ITEM 1. BUSINESS
CURRENT STATUS
GENERAL
We were incorporated in 1985 under the laws of the State of Arizona and own all of the outstanding equity securities of APS. APS is an 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 owned by APS. APS also generates, sells and delivers electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our competitive electricity generation operations;
* APS Energy Services, which provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States;
* SunCor, a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah; and
* El Dorado, which owns a majority interest in NAC (specializing in spent nuclear fuel technology) and holds miscellaneous small investments, including interests in Arizona community-based ventures.
We discuss each of these subsidiaries in greater detail below.
MARKETING AND TRADING
In early 2003, we moved our marketing and trading division from Pinnacle West to APS for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting the previously required transfer of APS' generating assets to Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" below). The marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS' Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. The division focuses primarily on managing APS' purchased power and fuel risks in connection with its costs of serving retail customer energy requirements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Financial Outlook" in Item 7 for a discussion of APS' implementation of an
ACC-mandated process by which APS must competitively procure energy. Additionally, the marketing and trading division, subject to specific parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 for information about the historical and prospective contribution of the marketing and trading activities to our financial results.
BUSINESS SEGMENTS
We have three principal business segments (determined by products, services and the regulatory environment):
* our regulated electricity segment (76% of operating revenues in 2002), which consists of regulated traditional retail and wholesale electricity businesses and related activities, and includes electricity transmission, distribution and generation;
* our marketing and trading segment (12% of operating revenues in 2002), which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services' commodity-related energy services; and
* our real estate segment (9% of operating revenues in 2002), which consists of SunCor's real estate development and investment activities.
See Note 17 of Notes to Consolidated Financial Statements in Item 8 for financial information about our business segments.
EMPLOYEES
At December 31, 2002, we employed about 7,200 people, including the employees of our subsidiaries. Of these employees, about 5,100 were employees of our major subsidiary, APS, and employees assigned to jointly-owned generating facilities for which APS serves as the generating facility manager. About 2,100 people were employed by Pinnacle West and our other subsidiaries. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
OVERVIEW OF ARIZONA REGULATORY DEVELOPMENTS
As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Financial Outlook" in Item 7, we believe pending Arizona regulatory matters are among the key factors affecting our financial outlook.
GENERAL
On September 21, 1999, the ACC approved Rules that provided a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy on or before that
date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed APS not to transfer its generation assets to Pinnacle West Energy. See Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional information about the 1999 Settlement Agreement, the Rules (including legal challenges to the Rules) and the Track A Order.
APS FINANCING APPLICATION
On September 16, 2002, APS filed an application with the ACC requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or a combination of both, not to exceed $500 million in the aggregate. In its application, APS stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing that we provided to fund the construction of Pinnacle West Energy generation assets or from effectively competing in the wholesale markets. On March 27, 2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt or a combination of both, not to exceed $500 million in the aggregate. See "ACC Applications" in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional information.
COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things, established a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order, which documented the decision made by the ACC at its open meeting on February 27, 2003, addressing this requirement. Under the order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS will be required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets." The order recognizes APS' right to reject any bids that are unreasonable, uneconomical or unreliable.
APS expects to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply APS' electricity requirements. See "Track B Order" in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional information.
APS GENERAL RATE CASE
As required by the 1999 Settlement Agreement, on or before June 30, 2003, APS will file a general rate case with the ACC. In this rate case, APS will update its cost of service and rate design. In addition, APS expects to seek:
* rate base treatment of certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3);
* recovery of the $234 million pretax asset write-off recorded by APS as a result of the 1999 Settlement Agreement; and
* recovery of costs incurred by APS in preparation for the previously required transfer of generation assets to Pinnacle West Energy.
We assume that the ACC will make a decision in this general rate case by the end of 2004.
AVAILABLE INFORMATION
We make available free of charge on or through our Internet website (www.pinnaclewest.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information on our website is not part of this report.
FORWARD-LOOKING STATEMENTS
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. 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 the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition; the outcome of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including price caps and other market constraints imposed by the FERC; regional economic and market conditions, including the California energy situation and 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; weather variations affecting local and regional customer energy usage; the effect of conservation programs on energy usage; power plant performance; the successful completion of our generation construction program; regulatory issues associated with generation construction, such as permitting and licensing; our ability to compete successfully outside traditional regulated markets (including the wholesale market); our ability to manage our marketing and trading activities and the use of derivative contracts in our business; technological developments in the electric industry; the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommissioning trust funds; the strength of the real estate market in SunCor's market areas, which include Arizona, New Mexico and Utah; and other uncertainties, all of which are difficult to predict and many of which are beyond our control.
REGULATION AND COMPETITION
RETAIL
The ACC regulates APS' retail electric rates and its issuance of securities. The ACC must also approve any transfer of APS' utility property and certain transactions between APS and affiliated parties. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Financial Outlook" in Item 7 and Note 3 of Notes to Consolidated Financial Statements in Item 8 for a discussion of the status of electric industry restructuring in Arizona.
APS is subject to varying degrees of competition from other utilities in Arizona (such as Tucson Electric Power Company, Southwest Gas Corporation and Citizens Communications Company) as well as cooperatives, municipalities, electrical districts and similar types of governmental organizations (principally Salt River Project). APS also faces competition from low-cost hydroelectric power and parties that have access to low-priced preferential federal power and other subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate facilities to generate their own electric energy requirements. Although some very limited retail competition existed in APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete effectively in a restructured industry.
