643			613,490

Deferred Debits:
Regulatory assets (Notes 1 and 3)		164,804			241,045
Unamortized debt issue costs		19,797			16,696
Other		73,056			80,760

Total Deferred Debits		257,657			338,501

Total Assets	$	7,754,988		$	7,122,238

See Notes to Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES AND EQUITY


	December 31,
	2003			2002
	(dollars in thousands)
Capitalization:
Common stock	$	178,162		$	178,162
Additional paid-in capital		1,246,804			1,246,804
Retained earnings		830,569			819,632
Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		(57,158	)		(61,487	)
Derivative instruments		5,253			(23,799	)

Common stock equity		2,203,630			2,159,312
Long-term debt less current maturities (Note 6)		2,415,946			2,217,340

Total Capitalization		4,619,576			4,376,652

Current Liabilities:
Current maturities of long-term debt (Note 6)		206,727			3,503
Accounts payable		131,383			118,133
Accrued taxes		90,474			82,557
Accrued interest		42,702			42,608
Customer deposits		45,481			39,865
Deferred income taxes (Note 4)		631			—
Liabilities from risk management and trading activities		58,138			59,773
Other		60,008			51,820

Total Current Liabilities		635,544			398,259

Deferred Credits and Other:
Deferred income taxes (Note 4)		1,248,397			1,225,552
Regulatory Liabilities (Notes 1, 3 and 4)		510,423			26,264
Liability for asset retirements and removals (Note 11)		234,440			600,431
Pension liability (Note 7)		160,639			156,442
Unamortized gain – sale of utility plant (Note 8)		54,909			59,484
Customer advances for construction		52,783			45,513
Liabilities from risk management and trading activities		4,502			36,678
Other		233,775			196,963

Total Deferred Credits and Other		2,499,868			2,347,327

Commitments and Contingencies (Note 10)
Total Liabilities and Equity	$	7,754,988		$	7,122,238

See Notes to Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2003			2002			2001
	(dollars in thousands)
Cash Flows from Operating Activities:
Net income	$	180,937		$	199,343		$	265,487
Items not requiring cash:
Depreciation and amortization		389,240			399,640			420,893
Nuclear fuel amortization		28,757			31,185			28,362
Allowance for equity funds used during construction		(14,240	)		—			—
Deferred income taxes		(1,087	)		206,767			(26,516	)
Change in derivative mark-to-market valuations		2,339			2,957			(100,030	)
Cumulative effect of change in accounting – net of income taxes		—			—			15,201
Changes in certain current assets and liabilities:
Accounts receivable		83,692			(102,450	)		302,283
Materials, supplies and fossil fuel		(872	)		68			(16,867	)
Other current assets		2,390			5,443			(5,385	)
Accounts payable		17,961			15,372			(190,141	)
Accrued taxes		7,917			(25,038	)		1,080
Accrued interest		94			1,565			1,555
Other current liabilities		13,804			44,224			(58,361	)
Increase in regulatory assets		(11,697	)		(11,029	)		(17,516	)
Change in risk management trading – assets		12,551			(22,570	)		10,730
Change in customer advances		7,270			(23,780	)		28,599
Change in pension liability		17,395			7,016			(35,244	)
Change in other long-term assets		(14,623	)		(24,502	)		(13,967	)
Change in other long-term liabilities		55,296			301			(5,088	)

Net cash flow provided by operating activities		777,124			704,512			605,075

Cash Flows from Investing Activities:
Capital expenditures		(426,260	)		(490,156	)		(465,360	)
Capitalized interest		(7,379	)		(15,150	)		(14,964	)
Loan to Pinnacle West Energy		(497,865	)		—			—
Other		(8,296	)		44,918			(41,926	)

Net cash flow used for investing activities		(939,800	)		(460,388	)		(522,250	)

Cash Flows from Financing Activities:
Issuance of long-term debt		491,654			459,926			396,072
Short-term borrowings		—			(171,162	)		89,062
Dividends paid on common stock		(170,000	)		(170,000	)		(170,000	)
Repayment and reacquisition of long-term debt		(89,525	)		(337,160	)		(383,747	)

Net cash flow provided by (used for) financing activities		232,129			(218,396	)		(68,613	)

Net increase in cash and cash equivalents		69,453			25,728			14,212
Cash and cash equivalents at beginning of year		42,549			16,821			2,609

Cash and cash equivalents at end of year	$	112,002		$	42,549		$	16,821

Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes paid/(refunded)	$	74,523		$	(54,283	)	$	212,989
Interest (excluding capitalized interest)	$	140,010		$	117,081		$	114,094

See Notes to Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY


	Years Ended December 31,
	2003			2002			2001
	(dollars in thousands)

COMMON STOCK	$	178,162		$	178,162		$	178,162

ADDITIONAL PAID-IN CAPITAL		1,246,804			1,246,804			1,246,804

RETAINED EARNINGS
Balance at beginning of year		819,632			790,289			694,802
Net income		180,937			199,343			265,487
Common stock dividends		(170,000	)		(170,000	)		(170,000	)

Balance at end of year		830,569			819,632			790,289

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		(85,286	)		(64,565	)		—
Minimum pension liability adjustment, net of tax of $3,105, $39,696 and $634		4,329			(60,521	)		(966	)
Cumulative effect of a change in accounting for derivatives, net of tax of $47,404		—			—			72,274
Unrealized gain/(loss) on derivative instruments, net of tax of $15,824, $25,426 and $71,720		24,135			38,764			(109,346	)
Reclassification of realized (gain)/loss to income, net of tax of $3,207, $679 and $17,399		4,917			1,036			(26,527	)

Balance at end of year		(51,905	)		(85,286	)		(64,565	)

TOTAL COMMON STOCK EQUITY	$	2,203,630		$	2,159,312		$	2,150,690

COMPREHENSIVE INCOME
Net income	$	180,937		$	199,343		$	265,487
Other comprehensive income (loss)		33,381			(20,721	)		(64,565	)

Comprehensive income	$	214,318		$	178,622		$	200,922

See Notes to Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Nature of Operations

We are a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. We also generate, sell and deliver electricity to wholesale customers in the western United States. In early 2003, the marketing and trading division was moved from Pinnacle West to us for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy. See Note 3 for a discussion of the Track A Order. Our marketing and trading division sells, in the wholesale market, our and Pinnacle West Energy’s generation output that is not needed for our Native Load, which includes loads for retail customers and cost-of-service wholesale customers. We do not distribute any products. Pinnacle West owns all of our outstanding stock.

During 2001, we transferred most of our marketing and trading activities to Pinnacle West. Thus, we did not have any significant marketing and trading activity in 2002. Conversely, in the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West). This latest move was a result of the ACC’s Track A Order prohibiting the previously-required transfer of our generating assets to Pinnacle West Energy.

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


	For the year ended
	December 31,
	2003		2002		2001
Electric operating revenues:
Pinnacle West – marketing and trading	$	12	$	85	$	50
Pinnacle West Energy		1		—		—

Total	$	13	$	85	$	50

Purchased power and fuel costs:
Pinnacle West – marketing and trading	$	—	$	135	$	50
Pinnacle West Energy		70		—		14

Total	$	70	$	135	$	64

Other:
Pinnacle West Energy:
Lease expense	$	10	$	—	$	—

Interest income	$	12	$	—	$	—

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS


	As of December 31,
	2003			2002
Net intercompany receivables/(payables):
Pinnacle West Energy (a)	$	463		$	(1	)
Pinnacle West – marketing and trading		16			135
APS Energy Services		10			—
Pinnacle West		(8	)		(1	)

Total	$	481		$	133

(a) The net intercompany receivable as of December 31, 2003 related to Pinnacle West Energy primarily consists of the $500 million of debt we issued to Pinnacle West Energy pursuant to the Financing Order (see “ACC Financing Order” in Note 3).

Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. The Company purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in Issue No. 2-3.” See Note 16 for more information related to EITF 03-11. Intercompany receivables primarily include the amounts related to the loan we made to Pinnacle West Energy and intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

Accounting Records and Use of Estimates

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

Derivative Accounting

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.

Prior to the fourth quarter of 2002, we accounted for our trading activity at fair value, with changes in fair value reported in earnings as required by EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” In the fourth quarter of 2002, we adopted EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which rescinded EITF 98-10. The impact of this guidance was immaterial to our financial statements. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy trading contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

See Note 16 for additional information about our derivative and energy trading accounting policies.

Mark-to-Market Accounting

Under mark-to-market accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as current or long-term assets and liabilities from risk management and trading activities in the Balance Sheets.

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

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

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

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

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

The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. See Note 16 for further discussion on credit risk.

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

Regulatory Accounting

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

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

As part of the 1999 Settlement Agreement with the ACC (see Note 3), we continue to amortize certain regulatory assets over an eight-year period as follows (dollars in millions):

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS


1999	2000		2001		2002		2003		2004		Total
$164	$	158	$	145	$	115	$	86	$	18	$	686

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


	December 31,
	2003		2002
Remaining balance recoverable under the 1999 Settlement Agreement (a)	$	18	$	104
Spent nuclear fuel storage (Note 10)		49		46
Electric industry restructuring transition costs (Note 3)		46		40
Deferred compensation		24		23
Contributions in aid of construction		11		10
Loss on reacquired debt (b)		12		9
Other		5		9

Total regulatory assets	$	165	$	241

(a) The majority of our unamortized regulatory assets above relates to deferred income taxes (see Note 4) and rate synchronization cost deferrals (see “Rate Synchronization Cost Deferrals” below).

(b) See “Reacquired Debt Costs” below.

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


	December 31,
	2003		2002
Removal costs (a)	$	480	$	—
Deferred gains on utility property		20		20
Deferred interest income (b)		8		—
Other		2		6

Total regulatory liabilities	$	510	$	26

(a) See Note 11 for information on Asset Retirement Obligations.

(b) See “ACC Financing Orders” in Note 3 for information on the “APS Loan”.

Rate Synchronization Cost Deferrals

As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense in the Statements of Income.

Utility Plant and Depreciation

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

• material and labor;

• contractor costs;

• capitalized leases;

• construction overhead costs (where applicable); and

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

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Prior to 2003, we charged removal costs, less salvage, to accumulated depreciation. Effective January 1, 2003, we applied the provisions of SFAS 143 (see Note 11).

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2003 were as follows:

• Fossil plant – 23 years;

• Nuclear plant – 20 years;

• Other generation – 25 years

• Transmission – 36 years;

• Distribution – 23 years; and

• Other – 9 years.

For the years 2001 through 2003, the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 12.5%. The weighted-average rate was 3.35% for 2003, 3.35% for 2002 and 3.40% for 2001. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.

Capitalized Interest

Capitalized interest represents the cost of debt funds used to finance construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. The rate used to calculate capitalized interest was a composite rate of 4.55% for 2003, 4.80% for 2002 and 6.13% for 2001. Capitalized interest ceases to accrue when construction is complete.

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

AFUDC was calculated by using a composite rate of 8.55% for 2003. We compound AFUDC monthly and cease to accrue AFUDC when construction work is completed and the property is placed in service.

In 2003, we returned to the AFUDC method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This is consistent with our returning to a vertically-integrated utility, as evidenced by our recent general rate case filing, which includes the request for rate recognition of generation assets. Previously, we capitalized interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” Although AFUDC both increases the plant balance and results in higher current earnings during the construction period, AFUDC is realized in future revenues through depreciation provisions included in rates. This change increased earnings by $11 million in 2003 as compared to what it would have been under SFAS No. 34.

Electric Revenues

We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. However, the determination and billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers since the date of the last meter reading and billing and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis in our Statements of Income.

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

We adopted EITF 03-11 effective October 1, 2003. EITF 03-11 provided guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs, reducing both revenues and purchased power

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows (see Note 16 for additional information).

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an initial maturity of three months or less to be cash equivalents.