WHOLESALE
GENERAL
The FERC regulates rates for wholesale power sales and transmission services. During 2002, approximately 20% of our electric operating revenues resulted from such sales and services. In early 2003, we moved our marketing and trading division from Pinnacle West to APS for all future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting the previously required transfer of APS' generating assets to Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" above). The marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS' Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. The division focuses primarily on managing APS' purchased power and fuel risks in connection with its costs of serving retail customer energy requirements. See "Track B Order" in Note 3 of Notes to Consolidated Financial Statements in Item 8 for information regarding an ACC-mandated process by which APS must competitively procure energy. See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding our generation construction plans.
REGIONAL TRANSMISSION ORGANIZATIONS
On December 20, 1999, the FERC issued its Order No. 2000 regarding regional transmission organizations. In its order, the FERC set minimum characteristics and functions that must be met by utilities that participate in 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.
As stated in Order No. 2000, the FERC believes that a number of benefits will result from the formation of RTOs throughout the country, and it has moved aggressively to ensure that all public utilities participate in an RTO or demonstrate why such participation is not feasible. According to the FERC, the benefits it expects to result from RTO formation include: (1) improvements in transmission system operations with resulting enhancements to inter-regional trade, congestion management, reliability and coordination; and (2) improved performance of energy markets, including greater incentives for efficient generator performance and enhanced potential for demand response.
On October 16, 2001, APS and other owners of electric transmission lines in the Southwest filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC's requirements for the formation of an RTO. APS and the other filing parties have agreed to fund the start-up of WestConnect's operations, which are subject to FERC approval. WestConnect has been structured as a for-profit RTO and evolved from DesertSTAR, a not-for-profit corporation in which APS participated, which was originally designed to serve as an RTO for the southwestern United States. The success of WestConnect will be largely dependent on participation by all major transmission owners in the Southwest. The success is also dependent on support from the affected state regulatory commissions.
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. In its order, the FERC also stated that its approval of various WestConnect provisions addressed in the order would not be overturned or affected by the final rule the FERC intends to ultimately adopt in response to its July 31, 2002 Notice of Proposed Rulemaking regarding a standard market design for the electric utility industry (see "Federal" in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Notice of Proposed Rulemaking). On November 12, 2002, APS and other owners filed a request for rehearing and clarification on portions of the October 10, 2002 order.
On December 23, 2002, the FERC issued its order on rehearing. In it, the FERC clarified the RTO elements that it had approved. In its order, the FERC stated that it envisions the Seams Steering Group - Western Interconnection (SSG-WI) as the entity that will facilitate a common market design for the West. The SSG-WI consists of western transmission owners, including members of WestConnect. The FERC also noted that its prior WestConnect order did not address other elements of market design that are currently being considered in the pending SMD proposal and/or through the SSG-WI process. The FERC clarified that there are only three areas that would be subject to the final SMD rule: (1) transmission credits; (2) resource adequacy; and (3) market monitoring.
The order also stated that the FERC's approval of the for-profit structure will not predetermine its decision in the final SMD rule regarding whether a for-profit independent transmission company should be permitted to perform all the functions of an independent transmission provider. To the extent that the FERC has not addressed aspects of WestConnect's for-profit proposal or WestConnect's proposed particular functions, such elements will be subject to review for consistency with Order No. 2000 and other related decisions regarding
functions that may be performed by an independent transmission company. The WestConnect applicants sought further clarification of that aspect of the rehearing order. The FERC has indicated that it will issue an order on the WestConnect applicants' motion for clarification before April 14, 2003.
The ACC 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. APS 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. On February 8, 2002, the ACC's Chief ALJ issued a procedural order which consolidated the ACC docket relating to the AISA with several other pending ACC dockets. In its Track B Order, the ACC directed that a hearing be held on whether or not APS should be required to continue funding the AISA.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
Following is a discussion of the business of APS, our major subsidiary.
GENERAL
APS was incorporated in 1920 under the laws of Arizona and currently has more than 902,000 customers. APS 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 APS owns. APS also generates, sells and delivers electricity to wholesale customers in the western United States. APS' marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy's generation output that is not needed for APS' Native Load, which includes loads for retail customers and cost-of-service wholesale customers. APS does not distribute any products. During 2002, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 4% of consolidated electric revenues.
At December 31, 2002, APS employed approximately 5,100 people, which includes employees assigned to jointly-owned generating facilities for which APS serves as the generating facility manager. APS' principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
PURCHASED POWER AND GENERATING FUEL
See "Properties - Capacity" in Item 2
ITEM 2. PROPERTIES
CAPACITY
Our generating facilities are described below. For APS' plants, the "net accredited capacities" are reported, consistent with industry practice for regulated utilities. For Pinnacle West Energy, the "permitted capacities" are reported, consistent with industry practice for unregulated plants.
APS - NET ACCREDITED CAPACITY
APS' present generating facilities have net accredited capacities as follows:
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(a) 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 ........ 1,086,300 ---------
Hydro and Solar ................................................ 7,600 ---------
Total APS facilities ......................................... 3,983,900 =========
PINNACLE WEST ENERGY - PERMITTED CAPACITIES
Pinnacle West Energy's present generating facilities have permitted capacities as follows:
Gas or Oil: Two combined cycle units at Redhawk and one combined-cycle unit at West Phoenix .............................................. 1,180,000(b) One combustion turbine unit at Saguaro ......................... 80,000 ---------
Total Pinnacle West Energy facilities .......................... 1,260,000 =========
- ---------- (a) Does not include West Phoenix steam units (108,300 kW), which were retired in December 2002. (b) See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding Pinnacle West Energy's generation construction plans.