Nuclear Fuel

We charge nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method based on actual physical usage. We divide the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. We then multiply that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

We also charge nuclear fuel expense for the permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel, and it charges us $0.001 per kWh of nuclear generation. See Note 10 for information about spent nuclear fuel disposal and Note 11 for information on nuclear decommissioning costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes.” Pinnacle West files the federal income tax return on a consolidated basis and files the state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to us as though we filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to Pinnacle West. See Note 4.

Reacquired Debt Costs

We defer the gains and losses incurred upon early retirement and are seeking recovery in the general rate case (see Note 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of reacquired debt costs over an eight-year period that will end June 30, 2004. All regulatory asset amortization is included in depreciation and amortization expense in the Statements of Income.

Stock-Based Compensation

Pinnacle West offers stock-based compensation plans for officers and key employees of our company. In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”

The following chart compares our net income and stock compensation expense to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through 2003 (dollars in thousands):


	2003		2002		2001
Net income, as reported	$	180,937	$	199,343	$	265,487
Add: Stock compensation expense included in reported net income (net of tax):		751		200		—
Deduct: Total stock compensation expense determined under fair value method (net of tax):		1,740		1,162		1,582

Pro forma net income	$	179,948	$	198,381	$	263,905

In order to calculate the fair value of the 2003, 2002 and 2001 stock option grants and the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options:


	2003			2002			2001
Risk-free interest rate		3.35	%		4.17	%		4.08	%
Dividend yield		5.26	%		4.17	%		3.70	%
Volatility		38.03	%		22.59	%		27.66	%
Expected life (months)		60			60			60

See Note 14 for further discussion about our stock compensation plans.

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets on our Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. The Company’s gross intangible assets (which are primarily capitalized software costs) were $215 million at December 31, 2003 and $193 million at December 31, 2002. The related accumulated amortization was $121 million at December 31, 2003 and $100 million at December 31, 2002. Amortization expense was $21 million in 2003, $19 million in 2002 and $21 million in 2001. Estimated amortization expense on existing intangible assets over the next five years is $24 million in 2004, $23 million in 2005, $21 million in 2006, $17

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

million in 2007 and $9 million in 2008. At December 31, 2003, the weighted average amortization period for our intangible assets is 7 years.

2. Accounting Matters

See the following Notes for information about new accounting standards and other accounting matters:

• Note 7 for amended disclosure requirements (SFAS No. 132) on retirement plans and other benefits;

• Note 11 for a new accounting standard (SFAS No. 143) on asset retirement obligations;

• Notes 14 for a new accounting standard (SFAS No. 148) related to stock-based compensation;

• Note 16 for EITF issues (EITF 02-3 and 03-11), DIG Issue No. C15, and a new accounting standard (SFAS No. 149) related to accounting for derivatives and energy contracts;

• Note 18 for a new FASB interpretation (FIN No. 46R) related to VIEs; and

• Note 19 for a new FASB interpretation (FIN No. 45) on guarantees.

3. Regulatory Matters

Electric Industry Restructuring

State

1999 Settlement Agreement

The following are the major provisions of the 1999 Settlement Agreement, as approved by the ACC:

• We have reduced rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. Based on the price reductions authorized in the 1999 Settlement Agreement, there were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; approximately $28 million ($17 million after taxes), effective July 1, 2002; and approximately $29 million ($18 million after taxes), effective July 1, 2003. For

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.

• Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.

• There is a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor we are prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance 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.

• We will be permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. See “General Rate Case and Retail Rate Adjustment Mechanisms” below.

• Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of 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 providing 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.

• Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we had demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also states that we will not be allowed to recover $183 million net present value (in 1999 dollars) of the $533 million. The 1999 Settlement Agreement

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

provides that we will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As discussed below under “General Rate Case and Retail Rate Adjustment Mechanisms,” we are seeking to recover amounts written off by us as a result of the 1999 Settlement Agreement.

• The 1999 Settlement Agreement required us to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) our competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that we would be allowed to defer and later collect, beginning July 1, 2004, 67% of our costs to accomplish the required transfer of generation assets to an affiliate. However, as discussed below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing the Track A Order, an order preventing us from transferring our generation assets. We are seeking to recover all costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “General Rate Case and Retail Rate Adjustment Mechanisms” below.

Retail Electric Competition Rules

The Rules approved by the ACC include the following major provisions:

• They apply to virtually all Arizona electric utilities regulated by the ACC, including us.

• Effective January 1, 2001, retail access became available to all of our retail electricity customers.

• Electric service providers that get CC&N’s from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.

• Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.

• The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.

• Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

competitive electric assets and services to affiliates no later than December 31, 2002. However, as discussed below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require us to transfer our generation assets.

Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, we must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement.

On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of our property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute.

Provider of Last Resort Obligation

Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are, under the Rules, 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 two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. In the event of shortfalls 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. 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. See “General Rate Case and Retail Rate Adjustment Mechanisms” below for a discussion of retail rate adjustment mechanisms that were the subject of ACC hearings in April 2003.

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

Track A Order

On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things:

• reversed its decision, as reflected in the Rules, to require us to transfer our generation assets either to an unrelated third party or to a separate corporate affiliate; and

• unilaterally modified the 1999 Settlement Agreement, which authorized our transfer of our generating assets, and directed us to cancel our activities to transfer our generation assets to Pinnacle West Energy.

On November 15, 2002, we filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals. Arizona Public Service Company vs. Arizona Corporation Commission, CV 2002-0222 32. Arizona Public Service Company vs. Arizona Corporation Commission, 1CA CC 02-0002. On December 13, 2002, we and the ACC staff agreed to principles for resolving certain issues raised by us in our appeals of the Track A Order. We and the ACC are the only parties to the Track A Order appeals. The major provisions of the principles include, among other things, the following:

• We and the ACC staff agreed that it would be appropriate for the ACC to consider the following matters in our general rate case, which was filed on June 27, 2003:

• the generating assets to be included in our rate base, including the question of whether the PWEC Dedicated Assets should be included in our rate base;

• the appropriate treatment of the $234 million pretax asset write-off agreed to by us as part of the 1999 Settlement Agreement; and

• the appropriate treatment of costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy.

• Upon the ACC’s issuance of a final decision that is no longer subject to appeal approving our request to provide $500 million of financing or credit support to Pinnacle West Energy or the Company, with appropriate conditions, our appeals of the Track A Order would be limited to the issues described in the preceding bullet points, each of which would be presented to the ACC for consideration prior to any final judicial resolution. As noted below, the ACC issued the Financing Order on April 4, 2003. The Financing Order is final and no longer subject to appeal. As a result, our appeals of the Track A Order are limited to the issues described in the preceding bullet points.

On August 27, 2003, we, Pinnacle West and Pinnacle West Energy filed a lawsuit asserting damage claims relating to the Track A Order. Arizona Public Service Company et al. v. The State

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

of Arizona ex rel., Superior Court of the State of Arizona, County of Maricopa, No. CV2003-016372.

Track B Order

On March 14, 2003, the ACC issued the Track B Order, which required us to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003, we were required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in our retail load and our retail energy sales. The Track B Order also confirmed that it was “not intended to change the current rate base status of our existing assets.”

The order recognizes our right to reject any bids that are unreasonable, uneconomical or unreliable. The ACC staff and an independent monitor participated in the Track B procurement process. The Track B Order also contains requirements relating to standards of conduct between us and any affiliate of ours participating in the competitive solicitation, requires us to treat bidders in a non-discriminatory manner and requires us to file a protocol regarding short-term and emergency procurements. The order permits the provision by us of corporate oversight, support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with our confidential bidding information that is not available to other bidders. The order directs us to evaluate bids on cost, reliability and reasonableness. The decision requires bidders to allow the ACC to inspect their plants and requires assurances of appropriate competitive market conduct from senior officers of such bidders. Following the solicitation, the decision requires us to prepare a report evaluating environmental issues relating to the procurement, and a series of workshops on environmental risk management will be commenced thereafter.

We issued requests for proposals in March 2003 and, by May 6, 2003, we entered into contracts to meet all or a portion of our requirements for the years 2003 through 2006 as follows:

(1) Pinnacle West Energy agreed to provide 1,700 MW in July through September of 2003 and in June through September of 2004, 2005 and 2006, by means of a unit contingent contract.

(2) PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.

(3) Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.

ACC Financing Orders

On April 4, 2003, the ACC issued the Financing Order authorizing us to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

combination of both, not to exceed $500 million in the aggregate (the “APS Loan”), subject to the following principal conditions:

• any debt issued by us pursuant to the order must be unsecured;

• the APS Loan must be callable and secured by the PWEC Dedicated Assets;

• the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on our debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security);

• the 264 basis points referred to in the previous bullet point will be capitalized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum;

• the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC;

• any demonstrable increase in our cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;

• we must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce our common equity ratio below that threshold, unless otherwise waived by the ACC. The ACC will process any waiver request within sixty days, and for this sixty-day period this condition will be suspended. However, this condition, which will continue indefinitely, will not be permanently waived without an order of the ACC; and

• certain waivers of the ACC’s affiliated interest rules previously granted to us and our affiliates will be temporarily withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each, a “Covered Transaction”), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, except that the foregoing restrictions will not apply to the following categories of Covered Transactions:

• Covered Transactions less than $100 million, measured on a cumulative basis over the calendar year in which the Covered Transactions are made;

• Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCor’s anticipated accelerated asset sales activity during those years;

• Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy’s (a) West Phoenix Unit 5, located in Phoenix, and

			(b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and

	•		Covered Transactions related to the sale of 25% of the Silverhawk plant to SNWA pursuant to an agreement between SNWA and Pinnacle West Energy.

The ACC also ordered the ACC staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003, we submitted our report on these matters to the ACC staff. The ACC has indicated that the preliminary investigation would be addressed in the pending general rate case (see below).

On May 12, 2003, we issued $500 million of debt pursuant to the Financing Order 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 (see Note 6).

On November 22, 2002, the ACC issued an order approving our request to permit us to make short-term advances to Pinnacle West in the form of an interaffiliate line of credit in the amount of $125 million. As of December 31, 2003, there were no borrowings outstanding under this financing arrangement, and this authority expired on December 4, 2003.

As noted above, on June 27, 2003, we filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in our annual retail electricity revenues, to become effective July 1, 2004. In this rate case, we updated our cost of service and rate design.

	•		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 recognition of 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 Rules.

Requested Rate Increase The requested rate increase totals $175.1 million, or 9.8%, and is comprised of the following items (dollars in millions):

Test Year The filing is based on an adjusted historical test year ended December 31, 2002.

Cost of Capital The proposed weighted average cost of capital for the test year ended December 31, 2002 is 8.67%, including an 11.5% return on equity.

Rate Base The request is based on a rate base of $4.2 billion, calculated using Original Cost Less Depreciation (“OCLD”) methodology. The OCLD rate base approximates the ACC-jurisdictional portion of the net book value of utility plant, net of accumulated depreciation and deferred taxes, as of December 31, 2002, except as set forth below.

The requested rate base includes the PWEC Dedicated Assets, with a total combined capacity of approximately 1,800 MW. These assets were included at their estimated July 1, 2004 net book value. Upon approval of the request, the PWEC Dedicated Assets would be transferred to us from Pinnacle West Energy.

The filing also includes calculated amounts for Fair Value Rate Base and Replacement Cost New Depreciated (“RCND”) rate base. The ACC is required by the Arizona Constitution to make a finding of Fair Value Rate Base, which has traditionally been defined by the ACC as the arithmetic average of OCLD rate base and RCND rate base.

Recovery of Previous $234 Million Write-Off The request includes recovery, over a fifteen year period, of the write-off of $234 million pretax of regulatory assets by us as a result of the 1999 Settlement Agreement. See “1999 Settlement Agreement” above.