RESERVE MARGIN
APS' 2002 peak one-hour demand on its electric system was recorded on July 9, 2002 at 5,802,900 kW, compared to the 2001 peak of 5,687,200 kW recorded on July 2, 2001. Taking into account additional capacity then available to APS under long-term purchase power contracts as well as APS' and Pinnacle West Energy's generating capacity, APS' capability of meeting system demand on July 9, 2002 amounted to 6,046,600 kW, for an installed reserve margin of 6.5%. The power actually available to APS from its resources fluctuates from time to time due in part to planned outages and technical problems. The available capacity from sources actually operable at the time of the 2002 peak amounted to 3,877,600 kW, for a margin of negative 38.1%. Firm purchases totaling 2,612,000 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 7.1%.
See "Business of Arizona Public Service Company - Purchased Power Agreements" in Item 1 for information about certain of APS' long-term power agreements.
PLANT SITES LEASED FROM NAVAJO NATION
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.
PALO VERDE NUCLEAR GENERATING STATION
PALO VERDE LEASES
See Note 9 of Notes to Consolidated Financial Statements in Item 8 for a discussion of three sale-leaseback transactions related to Palo Verde Unit 2.
REGULATORY
Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.
NUCLEAR DECOMMISSIONING COSTS
The NRC rules on financial assurance requirements for the decommissioning of nuclear power plants provide that a licensee may use a trust as the exclusive financial assurance mechanism if the licensee recovers estimated total decommissioning costs through cost of service rates or through a "non-bypassable charge." The "non-bypassable systems benefits" charge is the charge that the ACC has approved 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 APS, the customer will still have to pay this charge as part of the customer's APS electric bill. Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on the external sinking fund mechanism are not met. APS currently relies on the external sinking fund mechanism to meet the NRC financial assurance requirements for its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS' ACC jurisdictional rates. ACC retail electric competition Rules provide that decommissioning costs would be recovered through a non-bypassable "system benefits" charge, which would allow APS to maintain its external sinking fund mechanism. See Note 12 of Notes to Consolidated Financial Statements in Item 8 for additional information about our nuclear decommissioning costs.
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 11 of Notes to Consolidated Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.
PROPERTY NOT HELD IN FEE OR SUBJECT TO ENCUMBRANCES
JOINTLY-OWNED FACILITIES
APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS' interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2002:
PERCENT OWNED BY APS ------------ 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) 62.8%(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 50.0%(b)
(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
PALO VERDE LEASES
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. See Notes 9 and 20 of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale-leaseback transactions.
APS FIRST MORTGAGE LIEN
APS' 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 Consolidated Financial Statements in Item 8 for information regarding APS' outstanding first mortgage bonds.
OTHER INFORMATION REGARDING OUR PROPERTIES
See "Environmental Matters" and "Water Supply" in Item 1 with respect to matters having 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 plans.
INFORMATION REGARDING PROPERTIES OF PINNACLE WEST ENERGY AND SUNCOR
See "Business of Pinnacle West Energy Corporation" and "Business of SunCor Development Company" for information regarding Pinnacle West Energy's and SunCor's properties.
[MAP PAGE}
In accordance with Item 304 of Regulation S-T of the Securities Exchange Act of 1934, APS' Service Territory map contained in this Form 10-K is a map of the State of Arizona showing APS' service area, the location of its major power plants and principal transmission lines, the location of Pinnacle West Energy's power plants and the location of transmission lines operated by APS for others. APS' major power plants shown on such map are the Navajo Generating Station located in Coconino County, Arizona; the Four Corners Power Plant located near Farmington, New Mexico; the Cholla Power Plant, located in Navajo County, Arizona; the Yucca Power Plant, located near Yuma, Arizona; the Palo Verde Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona; the West Phoenix Power Plant, located near Phoenix, Arizona; and the Saguaro Power Plant, located near Tucson, Arizona (each of which plants is reflected on such map as being jointly owned with other utilities), as well as the Ocotillo Power Plant located near Phoenix, Arizona. Pinnacle West Energy's power plants shown on such map are the West Phoenix Power Plant located near Phoenix, Arizona, and the Saguaro Power Plant, located near Tucson, Arizona (both of which plants are reflected on such map as being jointly owned with APS), as well as the Redhawk Power Plant, located near Phoenix, Arizona. APS' major transmission lines shown on such map are reflected as running between the power plants named above and certain major cities in the State of Arizona. The transmission lines operated for others shown on such map are reflected as running from the Four Corners Plant through a portion of northern Arizona to the California border and from the Phoenix area.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
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 Consolidated Financial Statements in Item 8 for a discussion of the ACC retail electric competition Rules, the Track A Order and related litigation.
See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information relating to the FERC proceedings on California energy market issues and a claim by Citizens that APS overcharged Citizens under a power service agreement. See also Note 22 of Notes to Consolidated Financial Statements in Item 8 for information relating to a breach of contract claim by Maine Yankee against Pinnacle West and NAC.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers are as follows:
Name Age at March 1, 2003 Position(s) at March 1, 2003 - ---- -------------------- ---------------------------- William J. Post 52 Chairman of the Board and Chief Executive Officer (1) Jack E. Davis 56 President, and President and Chief Executive Officer, APS (1) Robert S. Aiken 46 Vice President, Federal Affairs John G. Bohon 57 Vice President, Corporate Services & Human Resources Donald E. Brandt 48 Senior Vice President and Chief Financial Officer Dennis L. Brown 52 Vice President and Chief Information Officer Armando B. Flores 59 Executive Vice President, Corporate Business Services Edward Z. Fox 49 Vice President, Communications, Environment & Safety Barbara M. Gomez 48 Treasurer James M. Levine 53 Executive Vice President, APS and President, Pinnacle West Energy Nancy C. Loftin 49 Vice President, General Counsel and Secretary Gregg R. Overbeck 56 Senior Vice President, APS, Nuclear Martin L. Shultz 58 Vice President, Government Affairs Steven M. Wheeler 54 Senior Vice President, APS Transmission, Regulation and Planning - ---------- (1) Member of the Board of Directors.