Estimated Timeline We have asked the ACC to approve the requested rate increase by July 1, 2004. The ACC ALJ has issued a procedural schedule setting a hearing date on the application of May 25, 2004. Based on the schedule and existing ACC regulations, we believe the ACC will be able to make a decision in this general rate case by the end of 2004.

The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of 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 Rules.

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 provisions of this order will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend, modify or reconsider, in its entirety, this November 4 order during the rate case.

Testimony As required by the procedural schedule, on February 3, 2004, the following parties filed their initial written testimony with the ACC on all issues except cost of service (i.e., cost allocation among customer classes) and rate design:

	•		the ACC “litigation” staff;

	•		the Arizona Residential Utility Consumers Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and

	•		other approved rate case interveners.

ACC Staff Recommendations In its filed testimony, the ACC staff recommended, among other things, that the ACC:

	•		decrease our annual retail electricity revenues by at least $142.7 million, which would result in a rate decrease of approximately 8%, based on a 9% return on equity;

	•		not allow the PWEC Dedicated Assets to be included in our rate base;

	•		not allow us to recover any of the $234 million written off as a result of the 1999 Settlement Agreement; and

	•		not implement any adjustment mechanisms for fuel and purchased power.

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 that our rate case requests are supported by, among other things, our demonstrated need for the PWEC Dedicated Assets; our need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in our high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard.

The ACC staff also submitted testimony, indicating that we and our affiliates had violated the “spirit, if not the letter,” of the Rules, the Code of Conduct and the 1999 Settlement Agreement.

RUCO Recommendations In its filed testimony, RUCO recommended, among other things, that the ACC:

	•		decrease our annual retail electricity revenues by $53.6 million, which would result in a rate decrease of approximately 2.84%, based on a 9.5% return on equity;

	•		not allow the PWEC Dedicated Assets to be included in our rate base;

	•		not allow us to recover any of the $234 million written off as a result of the 1999 Settlement Agreement; and

	•		not implement any adjustment mechanisms for fuel and purchased power.

We believe that our rate request is necessary to ensure our continued ability to reliably serve one of the fastest growing regions in the country and view any ultimate decision that would deny recovery of the Company’s investment in the PWEC Dedicated Assets as constituting a regulatory “taking.” We will vigorously oppose the recommendations of the ACC staff, RUCO, and other parties offering similar recommendations.

In early December 2003, we issued a request for proposals (“RFP”) for long-term power supply resources, and on January 8, 2004, an ACC Administrative Law Judge issued an order requiring, among other things, us to file a summary of the proposals with the ACC. On January 27, 2004, we filed a summary of the proposals with the ACC. We are negotiating with certain of the parties that submitted proposals.

In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.

On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule. On April 28, 2003, the FERC Staff issued an additional white paper on the proposed Standard Market Design. The white paper discusses several policy changes to the proposed Standard Market Design, including a greater emphasis on flexibility for regional needs. We cannot currently predict what, if any, impact there may be to the Company if the FERC adopts the proposed rule or any modifications proposed in the comments.

The regulatory developments and legal challenges to the Rules discussed in this Note 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 providing 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 competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.

We are included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to us, it does so based on our taxable income or loss alone.

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

We have recorded a regulatory asset related to income taxes on our Balance Sheets in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. We amortize this amount as the differences reverse. In accordance with ACC settlement agreements, we are continuing to accelerate amortization of a regulatory asset related to income taxes over an eight-year period that will end June 30, 2004 (see Note 1). Accordingly, we are including this accelerated amortization in depreciation and amortization expense on the Statements of Income.

As a result of a change in IRS guidance, we claimed a tax deduction related to a tax accounting method change on the 2001 Pinnacle West federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. In 2002, we received an income tax refund of approximately $115 million related to the 2001 Pinnacle West federal consolidated income tax return. In 2003, we resolved certain prior-year issues with the taxing authorities and recorded a $13 million tax benefit associated with tax credits and other reductions to income tax expense.

The components of income tax expense for income before accounting change are as follows (dollars in thousands):

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

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

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

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

We had committed lines of credit with various banks of $250 million at December 31, 2003 and 2002, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The current line matures in May 2004, and the document allows for a 364-day extension of the termination date without lender consent. The commitment fees at December 31, 2003 and 2002 for these lines of credit were 0.175% and 0.09% per annum. We had no bank borrowings outstanding under these lines of credit at December 31, 2003 and 2002.

We had no commercial paper borrowings outstanding at December 31, 2003 and 2002. By Arizona statute, our short-term borrowings cannot exceed 7% of our total capitalization unless approved by the ACC.

Borrowings under our mortgage bond indenture are secured by substantially all of our utility plant. We also have unsecured debt. The following table presents the components of long-term debt on the Balance Sheets outstanding at December 31, 2003 and 2002 (dollars in thousands):

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

(b)		On August 15, 2003, we redeemed at maturity $54 million of our First Mortgage Bonds, 7.25% Series due 2023.

(c)		On April 7, 2003, we redeemed $33 million of our First Mortgage Bonds, 8.00% Series due 2025.

(d)		The weighted-average rate was 1.51% at December 31, 2003 and 1.94% at December 31, 2002. Changes in short-term interest rates would affect the costs associated with this debt.

(e)		On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned the proceeds to us pursuant to a loan agreement. The bonds were issued to refinance $90 million of outstanding pollution control bonds. The bondholders were issued $90 million of first mortgage bonds (senior note mortgage bonds) as collateral.

(f)		We currently have outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes, as well as the $90 million issue discussed in footnote (e) above. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity and redemption provisions as the senior notes. Our payments of principal, premium and/or interest on the senior notes satisfy our

		corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When we repay all of our first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding.

(g)		The weighted average rate was 5.55% at December 31, 2003 and 5.78% at December 31, 2002. Capital leases are included in property, plant and equipment on the Balance Sheets for both December 31, 2003 and December 31, 2002.

Our debt covenants related to our financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. We comply with these covenants and anticipate that we will continue to meet the covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65%. At December 31, 2003, our ratio was approximately 53%. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for us. Based on 2003 results, the coverage is approximately 4 times for our bank agreements and 15 times for our mortgage indenture. 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.

All of our bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if we were to default under other agreements. All of our bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if we were to default under other agreements. Our credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects.

The following is a list of payments due on total long-term debt and capitalized lease requirements through 2008:

	•		$207 million in 2004;

	•		$402 million in 2005;

	•		$85 million in 2006;

	•		$1 million in 2007;

	•		$1 million in 2008; and

	•		$1,935 million, thereafter.

Our first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. We may pay dividends

on our common stock if there is a sufficient amount “available” from retained earnings and the excess of cumulative book depreciation (since the mortgage’s inception) over mortgage depreciation, which is the cumulative amount of additional property pledged each year to address collateral depreciation. As of December 31, 2003, the amount “available” under the mortgage would have allowed us to pay approximately $3 billion of dividends compared to our current annual common stock dividends of $170 million.

The mortgage currently constitutes a lien on substantially all of our property. We anticipate that in early April 2004, all first mortgage bonds issued by us under our existing mortgage and deed of trust, other than the first mortgage bonds securing our senior notes, will have been paid and retired. At that time, our obligation to make payment on the first mortgage bonds securing the senior notes will also be deemed to be satisfied and discharged and the senior note first mortgage bonds will cease to secure the senior notes. We are then obligated to take all steps necessary to terminate our existing mortgage and deed of trust and cannot issue any additional first mortgage bonds under that mortgage.

Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and their subsidiaries. In 2003, we represented 89% of the total cost of these plans. Effective January 1, 2003, Pinnacle West sponsored a new account balance plan for all new employees in place of the defined benefit plan, and, as of April 1, 2003, the plan was offered as an alternative to the defined benefit plan for all existing employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all of our employees. The supplemental excess benefit retirement plan covers officers of the company and highly compensated employees designated for participation by Pinnacle West’s Board of Directors. Our employees do not contribute to the plans. Generally, the benefits under these plans are calculated based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefits for the employees of Pinnacle West and their subsidiaries. Pinnacle West provides medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. Pinnacle West retains the right to change or eliminate these benefits.

In December 2003, FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to enhance disclosures of relevant accounting information by providing additional information on plan assets, obligations, cash flows, and net cost. The revisions are reflected in this Note. Pinnacle West uses a December 31 measurement date for its plans.

On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug costs. We have not yet quantified the effect, if any, on accumulated projected benefit obligation or the net periodic postretirement benefit cost in our financial statements and

accompanying notes. Specific accounting guidance for this subsidy, including transition rules, is pending.

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

The following table sets forth the Pinnacle West plan’s change in the benefit obligations for the plan years 2003 and 2002 (dollars in thousands):

(a)

The plan was amended in January 2002 to increase the deductibles, out-of-pocket maximums and prescription drug co-pays. The plan was amended in June 2002 to increase the participants’ portion of premiums.

The following table sets forth the qualified defined benefit plan and other benefit plan changes in the fair value of Pinnacle West’s plan assets for the years 2003 and 2002 (dollars in thousands):

The following table shows a reconciliation of the funded status of the Pinnacle West plans to the amounts Pinnacle West recognized in its Consolidated Balance Sheets as of December 31, 2003 and 2002 (dollars in thousands):

The following sets forth the details related to benefits included on Pinnacle West’s Consolidated Balance Sheets (dollars in thousands):

The following table sets forth the other comprehensive income arising from the change in additional minimum liability for the years ended December 31, 2003 and 2002 (dollars in thousands):

The following table sets forth the projected benefit obligations and the accumulated benefit obligation for Pinnacle West pension plans in excess of plan assets for the plan years 2003 and 2002 (dollars in thousands):

Below are the weighted-average assumptions for both the pension and other benefits used to determine each respective benefit obligation and net periodic benefit cost of Pinnacle West:

In selecting the pretax expected long-term rate of return on plan assets Pinnacle West considers past performance and economic forecasts for the types of investments held by the plan. For the year 2003, Pinnacle West decreased its pretax expected long-term rate of return on plan assets from 10% to 9%, as a result of continued declines in general equity and bond market conditions. For the year 2004 Pinnacle West is assuming a 9% rate of return on plan assets. This

rate is reflective of the market returns earned historically on Pinnacle West’s target asset allocation. As recent history has demonstrated, markets may decline and increase dramatically. However, the long-term rate of return on plan assets of 9% is reasonable given Pinnacle West’s asset allocation in relation to historical and expected future performance.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans of Pinnacle West. A 1% change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):

Pinnacle West’s qualified pension plan asset allocation at December 31, 2003, and 2002 is as follows:

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

Pinnacle West’s other postretirement benefit plan asset allocation at December 31, 2003, and 2002, is as follows:

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

Under current law, Pinnacle West is required to contribute approximately $100 million to its pension plans in 2004 and expects to contribute approximately $50 million to its other postretirement benefit plans in 2004. Our share is approximately 89%. If currently pending legislation is enacted, Pinnacle West’s required pension contribution in 2004 would decrease to the $25 to $50 million range (our share would decrease to the $22 to $44 million range).

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and subsidiaries. In 2003, we represented 90% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account. Under this plan, Pinnacle West matches a percentage of the participants’ contributions in the form of Pinnacle West stock. After a five year vesting period, participants have an option to transfer the company matching contributions out of the Pinnacle West Stock Fund to other investment funds within the plan. At December 31, 2003, approximately 23% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately $5 million in 2003, $4 million in 2002 and $4 million in 2001.

In July 2002, we implemented a voluntary workforce reduction as part of a cost reduction program. We recorded $34 million before taxes in voluntary severance costs in 2002. No further charges are expected.

amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, a regulatory asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis. See Note 18 for a discussion of VIEs, including the SPEs involved in the Palo Verde sale-leaseback transactions.