The executive officers of Pinnacle West are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and the principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows:
Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the following capacities: from August 1999 to February 2001 as President; from February 1997 to February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post is also a director of APS, Pinnacle West Energy and Phelps Dodge Corporation.
Mr. Davis was elected to his present position effective February 2001. Prior to that time he was Chief Operating Officer and Executive Vice President of Pinnacle West (April 2000-February 2001) and Executive Vice President, Commercial Operations of APS (September 1996-October 1998). Mr. Davis is President of APS (since October 1998) and Chief Executive Officer of APS (since October 2002). He is a director of APS and Pinnacle West Energy.
Mr. Aiken was elected to his present position in July 1999. Prior to that time he was Pinnacle West's Manager, Federal Affairs (November 1986-July 1999).
Mr. Bohon was elected to his present position in July 1999. Prior to that time he was Vice President, Corporate Services and Human Resources of APS (October 1998-July 1999) and Vice President, Procurement of APS (April 1997-October 1998).
Mr. Brandt was elected to his present position in December 2002. Prior to that time he was Senior Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services company). Mr. Brandt was elected Senior Vice President and Chief Financial Officer of APS in January 2003.
Mr. Brown was elected to his present position in June 2001. Prior to that time he was Director, Information Technology of Pinnacle West (October 1999 - June 2001) and Global Solution Executive for IBM Utilities and Energy Services of IBM prior to that time.
Mr. Flores was elected to his present position in July 1999. Prior to that time, he was Executive Vice President, Corporate Business Services of APS (October 1998-July 1999) and Senior Vice President, Corporate Business Services of APS (September 1996-October 1998).
Mr. Fox was elected to his present position in July 1999. Prior to that time he was Vice President, Environmental/Health/Safety and New Technology Ventures of APS (October 1995-July 1999).
Ms. Gomez was elected to her present position in August 1999. Prior to that time, she was Manager, Treasury Operations of APS (1997-1999). She was also elected Treasurer of APS in October 1999.
Mr. Levine was elected Executive Vice President of APS in July 1999 and President of Pinnacle West Energy in January 2003. Prior to that time he was Senior Vice President, Nuclear Generation of APS (September 1996-July 1999).
Ms. Loftin was elected Vice President and General Counsel in July 1999 and Secretary in October 2002. She was elected to the positions of Vice President and Chief Legal Counsel of APS in September 1996. She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.
Mr. Overbeck was elected to his present position in July 1999. Prior to that time he was Vice President, Nuclear Production of APS (September 1996 to July 1999) and Vice President, Nuclear Support of APS (July 1995 to September 1996).
Mr. Shultz was elected to his current position in July 1999. Prior to that time he held the position of Director of Government Relations for APS (1988-July 1999).
Mr. Wheeler was elected to his present position in October 2002. Prior to that time he was Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS (June 2001 - October 2002). Prior to that time he was a partner with Snell & Wilmer L.L.P.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Our common stock is publicly held and is traded on the New York and Pacific Stock Exchanges. At the close of business on March 26, 2003, our common stock was held of record by approximately 36,876 shareholders.
See "Quarterly Stock Prices and Dividends Per Share" in Item 6
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
(a) Tax benefit stemming from the resolution of income tax matters related to a former subsidiary MeraBank, A Federal Savings Bank. (b) Charges associated with a regulatory disallowance. See "Regulatory Accounting" in Note 1. (c) Change in accounting standards related to derivatives in 2001. See Note 18. (d) Change in accounting standards related to trading activities in 2002. See Note 18.
REGULATED ELECTRICITY AND MARKETING AND TRADING SEGMENTS' REVENUES
(a) The breakout of retail load hedge management and generation sales other than Native Load is not available for 1998. These amounts are included in other delivered electricity in the marketing and trading segment for 1998.
(a) The breakout of retail load hedge management and generation sales other than Native Load is not available for 1998. These amounts are included in other delivered electricity in the marketing and trading segment for 1998.
See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of certain information in the tables above.
QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE STOCK SYMBOL: PNW Dividends Per 2002 High Low Close Share - ----------- ------ ------ ------ ------ 1st Quarter $45.60 $39.36 $45.35 $0.400 2nd Quarter 46.68 37.08 39.50 0.400 3rd Quarter 39.72 25.82 27.76 0.400 4th Quarter 34.36 21.70 34.09 0.425
Dividends Per 2001 High Low Close Share - ----------- ------ ------ ------ ------ 1st Quarter $47.96 $39.06 $45.87 $0.375 2nd Quarter 50.70 45.20 47.40 0.375 3rd Quarter 49.93 37.65 39.70 0.375 4th Quarter 43.50 38.00 41.85 0.400
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In this Item, we explain the results of operations, general financial condition and outlook for Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado, including:
* the changes in our earnings from 2001 to 2002 and from 2000 to 2001;
* our capital needs, liquidity and capital resources;
* our critical accounting policies;
* our business outlook and major factors that affect our financial outlook; and
* our management of market risks.