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

Total lease expense recognized in the Statements of Income was $66 million in 2003, $57 million in 2002 and $55 million in 2001.

The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2003 to 2015.

In accordance with the 1999 Settlement Agreement and previous settlement agreements, we are continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). All regulatory asset amortization is included in depreciation and amortization expense in the Statements of Income. The balance of this regulatory asset at December 31, 2003 was $5 million.

Estimated future minimum lease payments for our operating leases are approximately as follows (dollars in millions):

We share ownership of some of our generating and transmission facilities with other companies. The following table shows our interest in those jointly-owned facilities recorded on the Balance Sheets at December 31, 2003. Our share of operating and maintaining these facilities is included in the Statements of Income in operations and maintenance expense (dollars in thousands):

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

(b)		Weighted average of interests.

10.		Commitments and Contingencies

We recorded charges totaling $13 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. These charges take into consideration our rights of set-off with respect to the Enron related contractual obligations. The basis of the set-offs included, but was not limited to, provisions in the various contractual arrangements with Enron and its affiliates, including an International Swaps and Derivative Agreement (ISDA) between us and Enron North America. The write-off is also net of the expected recovery based on secondary market quotes from the bond market. The amounts were written-off from the balances of the related assets and liabilities from risk management and trading activities on the Balance Sheets. In February 2004, Enron filed an adversary proceeding against us in bankruptcy court regarding differences in the valuation of trading positions involving us. Enron North America v. Arizona Public Service Company, Adversary Proceeding No. 04-02366 (ALJ). We will vigorously defend this action and do not believe it will have any material adverse impact on our anticipated exposure to Enron described above.

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and that it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including us (on behalf of ourselves and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. Arizona Public Service Company v. United States of America, United States Court of Federal Claims, 03-2832C.

In February 2002, the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the President’s recommendation. Congress approved the Yucca Mountain site, overriding the Nevada veto. It is now expected that the DOE will submit a license application to the NRC in late 2004. The State of Nevada has filed several lawsuits relating to the Yucca Mountain site. We cannot currently predict what further steps will be taken in this area.

We have existing fuel storage pools at Palo Verde and are operating a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, we believe that spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.

Although some low-level waste has been stored on-site in a low-level waste facility, we are currently shipping low-level waste to off-site facilities. We currently believe that interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.

We currently estimate that we will incur $115 million (in 2003 dollars) over the life of Palo Verde for our share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2003, we had spent $7 million and had recorded a liability of $42 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. We have recorded a corresponding regulatory asset of $49 million and are seeking recovery of these costs through future rates (see “General Rate Case and Retail Rate Mechanisms” in Note 3).

We have reclassified prior year spent nuclear fuel costs of approximately $44 million previously included in accumulated amortization of nuclear fuel to the liability for asset retirements and removals on our Balance Sheets at December 31, 2002. Upon adoption of SFAS No. 143 in

2003, we reclassified this liability to a regulatory liability because no legal obligation for removal exists.

We believe that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, we acknowledge that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which we are less able to predict. We expect to vigorously protect and pursue our rights related to this matter.

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $10 million per incident. Based on our interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $9 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

We are party to various purchased power and fuel contracts with terms expiring from 2004 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $262 million in 2004; $95 million in 2005; $92 million in 2006; $51 million in 2007; $51 million in 2008 and $461 million thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

Of the various purchased power and fuel contracts mentioned above some of those contracts have take-or-pay provisions. The contracts we have for the supply of our coal and nuclear fuel have take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2016. The current take-or-pay nuclear fuel contracts expire in 2004 and had not been renewed as of December 31, 2003.

The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions):

(a)

Total take-or-pay commitments are approximately $530 million. The total net present value of these commitments is approximately $340 million.

We must reimburse certain coal providers for amounts incurred for coal mine reclamation. Our coal mine reclamation obligation was $60 million at December 31, 2003 and $59 million at December 31, 2002 and is included in deferred credits-other in the Balance Sheets.

A regulatory asset has been established for amounts not yet recovered from ratepayers related to the coal obligations. In accordance with the 1999 Settlement Agreement with the ACC, we are continuing to accelerate the amortization of the regulatory asset for coal mine reclamation over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the Statements of Income.

In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. We were a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, we should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. We do not anticipate material changes in our exposure and still believe, subject to the finalization of the revised proxy prices, that we will be entitled to a net refund.

The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Court of Appeals (Ninth Circuit).

Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.

On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its Staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including us, may potentially have been involved in arbitrage transactions

that allegedly violated certain provisions of the ISO tariff. We and the FERC staff have settled this matter, and the settlement was approved by the FERC.

SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO. PG&E filed for bankruptcy protection in 2001.

California Energy Market Litigation On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present. State of California v. British Columbia Power Exchange et. al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint has been dismissed by the FERC and the State of California is now appealing the matter to the Ninth Circuit Court of Appeals. In addition, the State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including us, attempting to expand those matters to such other participants. We have not yet filed a responsive pleading in the matter, but we believe the claims by Reliant and Duke as they relate to us are without merit.

We were also named in a lawsuit regarding wholesale contracts in California, which has now been moved back to state court. James Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court Case No. 407867. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market in violation of California unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against us and numerous other PX participants. Cal PX v. The State of California Superior Court in and for the County of Sacramento, JCCP No. 4203. Various motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations or liquidity.

By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised us that it believes we overcharged Citizens by over $50 million under a power service agreement. We believe that our charges under the agreement were fully in accordance with the terms of the agreement. In addition, in testimony filed with the ACC on March 13, 2002, Citizens acknowledged that, based on its review, “if Citizens filed a complaint with the FERC, it probably would lose the central issue in the contract interpretation dispute.” We and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, Pinnacle West and Citizens entered into a power sale agreement under which Pinnacle West will supply Citizens with future

specified amounts of electricity and ancillary services through May 31, 2008. This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001.

We and Pinnacle West Energy purchase the majority of our natural gas requirements for our gas-fired plants under contracts with a number of natural gas suppliers. Effective September 1, 2003, our and Pinnacle West Energy’s natural gas supply is transported pursuant to a firm, contract demand service agreement with El Paso Natural Gas Company. Pursuant to the terms of a comprehensive settlement entered into in 1996, the rates charged for transportation are subject to a 10-year rate moratorium extending through December 31, 2005.

Prior to September 1, 2003, our and Pinnacle West Energy’s natural gas supply was transported pursuant to a firm, full requirements transportation service agreement. On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement by requiring all firm, full requirements contract holders to convert to contract demand service agreements effective September 1, 2003. This required conversion has imposed additional limitations on the former full requirements contract holders’ ability to nominate firm transportation capacity. In order for us and Pinnacle West Energy to meet our natural gas supply and capacity requirements, we must make market purchases, which we expect to increase costs by approximately $5 million per year for natural gas supply and by approximately $14 million per year for capacity. We and Pinnacle West Energy have sought appellate review of the FERC’s July 9 order and related issues on the grounds that the FERC decision to abrogate the full requirements contracts is arbitrary and capricious and is not supported by substantial evidence. Arizona Public Service Company and Pinnacle West Energy Corporation v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1209. This petition for review was consolidated with a petition filed by the ACC and other full requirements contract holders. Arizona Corporation Commission et al v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1206. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements.

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

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The standard requires that these liabilities be recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Prior to January 1, 2003, we accrued asset retirement obligations over the life of the related asset through depreciation expense.

We have asset retirement obligations for our Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements we reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term. Some of our transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that we expect to continue. As a result, we cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.

On January 1, 2003 and in accordance with SFAS No. 143, we recorded a liability of $219 million for our asset retirement obligations, including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a net regulatory liability of $40 million for the asset retirement obligations related to our regulated assets. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. The adoption of SFAS No. 143 did not have a material impact on our net income for the year ended December 31, 2003.

We have reclassified prior year removal costs of approximately $557 million previously included in accumulated depreciation to the liability for asset retirements and removals on our Balance Sheets. In 2003, we reclassified the portion of this liability which no legal obligation for removal exists to a regulatory liability.

In accordance with SFAS No. 71, we will continue to accrue for removal costs for our regulated assets, even if there is no legal obligation for removal. At December 31, 2003, regulatory liabilities shown on our Balance Sheets included approximately $480 million of estimated future removal costs that are not considered legal obligations.

The following schedule shows the change in our asset retirement obligations during the twelve-month period ended December 31, 2003 (dollars in millions):

The following schedule shows the change in our pro forma liability for the years ended December 31, 2002 and 2001, as if we had recorded an asset retirement obligation based on the guidance in SFAS No. 143 (dollars in millions):

To fund the costs we expect to incur to decommission Palo Verde, we established external decommissioning trusts in accordance with NRC regulations. We invest the trust funds in fixed income and domestic equity securities and classifies them as available for sale. The following table shows the cost and fair value of our nuclear decommissioning trust fund assets which are on the Balance Sheets at December 31, 2003 and December 31, 2002 (dollars in millions):

Quarterly financial information for 2003 and 2002 is as follows (dollars in thousands):

(a)		Operating revenues previously disclosed in the March 31, 2003, June 20, 2003 and September 30, 2003 Quarterly Report on Forms 10-Q, except for the fourth quarter ended December 31, 2002, which was disclosed in our 8-K dated March 31, 2003.

(b)		Reclassification adjustment relates to the adoption of EITF 03-11 (see Note 16).

13.		Fair Value of Financial Instruments

We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2003 and 2002 due to their short maturities.

We hold investments in fixed income and domestic equity securities for purposes other than trading. The December 31, 2003 and 2002 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of our nuclear decommissioning trust fund assets in Note 11.

On December 31, 2003, the carrying value of our long-term debt (excluding capitalized lease obligations) was $2.61 billion, with an estimated fair value of $2.74 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $2.21 billion on December 31, 2002, with an estimated fair value of $2.30 billion. The fair value estimates are based on quoted market prices of the same or similar issues.

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

In May 2002, Pinnacle West’s shareholders approved the 2002 Long-Term Incentive Plan (2002 plan), which allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. Pinnacle West has reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.

The 1994 plan and the 1985 plan each include outstanding options but no new options will be granted under either plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents. Following the approval of the 2002 plan, no further grants have been made under the 1994 plan, except for awards for the annual award of up to 20,000 shares of stock to satisfy stock award obligations under employment contracts to certain executives.

In the third quarter of 2002, Pinnacle West began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123. The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25. We recorded approximately $1.3 million in stock option expense before income taxes in our Statements of Income in 2003 and approximately $0.4 million in 2002. This amount may not be reflective of the stock option expense we will record in future years because stock options typically vest over several years and additional grants are generally made each year.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” The standard amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. The standard also amends the disclosure requirements of SFAS No. 123. SFAS No. 148 is effective for fiscal years ending after December 15, 2002. We adopted the disclosure requirements in 2002. See Note 1 for our pro forma disclosures on stock-based compensation and our weighted-average assumptions used to calculate the fair value of our stock options.

Total stock-based compensation cost, including stock option cost, was $3 million in 2003, $3 million in 2002 and $2 million in 2001.

The following table is a summary of the status of Pinnacle West’s stock option plans as of December 31, 2003, 2002 and 2001 and changes during the years ending on those dates:

The following table summarizes information about Pinnacle West’s stock options at December 31, 2003:

The following table is a summary of the amount and weighted-average grant date fair value of Pinnacle West stock compensation awards granted, other than options, during the years ended December 31, 2003, 2002 and 2001:

	(a)		Restricted stock priced at the average of the high and low market price for the grant date.

	(b)		Performance shares priced at the closing market price for the grant date.

We have two principal business segments (determined by services and the regulatory environment):

	•		our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses and related activities and includes electricity generation, transmission and distribution; and

	•		our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading. During 2001, we transferred most of our marketing and trading activities to Pinnacle West. Thus, we did not have any significant marketing and trading activity in 2002. Conversely, in the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West). This latest move was a result of the ACC’s Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy.