Throughout this Item, we refer to specific "Notes" in the Notes to Consolidated Financial Statements in Item 8 of this report. These Notes add further details to the discussion.
BUSINESS OVERVIEW
The Company owns all of the outstanding common stock of APS. APS is an 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 owned by APS. APS also generates, sells and delivers electricity to wholesale customers in the western United States. The marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS' Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. APS does not distribute any products.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our competitive electricity generation operations;
* APS Energy Services, which provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States;
* SunCor, a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah; and
* El Dorado, which owns a majority interest in NAC (specializing in spent nuclear fuel technology) and holds miscellaneous small investments, including interests in Arizona community-based ventures.
SUMMARY OF KEY FACTORS AFFECTING OUR FINANCIAL OUTLOOK
We believe the following are among the key factors affecting our financial outlook:
* The following ACC regulatory matters:
* APS' $500 million financing application, which the ACC approved on March 27, 2003;
* the implementation of the ACC-mandated process by which APS must competitively procure energy; and
* APS' general rate case to be filed in 2003.
* Wholesale power market conditions in the western United States.
We discuss each of these, and other factors in detail below in the section entitled "Factors Affecting Our Financial Outlook."
EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT
We have three principal business segments (determined by products, services and the regulatory environment):
* Our regulated electricity segment, which consists of regulated traditional retail and wholesale electricity businesses and related activities and includes electricity transmission, distribution and generation;
* our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services' commodity-related energy services; and
* our real estate segment, which consists of SunCor's real estate development and investment activities.
The following tables summarize net income and segment details for the years ended December 31, 2002, 2001 and 2000 for Pinnacle West and each of our subsidiaries (dollars in millions):
(a) Primarily includes activities related to El Dorado, principally NAC. See Note 22.
(b) Consistent with APS' October 2001 ACC filing, APS entered into agreements with its affiliates to buy power. The agreements reflected a price based on the fully-dispatchable dedication of the Pinnacle West Energy generating assets to APS' Native Load customers. In 2002, Pinnacle West Energy recorded a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4.
(c) APS Energy Services' and El Dorado's net income is primarily reported before income taxes. The income tax expense or benefit for these subsidiaries is recorded at the parent company.
(d) We recorded a $66 million after-tax charge in 2002 for the cumulative effect of a change in accounting for trading activities, for the early adoption of EITF 02-3," Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," as of October 1, 2002. See Note 18.
(e) APS 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 18.
See Note 17 for additional financial information regarding our business segments.
RESULTS OF OPERATIONS
GENERAL
Throughout the following explanations of our results of operations, we refer to "gross margin." With respect to our regulated electricity segment and marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. Our real estate segment gross margin refers to real estate revenues less real estate operations costs of SunCor. Other gross margin refers to other operating revenues less other operating expenses, which includes El Dorado's investment in NAC, which we began consolidating in our financial statements in July 2002 (see Note 22). Other gross margin also includes amounts related to APS Energy Services' energy consulting services.
2002 COMPARED WITH 2001
Our consolidated net income for the year ended December 31, 2002 was $149 million compared with $312 million for the prior year. We recognized a $66 million after-tax charge in 2002 for the cumulative effect of a change in accounting for trading activities for the early adoption of EITF 02-3 on October 1, 2002 (see Note 18). 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 18).
Our income before accounting change for the year ended December 31, 2002 was $215 million compared with $327 million for the prior year. The period-to-period comparison was lower due to:
* lower earnings contributions from our marketing and trading activities, reflecting lower liquidity and lower price volatility in the wholesale power markets in the western United States;
* pretax losses of $59 million related to our investment in NAC;
* a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4, of which $47 million was recorded in operations and maintenance expense and $2 million was recorded in capitalized interest; and
* severance costs of approximately $36 million pretax recorded in the second half of 2002 relating to a voluntary workforce reduction.
The above decreases were partially offset by:
* increased earnings contributions from our regulated electricity activities, reflecting lower replacement power costs for power plant outages, retail customer growth and higher average usage per customer, partially offset by the effects of milder weather, retail electricity price decreases and higher costs for purchased power and gas due to higher hedged gas and power prices; and
* increased earnings contributions from real estate operations, primarily as a result of increased sales activities.
For additional details, see the following discussion.
The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $549 million lower in the year ended December 31, 2002, compared with the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result of lower sales volumes and lower prices ($64 million); * decreased revenues related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes ($455 million); * decreased retail revenues related to milder weather ($60 million); * increased retail revenues related to customer growth and higher average usage, excluding weather effects ($69 million); * decreased retail revenues related to reductions in retail electricity prices ($28 million); and * other miscellaneous factors ($11 million net decrease).
Regulated electricity segment purchased power and fuel costs were $661 million lower in the year ended December 31, 2002, compared with the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of lower sales volumes and lower prices ($64 million); * decreased costs related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes ($460 million); * increased costs related to higher prices for hedged natural gas and purchased power, net of mark-to-market reversals ($14 million); * decreased costs related to the effects of milder weather on retail sales ($33 million); * increased costs related to retail sales growth, excluding weather effects ($31 million); * charges in 2001 related to purchased power contracts with Enron and its affiliates ($13 million net decrease); * decreased replacement power costs for power plant outages due to lower market prices and fewer unplanned outages ($127 million); and * miscellaneous factors ($9 million net decrease).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $325 million lower in the year ended December 31, 2002, compared with the prior year as a result of:
* decreased revenues from generation sales other than Native Load primarily due to lower market prices partially offset by higher sales volumes ($98 million); * lower realized wholesale revenues net of related mark-to-market reversals primarily due to lower prices partially offset by higher volumes ($273 million); * increased revenues from higher competitive retail sales in California by APS Energy Services ($105 million); * 2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates ($8 million increase); * higher revenues related to the adoption of EITF 02-3 ($8 million); and
* lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and lower price volatility, resulting in lower volumes ($75 million).