See Note 16 for information about reclassifications related to the adoption of EITF 03-11. Financial data for the years ended December 31, 2003, 2002 and 2001 by business segments is provided as follows (dollars in millions):

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria is met, in common stock equity (as a component of other comprehensive income (loss)). We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

In 2001, we recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income (loss)), both as cumulative effects of a change in accounting for derivatives. The charge primarily resulted from electricity option contracts. The credit resulted from unrealized gains on cash flow hedges.

During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts, and on January 1, 2003 for existing contracts, with early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. The impact of this guidance was immaterial to our financial statements. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Statements of Income on a net basis. Derivative instruments used for non-trading activities are accounted for in accordance with SFAS No. 133.

Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Balance Sheets. For non-trading derivative instruments that qualify for cash flow hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Certain of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. Derivatives associated with trading activities are adjusted to fair value through income.

EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Previous guidance under EITF 98-10 permitted physically settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the Statements of Income and restated prior year amounts for all periods presented. Reclassification of such trading activity to a net basis of reporting resulted in reductions in both revenues and purchased power and fuel costs, but did not have any impact on our financial condition, net income or cash flows.

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

We adopted EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provided guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs, reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows. Following are the net reclassifications to our previously reported amounts (dollars in thousands):


	2003		2002		2001
Regulated Electricity	$	40,067	$	157,227	$	577,783
Marketing and Trading		233,423		—		181,447

Total	$	273,490	$	157,227	$	759,230

In November 2003, the FASB revised its derivative guidance in DIG Issue No. C15, “Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” Effective January 1, 2004, the new guidance changes the criteria for the normal purchases and sales scope exception for electricity contracts. We do not expect this guidance to have a material impact on our financial statements.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The provisions of SFAS No. 149 that relate to previously issued SFAS No. 133 derivatives implementation guidance should continue to be applied in accordance with the effective dates of the original implementation guidance. In general, other provisions are applied prospectively to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The impact of this standard was immaterial to our financial statements.

The changes in the fair value of our hedged positions included in the Statements of Income for the years ended December 31, 2003 and 2002 are comprised of the following (dollars in thousands):


	2003		2002
Gains on the ineffective portion of derivatives qualifying for hedge accounting	$	7,033	$	9,091
Gains (losses) from the change in options time value excluded from measurement of effectiveness		181		(609	)
Losses from the discontinuance of cash flow hedges		—		(9,206	)

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

As of December 31, 2003, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately three years. During the year ending December 31, 2004, we estimate that a net gain of $7 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.

Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments:

• Marketing and Trading – both non-trading and trading derivative instruments of our competitive business segment.

The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2003 and 2002 (dollars in thousands):

December 31, 2003


	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated Electricity:
Mark-to-Market	$	44,079	$	5,900	$	(47,268	)	$	(3,028	)	$	(317	)
Options		—		12,101		—			—			12,101
Marketing & Trading:
Mark-to-Market		8,369		—		(10,870	)		(1,474	)		(3,975	)

Total	$	52,448	$	18,001	$	(58,138	)	$	(4,502	)	$	7,809

December 31, 2002


	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated Electricity:
Mark-to-Market	$	39,616	$	6,971	$	(59,773	)	$	(36,678	)	$	(49,864	)
Options		—		24,651		—			—			24,651

Total	$	39,616	$	31,622	$	(59,773	)	$	(36,678	)	$	(25,213	)

Cash or collateral may be required to serve as collateral against our open positions on certain energy-related contracts. No collateral was provided to counterparties at December 31, 2003. Collateral provided to counterparties was $5 million at December 31, 2002, and is included in investments and other assets on the Balance Sheet. Collateral provided to us by counterparties is $12 million at December 31, 2003 and $4 million at December 31, 2002, and is included in other deferred credits on the Balance Sheet.

100

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

Credit Risk

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. Our risk management process assesses and monitors the financial exposure of counterparties. Despite the fact that the great 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 impact on earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Mark-to-Market Accounting” for a discussion of our credit valuation adjustment policy.

17. Other Income and Other Expense

The following table provides detail of other income and other expense for the years ended December 31, 2003, 2002 and 2001 (dollars in thousands):


	Year Ended December 31
	2003			2002			2001
Other income:
Interest income	$	15,660		$	3,455		$	5,004
Miscellaneous		2,510			1,694			2,854
Investment gains – net		2,107			—			—
Environmental insurance recovery		—			—			12,349

Total other income	$	20,277		$	5,149		$	20,207

Other expense:
Non-operating costs (a)	$	(10,883	)	$	(16,424	)	$	(14,637	)
Miscellaneous		(2,079	)		(1,783	)		(2,798	)
Equity losses – net		—			(1,131	)		(3,355	)

Total other expense	$	(12,962	)	$	(19,338	)	$	(20,790	)

(a) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations).

18. Variable Interest Entities

101

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. In 1986, we entered into agreements with three separate SPE 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. See Note 8 for further information about the sale leaseback transactions. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs. Certain provisions of FIN No. 46R have a future effective date. We do not expect these provisions to have a material impact on our financial statements.

19. Guarantees

On January 1, 2003, we adopted FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure provisions were effective for the year ended December 31, 2002. The initial recognition and measurement provisions of FIN No. 45 were effective on a prospective basis to guarantees issued or modified after December 31, 2002.

We have entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2003, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit have expiration dates in 2004 and 2005. We have also entered into approximately $109 million of letters of credit to support certain equity lessors in the Palo Verde sale-leaseback transactions (see Note 8 for further details on the Palo Verde sale-leaseback transactions). These letters of credit expire in 2005. Additionally, We have approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2004. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

We provide indemnifications relating to liabilities arising from or related to certain of our agreements. We have provided indemnifications to the equity participants and other parties in the Palo Verde sale-leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification and therefore, the overall maximum amount of the obligation

102

ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II – RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT

The Company has adopted a Code of Ethics for Financial Professionals that applies to professional employees in the areas of finance, accounting, internal audit, energy risk management, marketing and trading financial control, tax, investor relations, and treasury and also includes the Company’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at the Company’s subsidiaries. The Code of Ethics for Financial Professionals is posted on the Company website at www.aps.com. The Company intends to satisfy the requirements under Item 10 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by posting such information on the Company’s website.

ITEM 11. EXECUTIVE COMPENSATION

Not applicable.

ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

Not applicable.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Not applicable.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following fees were paid to our independent public accountants, Deloitte & Touche LLP, for the last two fiscal years:


Type of Service	2002		2003
Audit Fees(1)	$	724,618	$	1,338,846
Audit Related Fees(2)		—		161,970
Tax Fees(3)		32,219		1,677,474
All Other Fees(4)		—		2,304

(1)		The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Forms 10-Q.

(2)		The aggregate fees billed for assurance and services that are reasonably related to the performance of the audit or review of the financial statements that are not included in Audit Fees reported above, which primarily consist of fees for Sarbanes-Oxley Section 404 readiness.

(3)		The aggregate fees billed primarily for investment tax credit services, tax compliance and tax planning.

(4)		The aggregate fees billed for services rendered for all services in 2003, other than the audit services described above, which for 2003 consisted of continuing professional education fees.

Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by the Pinnacle West’s independent public accountants. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for us were pre-approved by the Audit Committee.

106

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K

Financial Statements and Financial Statement Schedules

See the Index to Financial Statements in Part II, Item 8.

Exhibits Filed


Exhibit No.				Description
3.1				Bylaws, amended as of January 21, 2004

12.1				Computation of Ratio of Earnings to Fixed Charges

23.1				Consent of Deloitte & Touche LLP
31.1				Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d – 14(a) of the Securities Exchange Act, as amended

31.2				Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d – 14(a) of the Securities Exchange Act, as amended

32.1				Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1				Risk Factors

In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
3.2	Articles of Incorporation, restated as of May 25, 1988	4.2 to Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report	1-4473	9-29-93

107


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
4.1	Mortgage and Deed of Trust Relating to the Company’s First Mortgage Bonds, together with forty-eight indentures supplemental thereto	4.1 to September 1992 Form 10-Q Report	1-4473	11-9-92

4.2	Forty-ninth Supplemental Indenture	4.1 to 1992 Form 10-K Report	1-4473	3-30-93

4.3	Fiftieth Supplemental Indenture	4.2 to 1993 Form 10-K Report	1-4473	3-30-94

4.4	Fifty-first Supplemental Indenture	4.1 to August 1, 1993 Form 8-K Report	1-4473	9-27-93

4.5	Fifty-second Supplemental Indenture	4.1 to September 30, 1993 Form 10-Q Report	1-4473	11-15-93

4.6	Fifty-third Supplemental Indenture	4.5 to Registration Statement No. 33-61228 by means of February 23, 1994 Form 8-K Report	1-4473	3-1-94

4.7	Fifty-fourth Supplemental Indenture	4.1 to Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report	1-4473	11-22-96

4.8	Fifty-fifth Supplemental Indenture	4.8 to Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report	1-4473	4-9-97

4.9	Fifty-sixth Supplemental Indenture	4.1 to Pinnacle West 2002 Form 10-K Report	1-8962	3-31-03

4.10	Fifty-seventh Supplemental Indenture	4.2 to Pinnacle West 2002 Form 10-K Report	1-8962	3-31-03

4.11	Fifty-eighth Supplemental Indenture	10.1 to the Pinnacle West June 2003 Form 10-Q Report	1-8962	8-14-03

108


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
4.12	Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets	4.1 to 1993 Form 10-K Report	1-4473	3-30-94

4.13	Indenture dated as of January 1, 1995 among the Company and The Bank of New York, as Trustee	4.6 to Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report	1-4473	1-11-95

4.14	First Supplemental Indenture dated as of January 1, 1995	4.4 to Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report	1-4473	1-11-95

4.15	Indenture dated as of November 15, 1996 among the Company and The Bank of New York, as Trustee	4.5 to Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report	1-4473	11-22-96

4.16	First Supplemental Indenture	4.6 to Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report	1-4473	11-22-96

4.17	Second Supplemental Indenture dated as of April 1, 1997	4.10 to Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report	1-4473	4-9-97

4.18	Third Supplemental Indenture	10.2 to the Company’s March 2003 Form 10-Q Report	1-8962	5-15-03

109


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
4.19	Indenture dated as of January 15, 1998 among the Company and The Chase Manhattan Bank, as Trustee	4.10 to Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report	1-4473	1-16-98

4.20	First Supplemental Indenture dated as of January 15, 1998	4.3 to Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report	1-4473	1-16-98

4.21	Second Supplemental Indenture dated as of February 15, 1999	4.3 to Registration Statement Nos. 333-27551 and 333-58445 by means of February 18, 1999 Form 8-K Report	1-4473	2-22-99

4.22	Third Supplemental Indenture dated as of November 1, 1999	4.5 to Registration Statement No. 333-58445 by means of November 2, 1999 Form 8-K Report	1-4473	11-5-99

4.23	Fourth Supplemental Indenture dated as of August 1, 2000	4.1 to Registration Statement Nos. 333-58445 and 333-94277 by means of August 2, 2000 Form 8-K Report	1-4473	8-4-00
4.24	Fifth Supplemental Indenture dated as of October 1, 2001	4.1 to September 2001 Form 10-Q	1-4473	11-6-01

4.25	Sixth Supplemental Indenture dated as of March 1, 2002	4.1 to Registration Statement Nos. 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report	1-4473	2-28-02

4.26	Seventh Supplemental Indenture dated as of May 1, 2003	4.1 to APS’ Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report	1-8962	5-9-03

110


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.1	Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between the Company and Mellon Bank, N.A., as Decommissioning Trustee	10.2 to September 1991 Form 10-Q	1-4473	11-14-91

10.2	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1) dated as of December 1, 1994	10.1 to 1994 Form 10-K Report	1-4473	3-30-95