Marketing and trading segment purchased power and fuel costs were $140 million lower in the year ended December 31, 2002, compared to the prior year as a result of:
* decreased fuel costs related to generation sales other than Native Load primarily because of lower natural gas prices partially offset by higher sales volumes ($32 million); * decreased purchased power costs related to other realized marketing activities in the current period primarily due to lower prices partially offset by higher volumes ($182 million); * increased purchased power costs related to higher competitive retail sales in California by APS Energy Services ($73 million); and * change in mark-to-market fuel costs for future delivery ($1 million increase).
OTHER INCOME STATEMENT ITEMS
The increase in real estate segment gross margin of $16 million was primarily due to increased sales activities.
The decrease in other gross margin of $44 million was primarily due to losses on El Dorado's investment in NAC (see further discussion in Note 22). These losses for 2002 totaled approximately $59 million on a pretax basis and were primarily related to NAC contracts with two customers ($51 million was recorded in other gross margin and $8 million was recorded in other expense). We believe we have reserved our exposure with respect to these contracts in all material respects and, as a result, we consider these charges to be non-recurring.
The increase in operations and maintenance expense of $54 million was due to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4, severance costs of $36 million related to a 2002 voluntary workforce reduction and other costs of $9 million, partially offset by lower costs related to generation reliability, plant outages and maintenance costs of $38 million.
The increase in taxes other than income taxes of $7 million is primarily due to increased property taxes on higher property balances.
Other income decreased $11 million primarily due to an insurance recovery recorded in 2001 related to environmental remediation costs and other costs (see Note 19).
Other expense was comparable with the prior year primarily due to losses recorded related to El Dorado's investment in NAC of approximately $8 million (see further discussion in Note 22), offset by $8 million of lower miscellaneous non-operating costs (see Note 19).
Net interest expense increased $16 million primarily because of higher debt balances related to our generation construction program and lower capitalized interest on our generation construction program due to completion of Redhawk Units 1 and 2 in mid-2002.
2001 COMPARED WITH 2000
Our consolidated net income for the year ended December 31, 2001 was $312 million compared with $302 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 18).
Our income before accounting change for the year ended December 31, 2001 was $327 million compared with $302 million for the prior year. The period-to-period comparison benefited from:
* strong marketing and trading results, including significant benefits recognized in the third quarter of 2001 from structured trading activities; and
* retail customer growth.
The above increases were partially offset by:
* lower earnings contributions from our regulated electricity activities, reflecting higher purchased power and fuel costs, due in part to increased power plant maintenance, generation reliability measures and continuing retail electricity price decreases; and
* 2001 charges related to Enron and its affiliates.
For additional details, see the following discussion.
The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
(a) We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001.
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $23 million higher in the year ended December 31, 2001 compared to the prior year as a result of:
* decreased revenues related to other wholesale sales and miscellaneous revenues as a result of lower sales volumes ($28 million);
* increased retail revenues primarily related to higher sales volumes primarily due to customer growth ($78 million); and * decreased retail revenues related to reductions in retail electricity prices ($27 million).
Regulated electricity segment purchased power and fuel costs were $95 million higher in the year ended December 31, 2001 compared to the prior year as a result of:
* decreased costs related to other wholesale sales as a result of lower volumes ($31 million); * higher replacement power costs primarily due to higher market prices and increased plant outages ($70 million), including costs of $12 million related to a Palo Verde outage extension to replace fuel control element assemblies; * higher costs related to retail sales volumes due to customer growth ($43 million); and * charges related to purchased power contracts with Enron and its affiliates ($13 million).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $233 million higher in the year ended December 31, 2001 compared with the prior year as a result of:
* increased revenues related to generation sales other than Native Load as a result of higher average market prices ($32 million); * increased realized wholesale revenues net of related mark-to-market reversals primarily due to more transactions ($96 million); * decreased prior period mark-to-market value related to trading with Enron and its affiliates ($8 million); and * increased mark-to-market value for future periods primarily as a result of more forward sales volumes ($113 million).
Marketing and trading segment purchased power and fuel costs were $42 million higher in the year ended December 31, 2001 compared to the prior year as a result of:
* increased fuel costs related to generation sales other than Native Load as a result of higher fuel prices ($7 million); and * increased purchased power and fuel costs net of related mark-to-market reversals primarily due to more transactions ($35 million).
OTHER INCOME STATEMENT ITEMS
The decrease in real estate segment profits of $8 million resulted primarily from reduced sales of land and homes by SunCor.
The increase in operations and maintenance expenses of $80 million primarily related to the 2001 generation summer reliability program (the addition of generating capability to enhance reliability for the summer of 2001 ($42 million)) and increased employee benefit costs, plant outage and
maintenance and other costs ($38 million). The comparison reflects Pinnacle West's $10 million provision for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001.
Net other expense increased $4 million primarily because of a change in the market value of El Dorado's investment in a technology-related venture capital partnership in 2000 and other nonoperating costs partially offset by an insurance recovery of environmental remediation costs (see Note 19).
Interest expense decreased by $17 million primarily because of increased capitalized interest resulting from our generation construction plan partially offset with higher interest expense due to higher debt balances.
See "Regulatory Matters - 1999 Settlement Agreement" in Note 3 for a discussion of the 1999 Settlement Agreement under which, among other things, APS agreed to five annual retail electricity price reductions of 1.5%, with the last decrease to take effect July 1, 2003.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS AND RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the year ended December 31, 2002 and estimated capital expenditures for the next three years.
CAPITAL EXPENDITURES (dollars in millions)
Actual Estimated ------ ------------------------ 2002 2003 2004 2005 ---- ---- ---- ---- APS Delivery $369 $273 $275 $329 Generation (a) 132 123 99 164 Other (e) -- 5 5 5 ---- ---- ---- ---- Subtotal 501 401 379 498 Pinnacle West Energy (a) (b) 374 268 31 20 SunCor (c) 72 64 23 20 Other (d) 37 17 13 14 ---- ---- ---- ---- Total $984 $750 $446 $552 ==== ==== ==== ====
(a) As discussed below under "Factors Affecting Our Financial Outlook," as part of its 2003 general rate case, APS intends to seek rate base treatment of certain power plants in Arizona currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3).
(b) See Note 11 for further discussion of Pinnacle West Energy's generation construction program and "Capital Resources and Cash Requirements - Pinnacle West Energy" below. These amounts do not include an expected reimbursement in 2004 by SNWA of about $100 million, assuming SNWA exercises its option to purchase a 25% interest in the Silverhawk project at that time. (c) Consists primarily of capital expenditures for land development and retail and office building construction reflected in the "Change in real estate investments" in the Consolidated Statements of Cash Flows. (d) Primarily related to the parent company and APS Energy Services. (e) The other amounts relate to capital expenditures for our marketing and trading segment. These costs were in the parent company for 2002.
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. In addition, APS began several major transmission projects in 2001. These projects are periodic in nature and are driven by strong regional customer growth. APS expects to spend about $105 million on major transmission projects during the 2003 to 2005 time frame, and these amounts are included in "APS-Delivery" in the table above.
Generation capital expenditures are comprised of various improvements for APS' 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 contains nuclear fuel expenditures of approximately $30 million annually for 2003 to 2005.
Replacement of the steam generators in Palo Verde Unit 2 is presently scheduled for completion during the fall outage of 2003. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. We expect that these generators will be installed in Units 1 and 3 in the 2005 to 2008 time frame. Our portion of steam generator expenditures for Units 1, 2 and 3 is approximately $145 million, which will be spent from 2003 through 2008. In 2003 through 2005, $94 million of the costs are included in the generation capital expenditures table above and would be funded with internally-generated cash or external financings.
CONTRACTUAL OBLIGATIONS
The following table summarizes actual contractual requirements for the year ended December 31, 2002 and estimated contractual commitments for the next five years and thereafter (dollars in millions):
OFF-BALANCE SHEET ARRANGEMENTS
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities." FIN No. 46 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. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003.
In 1986, APS 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 9 for further information about the sale-leaseback transactions. Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to consolidate the Palo Verde SPEs. However, we continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements.
APS is also exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2002, APS would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million.
GUARANTEES
We and certain of our subsidiaries have issued guarantees in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS
Energy Services. We have not recorded any liability on our Consolidated Balance Sheets with respect to these obligations. See Note 23 for additional information regarding guarantees.
CREDIT RATINGS
The ratings of securities of Pinnacle West and APS as of March 28, 2003 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 Pinnacle West's or APS' securities and serve to increase those companies' cost of and access to capital.
Moody's Standard & Poor's Fitch ------- ----------------- ----- PINNACLE WEST Senior unsecured Baa2 BBB- BBB Commercial paper P-2 A-2
APS Senior secured A3 A- A- Senior unsecured Baa1 BBB BBB+ Secured lease obligation bonds Baa2 BBB BBB Commercial paper P-2 A-2
On November 4, 2002, Standard & Poor's affirmed the APS debt ratings in the above chart, but lowered Pinnacle West's senior unsecured debt rating from BBB to BBB- "because of the structural subordination of this debt as compared to the unsecured debt at APS." On that same date, Standard & Poor's lowered APS' corporate credit rating from BBB+ to BBB and affirmed the BBB corporate credit rating of Pinnacle West. Standard & Poor's assigned a stable outlook to the ratings. All of Pinnacle West's and APS' credit ratings remain investment grade. In December 2002, Fitch placed certain of our debt and that of APS on Ratings Watch Negative. The ratings watch affects our senior unsecured debt and commercial paper ratings. It also affects all of APS' debt ratings, with the exception of its commercial paper rating.
On December 31, 2002, Moody's affirmed the ratings set forth above.
DEBT PROVISIONS
Pinnacle West's and APS' significant debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS are in compliance with such covenants and each anticipates it will continue to meet all the significant covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for both the Company and APS. At December 31, 2002, the ratios are approximately 54% and 48% for the parent company and APS, respectively. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for both the Company and APS. The coverages are approximately 4 times for the parent company, 5 times for the APS bank agreements and 15 times for the APS 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.
Neither Pinnacle West's nor APS' financing agreements 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, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
All of Pinnacle West's bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other agreements. All of APS' bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under other agreements. Pinnacle West's and APS' 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.
PINNACLE WEST (PARENT COMPANY)
Our primary cash needs are for dividends to our shareholders; equity infusions into our subsidiaries, primarily Pinnacle West Energy; and interest payments and optional and mandatory repayments of principal on our long-term debt (see the table above for our contractual requirements, including our debt repayment obligations, but excluding optional repayments). On October 23, 2002, our board of directors increased the common stock dividend to an indicated annual rate of $1.70 per share from $1.60 per share, effective with the December 1, 2002 dividend payment. The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2000 through 2002, total dividends from APS were $510 million and total distributions from SunCor were $33 million. For the year ended December 31, 2002, dividends from APS were approximately $170 million and distributions from SunCor were approximately $13 million. We expect SunCor to make cash distributions to the parent company of $80 million to $100 million annually in 2003 through 2005 due to anticipated accelerated asset sales activity.