10.3	Amendment No. 2 to Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991	10.4 to 1996 Form 10-K Report	1-4473	3-28-97

10.4	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002	10.2 to Pinnacle West’s March 2002 Form 10-Q Report	1-8962	5-15-02

10.5	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003	10.3 to Pinnacle West’s March 2003 Form 10-K Report	1-8962	3-15-04

10.6	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3) dated as of December 1, 1994	10.2 to 1994 Form 10-K Report	1-4473	3-30-95

10.7	Amendment No. 2 to Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991	10.6 to 1996 Form 10-K Report	1-4473	3-28-97

111


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.8	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of March 18, 2002	10.4 to Pinnacle West’s March 2002 Form 10-Q Report	1-8962	5-15-02

10.9	Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003	10.5 to 2003 Form 10-K Report	1-8962	3-15-04

10.10	Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992, among the Company, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2	10.1 to Pinnacle West 1991 Form 10-K Report	1-8962	3-26-92

10.11	First Amendment to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992	10.2 to 1992 Form 10-K Report	1-4473	3-30-93

10.12	Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of November 1, 1994	10.3 to 1994 Form 10-K Report	1-4473	3-30-95

112


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.13	Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992	10.1 to June 1996 Form 10-Q Report	1-4473	8-9-96

10.14	Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992	10.5 to 1996 Form 10-K Report	1-4473	3-28-97

10.15	Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000	10.1 to Pinnacle West’s March 2002 Form 10-Q Report	1-8962	5-15-02

10.16	Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002	10.3 to Pinnacle West’s March 2002 Form 10-Q Report	1-8962	5-15-02

10.17	Amendment No. 7 to the Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003	10.4 to Pinnacle West’s Form 10-K Report	1-8962	3-15-04

10.18	Asset Purchase and Power Exchange Agreement dated September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991	10.1 to June 1991 Form 10-Q Report	1-4473	8-8-91

113


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.19	Long-Term Power Transactions Agreement dated September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 8, 1991	10.2 to June 1991 Form 10-Q Report	1-4473	8-8-91

10.20	Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP	10.31 to Pinnacle West’s Form S-14 Registration Statement	2-96386	3-13-85

10.21	Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transactions Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and the Company	10.3 to 1995 Form 10-K Report	1-4473	3-29-96

10.22	Restated Transmission Agreement between PacifiCorp and the Company dated April 5, 1995	10.4 to 1995 Form 10-K Report	1-4473	3-29-96

10.23	Contract among PacifiCorp, the Company and United States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995	10.5 to 1995 Form 10-K Report	1-4473	3-29-96

10.24	Reciprocal Transmission Service Agreement between the Company and PacifiCorp dated as of March 2, 1994	10.6 to 1995 Form 10-K Report	1-4473	3-29-96

10.25	Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant	5.01 to Form S-7 Registration Statement	2-59644	9-1-77

114


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.26	Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant	5.02 to Form S-7 Registration Statement	2-59644	9-1-77

10.27	Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease, Four Corners, dated April 25,1985	10.36 to Registration Statement on Form 8-B of Pinnacle West	1-8962	7-25-85

10.28	Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site	5.04 to Form S-7 Registration Statement	2-59644	9-1-77

10.29	Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Power Plant Site, dated April 25, 1985	10.37 to Registration Statement on Form 8-B of Pinnacle West	1-8962	7-25-85

10.30	Four Corners Project Co-Tenancy Agreement Amendment No. 6	10.7 to Pinnacle West 2000 Form 10-K Report	1-8962	3-14-01

10.31	Application and Grant of Arizona Public Service Company rights-of-way and easements, Four Corners Plant Site	5.05 to Form S-7 Registration Statement	2-59644	9-1-77

10.32	Application and Amendment No. 1 to Grant of Arizona Public Service Company rights-of-way and easements, Four Corners Power Plant Site, dated April 25, 1985	10.38 to Registration Statement on Form 8-B of Pinnacle West	1-8962	7-25-85

10.33	Indenture of Lease, Navajo Units 1, 2, and 3	5(g) to Form S-7 Registration Statement	2-36505	3-23-70

115


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.34	Application and Grant of rights-of-way and easements, Navajo Plant	5(h) to Form S-7 Registration Statement	2-36505	3-23-70

10.35	Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant	5(l) to Form S-7 Registration Statement	2-39442	3-16-71

10.36	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto	10.1 to 1988 Form 10-K Report	1-4473	3-8-89

10.37	Amendment No. 13 dated as of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	10.1 to March 1991 Form 10-Q Report	1-4473	5-15-91

116


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.38	Amendment No. 14, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	10.4 to the Pinnacle West June 30, 2000 Form 10-Q Report	1-8962	8-14-00

10.39^c	Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee	4.3 to Form S-3 Registration Statement	33-9480	10-24-86

10.40^c	Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee	10.5 to September 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8	1-4473	12-4-86

117


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.41^c	Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.3 to 1988 Form 10-K Report	1-4473	3-8-89

10.42^c	Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee	10.3 to 1992 Form 10-K Report	1-4473	3-30-93

10.43	Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee	10.1 to November 18, 1986 Form 8-K Report	1-4473	1-20-87

10.44	Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee	4.13 to Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report	1-4473	8-24-87

118


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.45	Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee	10.4 to 1992 Form 10-K Report	1-4473	3-30-93

10.46^a	Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986	10.1 to June 1986 Form 10-Q Report	1-4473	8-13-86

10.47^a	Second Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of January 1, 1993	10.2 to 1993 Form 10-K Report	1-4473	3-30-94

10.48^a	Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan effective as of May 1, 1993	10.1 to September 1994 Form 10-Q	1-4473	11-10-94

10.49^a	Fourth Amendment dated December 28, 1999 to the Arizona Public Service Company Directors Deferred Compensation Plan	10.8 to Pinnacle West’s 1999 Form 10-K	1-8962	3-30-00

119


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.50^a	Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively	10.4 to 1988 Form 10-K Report	1-4473	3-8-89

10.51^a	Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	10.3 to 1993 Form 10-K Report	1-4473	3-30-94

10.52^a	Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993	10.2 to September 1994 Form 10-Q Report	1-4473	11-10-94

10.53^a	Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan	10.3 to 1997 Form 10-K Report	1-4473	3-28-97

10.54^a	Sixth Amendment to Arizona Public Service Company Deferred Compensation Plan	10.8 to Pinnacle West 2000 Form 10-K Report	1-8962	3-14-01

10.55^a	Schedules of William J. Post	10.2 to Pinnacle West	1-8962	3-31-03
	and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended	Form 10-K Report

120


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.56^a	Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996	10.10 to 1995 Form 10-K Report	1-4473	3-29-96

10.57^a	First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.6 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

10.58^a	Second Amendment effective as of January 1, 2000, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.10 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

10.59^a	Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.3 to Pinnacle West's March 2003 Form 10-Q Report	1-8962	5-15-03

10.60	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.6 to Pinnacle West's 2003 Form 10-K Report	1-8962	3-15-04

10.61^a	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 7, 1999	10.13 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

121


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.62^a	First Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan	10.7 to Pinnacle West’s 2001 Form 10-K Report	1-8962	3-27-02

10.63^a	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	10.7 to Pinnacle West’s 2003 Form 10-K Report	1-8962	3-15-04

10.64^a	Second Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan	10.8 to Pinnacle West’s 2001 Form 10-K Report	1-8962	3-27-02

10.65^a	Pinnacle West Capital Corporation and Arizona Public Service Company Directors’ Retirement Plan effective as of January 1, 1995	10.7 to 1994 Form 10-K Report	1-4473	3-30-95

10.66^a	Pinnacle West Capital Corporation and Arizona Public Service Company Directors’ Retirement Plan, as amended and restated on June 21, 2000	99.2 to Pinnacle West’s Registration Statement on Form S-8 No. 333-40796	1-8962	7-3-00

10.67^a	Arizona Public Service Company Director Equity Plan	10.1 to September 1997 Form 10-K Report	1-4473	11-12-97

10.68^a	Letter Agreement dated December 21, 1993, between the Company and William L. Stewart	10.6 to 1994 Form 10-K Report	1-4473	3-30-95

10.69^a	Letter Agreement dated August 16, 1996 between the Company and William L. Stewart	10.8 to 1996 Form 10-K Report	1-4473	3-28-97

10.70^a	Letter Agreement between the Company and William L. Stewart	10.2 to September 1997 Form 10-Q Report	1-4473	11-12-97

122


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.71^a	Letter Agreement dated December 13, 1999 between the Company and William L. Stewart	10.9 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

10.72^a	Amendment to Letter Agreement, effective as of January 1, 2002, between APS and William L. Stewart	10.1 to Pinnacle West’s June 2002 Form 10-Q Report	1-8962	8-13-02

10.73^a	Letter Agreement dated as of January 1, 1996 between the Company and Robert G. Matlock & Associates, Inc. for consulting services	10.8 to 1995 Form 10-K Report	1-4473	3-29-96

10.74^a	Letter Agreement dated October 3, 1997 between the Company and James M. Levine	10.17 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

10.75^a	Summary of James M. Levine Retirement Benefits	10.2 to Pinnacle West’s March 2002 Form 10-Q Report	1-8962	5-15-02

10.76^a	Employment Agreement, effective as of October 1, 2002, between APS and James M. Levine	10.1 to Pinnacle West’s November 2002 Form 10-Q	1-8962	11-14-02

10.77^a	Employment Agreement dated February 27, 2003 between APS and James M. Levine	10.1 to Pinnacle West’s March 2003 Form 10-Q Report	1-8962	5-15-03

10.78^a	Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler	10.4 to Pinnacle West’s 2002 Form 10-K Report	1-8962	3-31-03

123


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.79^ad	Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries	10.1 to Pinnacle West’s June 1999 Form 10-Q Report	1-8962	8-16-99

10.80^a	Pinnacle West Capital Corporation Stock Option and Incentive Plan	10.1 to 1992 Form 10-K Report	1-4473	3-30-93

10.81^a	First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation Stock Option and Incentive Plan	10.11 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

10.82^a	Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan effective as of March 23, 1994	A to the Proxy Statement for the Plan Report Pinnacle West 1994 Annual Meeting of Shareholders	1-8962	4-16-94

10.83^a	First Amendment dated December 7, 1999, to the Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan	10.12 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

10.84^a	Pinnacle West Capital Corporation 2002 Long- Term Incentive Plan	10.5 to Pinnacle West’s 2002 Form 10-K Report	1-8962	3-31-03

10.85^a	Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996	10.14 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

124


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.86^a	First Amendment dated December 7, 1999, to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans	10.15 to Pinnacle West’s 1999 Form 10-K Report	1-8962	3-30-00

10.87^a	2004 Officer Incentive Plan	10.1 to Pinnacle West’s 2003 Form 10-K Report	1-8962	3-15-04

10.88^a	2004 CEO Variable Incentive Plan	10.2 to Pinnacle West’s 2003 Form 10-K Report	1-8962	3-15-04

10.89	Agreement No. 13904 (Option and Purchase of Effluent) with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23, 1973	10.3 to 1991 Form 10-K Report	1-4473	3-19-92

10.90	Agreement for the Sale and Purchase of Wastewater Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981,including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4, 1986	10.4 to 1991 Form 10-K Report	1-4473	3-19-92

10.91	Territorial Agreement between the Company and Salt River Project	10.1 to March 1998 Form 10-Q Report	1-4473	5-15-98

10.92	Power Coordination Agreement between the Company and Salt River Project	10.2 to March 1998 Form 10-Q Report	1-4473	5-15-98

125


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
10.93	Memorandum of Agreement between the Company and Salt River Project	10.3 to March 1998 Form 10-Q Report	1-4473	5-15-98

10.94	Addendum to Memorandum of Agreement between the Company and Salt River Project dated as of May 19, 1998	10.2 to May 19, 1998 Form 8-K Report	1-4473	6-26-98

99.1	Collateral Trust Indenture among PVNGS II Funding Corp., Inc., the Company and Chemical Bank, as Trustee	4.2 to 1992 Form 10-K Report	1-4473	3-30-93

99.2	Supplemental Indenture to Collateral Trust Indenture among PVNGS II Funding Corp., Inc., the Company and Chemical Bank, as Trustee	4.3 to 1992 Form 10-K Report	1-4473	3-30-93

99.3^c	Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein	28.1 to September 1992 Form 10-Q Report	1-4473	11-9-92

126


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
99.4^c	Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1,1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein	10.8 to September 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8	1-4473	12-4-86

99.5^c	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein	28.4 to 1992 Form 10-K Report	1-4473	3-30-93

127


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
99.6^c	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.5 to Form S-3 Registration Statement	33-9480	10-24-86

99.7^c	Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.6 to September 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8	1-4473	12-4-86

99.8^c	Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.4 to 1992 Form 10-K Report	1-4473	3-30-93

99.9^c	Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.3 to Form S-3 Registration Statement	33-9480	10-24-86

128


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
99.10^c	Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.10 to September 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8	1-4473	12-4-86

99.11^c	Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.6 to 1992 Form 10-K Report	1-4473	3-30-93

99.12	Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, the Company, and the Owner Participant named therein	28.2 to September 1992 Form 10-Q Report	1-4473	11-9-92

129


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
99.13	Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, the Company, and the Owner Participant named therein	28.20 to Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report	1-4473	8-10-87

99.14	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Owner Participant named therein	28.5 to 1992 Form 10-K Report	1-4473	3-30-93

99.15	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.2 to November 18, 1986 Form 8-K Report	1-4473	1-20-87

130


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
99.16	Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.13 to Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report	1-4473	8-24-87

99.17	Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.5 to 1992 Form 10-K Report	1-4473	3-30-93

99.18	Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.5 to November 18, 1986 Form 8-K Report	1-4473	1-20-87

131


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
99.19	Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.7 to 1992 Form 10-K Report	1-4473	3-30-93

99.20c	Indemnity Agreement dated as of March 17, 1993 by the Company	28.3 to 1992 Form 10-K Report	1-4473	3-30-93

99.21	Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank	28.20 to Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report	1-4473	8-10-87

99.22	Rate Reduction Agreement dated December 4, 1995 between the Company and the ACC Staff	10.1 to December 4, 1995 Form 8-K Report	1-4473	12-14-95

99.23	Arizona Corporation Commission Order dated April 24, 1996	10.1 to March 1996 Form 10-Q Report	1-4473	5-14-96

99.24	Arizona Corporation Commission Order, Decision No. 59943, dated December 26, 1996, including the Rules regarding the introduction of retail competition in Arizona	99.1 to 1996 Form 10-K Report	1-4473	3-28-97

99.25	Retail Electric Competition Rules	10.1 to June 1998 Form 10-Q Report	1-4473	8-14-98

132


Exhibit No.	Description	Originally Filed as Exhibit:	File No.^b	Date Effective
99.26	Arizona Corporation Commission Order, Decision No. 61973, dated October 6, 1999, approving our Settlement Agreement	10.1 to September 1999 10-Q Report	1-4473	11-15-99

99.27	Arizona Corporation Commission Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules	10.2 to September 1999 10-Q Report	1-4473	11-15-99

99.28	Addendum to Settlement Agreement	10.1 to Pinnacle West September 2000 10-Q	1-8962	11-14-00

99.29	ACC Opinion and Order dated September 10, 2002, Decision No. 65154 (Track A Order)	99.1 to Pinnacle West’s September 10, 2002 Form 8-K Report	1-8962	9-17-02

99.30	Arizona Public Service Company Application filed with the Arizona Corporation Commission on September 16, 2002	99.2 to Pinnacle West’s September 10, 2002 Form 8-K Report	1-8962	9-17-02

99.31	Track “A” Appeals Issues – Principles for Resolution	99.1 to Pinnacle West’s November 15, 2002 Form 8-K Report	1-8962	12-16-02

99.32	ACC Decision No. 65796 dated April 4, 2003 (Financing Order)	99.3 to Pinnacle West’s March 2003 Form 10-Q Report	1-8962	5-15-03

^aManagement contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.

^bReports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

^cAn additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.

^dAdditional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

133

Reports on Form 8-K

During the quarter ended December 31, 2003 and the period ended March 15, 2004, the Company filed the following Reports on Form 8-K:

Report dated September 30, 2003 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7 and Item 9).

Report dated October 6, 2003 regarding the earnings outlook of Pinnacle West and slides presented at Pinnacle West analysts and investors meetings (Item 5, Item 7 and Item 9).

Report dated November 4, 2003 regarding the ACC approval of the issuance of a rate adjustment mechanism order (Item 5).

Report dated December 31, 2003 containing exhibits comprised of Pinnacle West’s financial information, earnings variance explanations and an earnings news release (Item 7, Item 9 and Item 12).

Report dated January 8, 2004 regarding a delay in the schedule for the hearing for our pending general rate case (Item 5 and Item 7).

Report dated January 27, 2004 regarding APS’ Summary of Responses Received to its Power Supply Resource Request for Proposals dated December 3, 2003 (Item 5 and Item 7).

Report dated February 3, 2004 regarding the ACC Staff’s and RUCO’s initial written testimony filed with the ACC (Item 5).

134

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		ARIZONA PUBLIC SERVICE COMPANY (Registrant)

Date: March 15, 2004		/s/ Jack E. Davis

		(Jack E. Davis, President and Chief
		Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date
/s/ William J. Post	Director	March 15, 2004

(William J. Post, Chairman
of the Board of Directors )

/s/ Jack E. Davis	Principal Executive Officer	March 15, 2004
	and Director
(Jack E. Davis, President
and Chief Executive Officer)

/s/ Donald E. Brandt	Principal Financial Officer	March 15, 2004

(Donald E. Brandt,
Executive Vice President,
and Chief Financial Officer)

/s/ Chris N. Froggatt	Principal Accounting Officer	March 15, 2004

(Chris N. Froggatt,
Vice President and Controller)

135

INDEX TO EXHIBITS


Exhibit No.		Description
3.1	—	Bylaws, amended as of January 21, 2004

12.1	—	Computation of Ratio of Earnings to Fixed Charges

23.1	—	Consent of Deloitte & Touche LLP

31.1	—	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d – 14(a) of the Securities Exchange Act, as amended

31.2	—	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d – 14(a) of the Securities Exchange Act, as amended

32.1	—	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1	—	Risk Factors

For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14.


ARIZONA		86-0011170
(State or other jurisdiction		(I.R.S. Employer Identification No.)
of incorporation or organization)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999		(602) 250-1000
(Address of principal executive offices,		(Registrant’s telephone number,
including zip code)		including area code)


GLOSSARY
PART I
	ITEM 1. BUSINESS
	ITEM 2. PROPERTIES
	ITEM 3. LEGAL PROCEEDINGS
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
	ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
	ITEM 6. SELECTED FINANCIAL DATA
	ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
	ITEM 9A. CONTROLS AND PROCEDURES
PART III
	ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
	ITEM 11. EXECUTIVE COMPENSATION
	ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
	ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
	ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
	ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
SIGNATURES
EX-3.1
EX-12.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-99.1


		Page

GLOSSARY			1
PART I			3
Item 1.	Business		3
Item 2.	Properties		14
Item 3.	Legal Proceedings		19
Item 4.	Submission of Matters to a Vote of Security Holders		19
PART II			19
Item 5.	Market for Registrant’s Common Stock and Related Stockholder Matters		19
Item 6.	Selected Financial Data		20
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		42
Item 8.	Financial Statements and Supplementary Data		43
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		105
Item 9A.	Controls and Procedures		105
PART III			106
Item 10.	Directors and Executive Officers of the Registrant		106
Item 11.	Executive Compensation		106
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		106
Item 13.	Certain Relationships and Related Transactions		106
Item 14.	Principal Accountant Fees and Services		106
PART IV			107
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		107
SIGNATURES			135


		Capacity (kW)

Coal:
	Units 1, 2 and 3 at Four Corners		560,000
	15% owned Units 4 and 5 at Four Corners		222,000
	Units 1, 2 and 3 at Cholla Plant		615,000
	14% owned Units 1, 2 and 3 at the Navajo Plant		315,000

	Subtotal		1,712,000

Gas or Oil:
	Two steam units at Ocotillo and two steam units at Saguaro		430,000
	Eleven combustion turbine units		493,000
	Three combined cycle units		255,000

	Subtotal		1,178,000

Nuclear:
	29.1% owned or leased Units 1, 2, and 3 at Palo Verde		1,113,000

Hydro and Solar			9,191

	Total		4,012,191


		Percent
		Owned by Us

Generating facilities:
	Palo Verde Nuclear Generating Station Units 1 and 3		29.1	%
	Palo Verde Nuclear Generating Station Unit 2 (see “Palo Verde Leases” below)		17.0	%
	Four Corners Steam Generating Station Units 4 and 5		15.0	%
	Navajo Steam Generating Station Units 1, 2, and 3		14.0	%
	Cholla Steam Generating Station Common Facilities (a)		62.4	%(b)
Transmission facilities:
	ANPP 500KV System		35.8	%(b)
	Navajo Southern System		31.4	%(b)
	Palo Verde-Yuma 500KV System		23.9	%(b)
	Four Corners Switchyards		27.5	%(b)
	Phoenix-Mead System		17.1	%(b)
	Palo Verde – Estrella 500KV System		55.5	%(b)
	Palo Verde – SE Valley Project		15.0	%(b)


(Mark One)
x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2003


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from _____ to ______


By Year				By Major Facilities

	2004	$	426	Delivery	$	1,152
	2005		562	Generation		467
	2006		655	Other		24

Total		$	1,643	Total	$	1,643


Quarter	2003		2002

1^st Quarter	$	42,500	$	42,500
2^nd Quarter		42,500		42,500
3^rd Quarter		42,500		42,500
4^th Quarter		42,500		42,500

(a)		Includes reclassifications of revenues in 2003, 2002 and 2001 for the adoption of EITF 03-11. See Note 16 of Notes to Financial Statements.

(b)		Changes associated with a regulatory disallowance. See “Regulatory Accounting” in Note 1 of Notes to Financial Statements.

(c)		Change in accounting standards related to derivatives in 2001. See Note 16 of Notes to Financial Statements.


			Increase (Decrease)

			Pretax			After Tax

Regulated electricity segment gross margin:
	Increased purchased power and fuel costs primarily due to higher prices for hedged gas and purchased power		$	(74	)	$	(45	)
	Higher replacement power costs from plant outages due to higher market prices and more unplanned outages			(47	)		(28	)
	Retail electricity price reductions effective July 1, 2002 and July 1, 2003			(27	)		(16	)
	Higher retail sales volumes due to customer growth, excluding weather effects			48			29
	Effects of weather on retail sales			13			8
	Decreased purchased power costs due to new power plants in service			8			5
	Miscellaneous factors, net			8			4

		Net decrease in regulated electricity segment gross margin		(71	)		(43	)

Marketing and trading segment gross margin:
	Increase in generation sales other than Native Load primarily due to higher sales volumes partially offset by lower unit margins			10			6
	Miscellaneous factors, net			(3	)		(2	)

		Net increase in marketing and trading segment gross margin		7			4

		Net decrease in regulated electricity and marketing and trading segments’ gross margins		(64	)		(39	)
Operations and maintenance expense decreases (increases):
		Severance costs recorded in 2002		34			20
		Increased pension and other benefit costs		(22	)		(13	)
		Increased costs related to customer growth and increased payroll		(15	)		(9	)
		Increased payroll cost related to transfer of power marketing division		(13	)		(8	)
		Net other items		(2	)		(1	)
Higher interest expense due to higher debt balances				(14	)		(8	)
Depreciation and amortization decreases (increases):
		Decreased regulatory asset amortization		29			18
		Increased delivery and other assets		(19	)		(12	)
Our return to the AFUDC method of capitalizing construction finance costs				8			11
Higher other income due to increased interest income and investment gains				15			9
Miscellaneous items, net				5			3
Tax credits and favorable income tax adjustments related to prior years resolved in 2003				—			11

		Net decrease in net income	$	(58	)	$	(18	)


			Increase/(Decrease)

			Pretax			After Tax

Regulated electricity segment gross margin:
	Lower replacement power costs for plant outages due to lower market prices and fewer unplanned outages		$	127		$	76
	Increased purchased power and fuel costs due to higher hedged gas and power prices, partially offset by improved hedge management, net of mark-to-market reversals			(24	)		(14	)
	Lower purchased power and fuel costs related to the 2001 generation reliability program			30			18
	Higher retail sales volumes due to customer growth and higher average usage, excluding weather effects			38			23
	2001 charges related to purchased power contracts with Enron and its affiliates			13			8
	Retail price reductions effective July 1, 2001 and July 1, 2002			(28	)		(17	)
	Effects of milder weather on retail sales			(27	)		(16	)

		Net increase in regulated electricity segment gross margin		129			78

Marketing and trading segment gross margin:
	Decrease in marketing and trading segment margin resulting from our transfer of marketing and trading activities to Pinnacle West in 2001			(156	)		(93	)
	Decrease in generation sales other than Native Load due to lower market prices partially offset by higher sales volumes			(78	)		(47	)

		Net decrease in marketing and trading segment gross margin		(234	)		(140	)

Net decrease in regulated electricity and marketing and trading segments’ gross margins				(105	)		(62	)
Higher operations and maintenance expense related to 2002 severance costs of approximately $34 million, partially offset by lower generation reliability costs				(30	)		(18	)
Lower depreciation and amortization expense primarily related to lower regulatory asset amortization				21			13
Higher taxes other than income taxes				(7	)		(4	)
Lower other income primarily due to a 2001 insurance recovery of environmental remediation costs				(15	)		(9	)
Higher net interest expense primarily due to higher debt balances and lower capitalized interest				(3	)		(2	)
Miscellaneous factors, net				2			1

	Net decrease in income before accounting change		$	(137	)		(81	)

Increase due to 2001 cumulative effect of change in accounting for derivatives - - net of income taxes							15

	Net decrease in net income					$	(66	)


		(Actual)		(Estimated)

		2003		2004		2005		2006

Delivery		$	288	$	309	$	390	$	453
Generation (a)			136		107		160		200
Other (b)			5		10		12		2

	Total	$	429	$	426	$	562	$	655


			2005-		2007-		There-
	2004		2006		2008		after		Total

Long-term debt payments, including interest (a)	$	342	$	699	$	192	$	2,567	$	3,800
Capital lease payments		2		4		2		3		11
Operating lease payments		65		127		125		402		719
Minimum pension funding requirement (b)		89		—		—		—		89
Purchase power and fuel commitments (c)		262		187		102		461		1,012
Purchase obligations (d)		87		27		5		68		187
Nuclear decommissioning funding requirements		11		22		22		158		213

Total contractual commitments	$	858	$	1,066	$	448	$	3,659	$	6,031


	Moody's		Standard & Poor's

Senior secured		A3		A-
Senior unsecured	Baa1		BBB
Secured lease obligation bonds	Baa2		BBB
Commercial paper		P-2		A-2
Outlook	Negative		Stable


		Increase/(Decrease)

		Impact on
		Projected			Impact on			Impact on
		Benefit			Pension			Pension
Actuarial Assumption (a)		Obligation			Liability			Expense

Discount rate:
	Increase 1%	$	(165	)	$	(123	)	$	(8	)
	Decrease 1%		189			139			6
Expected long-term rate of return on plan assets:
	Increase 1%		—			—			(3	)
	Decrease 1%		—			—			3


		Increase/(Decrease)

		Impact on Accumulated			Impact on Other
		Postretirement Benefit			Postretirement
Actuarial Assumption (a)		Obligation			Benefit Expense

Discount rate:
	Increase 1%	$	(81	)	$	(5	)
	Decrease 1%		96			5
Health care cost trend rate (b):
	Increase 1%		95			7
	Decrease 1%		(76	)		(5	)
Expected long-term rate of return on plan assets – pretax:
	Increase 1%		—			(1	)
	Decrease 1%		—			1

•		Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements of our regulated electricity business segment; and

•		Marketing and Trading – non-trading and trading derivative instruments of our competitive business segment.

(a)		These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.

(b)		These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

•		Management is responsible for establishing and maintaining effective internal control over financial reporting of Arizona Public Service Company (the “Company”). The internal control contains monitoring mechanisms, and actions are taken to correct deficiencies identified.

•		There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

•		Management evaluated the Company’s internal control over financial reporting as of December 31, 2003. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2003.

(a)		The majority of our unamortized regulatory assets above relates to deferred income taxes (see Note 4) and rate synchronization cost deferrals (see “Rate Synchronization Cost Deferrals” below).

(b)		See “Reacquired Debt Costs” below.

(a)		See Note 11 for information on Asset Retirement Obligations.

(b)		See “ACC Financing Orders” in Note 3 for information on the “APS Loan”.

•		material and labor;

•		contractor costs;

•		capitalized leases;

•		construction overhead costs (where applicable); and

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

•		Fossil plant – 23 years;

•		Nuclear plant – 20 years;

•		Other generation – 25 years

•		Transmission – 36 years;

•		Distribution – 23 years; and

•		Other – 9 years.

•		Note 7 for amended disclosure requirements (SFAS No. 132) on retirement plans and other benefits;

•		Note 11 for a new accounting standard (SFAS No. 143) on asset retirement obligations;

•		Notes 14 for a new accounting standard (SFAS No. 148) related to stock-based compensation;

•		Note 16 for EITF issues (EITF 02-3 and 03-11), DIG Issue No. C15, and a new accounting standard (SFAS No. 149) related to accounting for derivatives and energy contracts;

•		Note 18 for a new FASB interpretation (FIN No. 46R) related to VIEs; and

•		Note 19 for a new FASB interpretation (FIN No. 45) on guarantees.

		customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.

•		Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.

•		There is a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor we are prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance 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.

•		We will be permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. See “General Rate Case and Retail Rate Adjustment Mechanisms” below.

•		Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of 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 providing 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.

•		Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we had demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also states that we will not be allowed to recover $183 million net present value (in 1999 dollars) of the $533 million. The 1999 Settlement Agreement

		provides that we will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As discussed below under “General Rate Case and Retail Rate Adjustment Mechanisms,” we are seeking to recover amounts written off by us as a result of the 1999 Settlement Agreement.

•		The 1999 Settlement Agreement required us to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) our competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that we would be allowed to defer and later collect, beginning July 1, 2004, 67% of our costs to accomplish the required transfer of generation assets to an affiliate. However, as discussed below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing the Track A Order, an order preventing us from transferring our generation assets. We are seeking to recover all costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “General Rate Case and Retail Rate Adjustment Mechanisms” below.

•		They apply to virtually all Arizona electric utilities regulated by the ACC, including us.

•		Effective January 1, 2001, retail access became available to all of our retail electricity customers.

•		Electric service providers that get CC&N’s from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.

•		Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.

•		The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.

•		Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our

(1)		Pinnacle West Energy agreed to provide 1,700 MW in July through September of 2003 and in June through September of 2004, 2005 and 2006, by means of a unit contingent contract.

(2)		PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.

(3)		Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.

•		any debt issued by us pursuant to the order must be unsecured;

•		the APS Loan must be callable and secured by the PWEC Dedicated Assets;

•		the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on our debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security);

•		the 264 basis points referred to in the previous bullet point will be capitalized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum;

•		the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC;

•		any demonstrable increase in our cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;

•		we must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce our common equity ratio below that threshold, unless otherwise waived by the ACC. The ACC will process any waiver request within sixty days, and for this sixty-day period this condition will be suspended. However, this condition, which will continue indefinitely, will not be permanently waived without an order of the ACC; and

•		certain waivers of the ACC’s affiliated interest rules previously granted to us and our affiliates will be temporarily withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each, a “Covered Transaction”), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, except that the foregoing restrictions will not apply to the following categories of Covered Transactions:


	Annual Revenue		Percent

Increase in base rates	$	166.8		9.3	%
Rules compliance charge		8.3		0.5	%

Total increase	$	175.1		9.8	%


							December 31,

		Maturity		Interest
		Dates (a)		Rates			2003			2002

First mortgage bonds			2004		6.625	%	$	80,000		$	80,000
			2023		7.25	%(b)					54,150
			2025		8.0	%(c)					33,075
			2028		5.5	%		25,000			25,000
			2028		5.875	%		154,000			154,000
Unamortized discount and premium								(8,631	)		(6,337	)
Pollution control bonds			2024-2034		(d	)		386,860			386,860
Pollution control bonds with senior notes (e)			2029		5.05	%		90,000			90,000
Unsecured notes			2004		5.875	%		125,000			125,000
Unsecured notes			2005		6.25	%		100,000			100,000
Unsecured notes			2005		7.625	%		300,000			300,000
Unsecured notes			2011		6.375	%		400,000			400,000
Unsecured notes			2012		6.50	%		375,000			375,000
Unsecured notes			2033		5.625	%		200,000			—
Unsecured notes			2015		4.650	%		300,000			—
Senior notes (f)			2006		6.75	%		83,695			83,695
Capitalized lease obligations			2004-2012		(g	)		11,749			20,400

Total long-term debt								2,622,673			2,220,843
	Less current maturities							206,727			3,503

Total long-term debt less current maturities							$	2,415,946		$	2,217,340


		Pension									Other Benefits

		2003			2002			2001			2003			2002			2001

Service cost-benefits earned during the period		$	37,662		$	30,333		$	27,640		$	15,858		$	12,036		$	9,438
Interest cost on benefit obligation			76,951			71,242			66,549			30,163			25,235			21,585
Expected return on plan assets			(65,046	)		(75,652	)		(77,340	)		(18,762	)		(21,116	)		(21,985	)
Amortization of:
	Transition (asset)/obligation		(3,227	)		(3,227	)		(3,227	)		3,005			4,001			7,698
	Prior service cost/(credit)		2,401			2,912			3,008			(125	)		(75	)		—
	Net actuarial loss/(gain)		18,135			1,846			907			9,714			3,072			(4,066	)

Net periodic benefit cost		$	66,876		$	27,454		$	17,537		$	39,853		$	23,153		$	12,670

Our share of costs charged to expense		$	25,450		$	10,947		$	6,699		$	15,166		$	9,232		$	4,840


		2003		2002

Decrease/(Increase) in minimum liability included in other comprehensive income – net of tax:
	Pinnacle West Consolidated	$	4,700	$	(70,298	)
	Our share		4,329		(60,521	)


		2003		2002

Projected benefit obligation		$	1,307,628	$	1,069,577

Accumulated benefit obligation		$	1,075,352	$	904,687
Less fair value of plan assets			887,311		720,807

	Pinnacle West pension liability	$	188,041	$	183,880

	Our share of pension liability	$	160,639	$	156,442


							Benefit Costs
	Benefit Obligations						For the Years Ended
	As of December 31,						December 31,

	2003			2002			2003			2002

Discount rate		6.10	%		6.75	%		6.75	%		7.50	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
Expected long-term return on plan assets		9.00	%		9.00	%		9.00	%		10.00	%
Initial health care cost trend rate		8.00	%		8.00	%		8.00	%		7.00	%
Ultimate health care cost trend rate		5.00	%		5.00	%		5.00	%		5.00	%
Year ultimate health care trend rate is reached		2008			2007			2007			2006