On December 23, 2002, we issued 6,555,000 shares of common stock, no par value, which resulted in net proceeds of $199 million. See Note 7.
We have financed Pinnacle West Energy's generation construction program premised upon Pinnacle West Energy's receipt of APS' generation assets by the end of 2002. On November 22, 2002, the ACC approved APS' request (Interim Financing Application) to permit APS to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West's short-term debt, subject to certain conditions. As of December 31, 2002, there were no borrowings outstanding under this financing arrangement. On March 27, 2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to
exceed $500 million in the aggregate. See "Factors Affecting our Financial Outlook - Regulatory Matters" and "ACC Applications" in Note 3 for additional information.
In 2002, the parent company issued $215 million in long-term debt and had no repayments of long-term debt (see Note 6).
The parent company's outstanding long and short-term debt was approximately $887 million at December 31, 2002. At December 31, 2002, our commitments totaled $475 million, which were available to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2002, we had about $24 million of commercial paper outstanding and $72 million of short-term borrowings. Our long-term debt including current maturities totaled $791 million at December 31, 2002.
In mid-2003, we will need to refinance approximately $475 million of parent company indebtedness, including a total of $225 million we expect to borrow under an existing credit facility. We expect that this indebtedness will be repaid through funds borrowed by Pinnacle West Energy from APS under the $500 million financing arrangement recently approved by the ACC.
As part of a multi-employer pension plan sponsored by Pinnacle West, we contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. We 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, we contributed $27 million for 2002, $24 million for 2001, $44 million for 2000, $25 million for 1999 and $14 million for 1998. APS and other subsidiaries fund their share of the pension contribution, of which APS represents approximately 90% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. We currently forecast a pension contribution in 2003 of approximately $50 million, all or part of which may be required. If the fund performance continues to decline as a result of a continued decline in equity markets, larger contributions may be required in future years.
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction has resulted in a $200 million reduction in the current income tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return.
APS
APS' capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See "Factors Affecting Our Financial Outlook - Regulatory Matters" below and Note 3 for discussion of the $500 million financing arrangement between APS and Pinnacle West Energy recently approved by the ACC. See "Pinnacle West (Parent Company)" above and Note 3 for discussion of a $125 million financing arrangement between APS and Pinnacle West.
APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid for its dividends to Pinnacle West with cash from operations.
In 2002, APS issued $375 million in long-term debt, refinanced $90 million in long-term debt and redeemed approximately $247 million in long-term debt (see Note 6). On April 7, 2003, APS will redeem $33 million of its first mortgage bonds.
APS' outstanding debt was approximately $2.2 billion at December 31, 2002. At December 31, 2002, APS had 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, 2002, APS had no outstanding commercial paper or bank borrowings.
Although provisions in APS' first mortgage bond indenture, articles of incorporation and ACC financing orders establish maximum amounts of additional first mortgage bonds, debt and preferred stock that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.
PINNACLE WEST ENERGY
The costs of Pinnacle West Energy's construction of generating capacity from 2000 through 2004 are expected to be about $1.4 billion. This does not reflect an expected reimbursement in 2004 by SNWA of about $100 million of Pinnacle West Energy's cumulative capital expenditures in the Silverhawk project, assuming SNWA exercises its option to purchase a 25% interest in the project. Pinnacle West Energy is currently funding its capital requirements through capital infusions from Pinnacle West, which finances those infusions through debt and equity financings and internally-generated cash. See the capital expenditures table above for actual capital expenditures in 2002 and projected capital expenditures for the next three years.
See "Factors Affecting Our Financial Outlook - Regulatory Matters" below and Note 3 for discussion of the $500 million.
OTHER SUBSIDIARIES
During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor's capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures in 2002 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings.
In 2002, SunCor issued $50 million in long-term debt, and redeemed, refinanced or repaid $53 million in long-term debt (see Note 6).
SunCor's outstanding long and short-term debt was approximately $153 million as of December 31, 2002. As of December 31, 2002, SunCor had a $140 million line of credit, under which $126 million of borrowings were outstanding. SunCor's short-term debt was $6 million and other long-term debt, including current maturities, totaled $21 million at December 31, 2002.
We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2003 through 2005 due to anticipated accelerated asset sales activity.
El Dorado funded its cash requirements during the past three years, primarily for NAC in 2002, with cash infused by the parent company and with cash from operations. El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments. El Dorado's long-term debt was approximately $3 million at December 31, 2002 and it had no long-term debt outstanding at December 31, 2001. El Dorado's long-term debt increased primarily due to its consolidation of NAC for financial reporting purposes (see Notes 6 and 22).
APS Energy Services' cash requirements during the past three years were funded with cash infusions from the parent company. APS Energy Services' capital expenditures and other cash requirements are increasingly funded by operations, with some funding from cash infused by Pinnacle West. See the capital expenditures table above regarding APS Energy Services' actual capital expenditures for 2002 and projected capital expenditures for the next three years.
CRITICAL ACCOUNTING POLICIES
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 - Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies.
* Pensions and Other Postretirement Benefit Accounting - Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term.
* Derivative Accounting - Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in other comprehensive income.
* Mark-to-Market Accounting - The market value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.
See the discussion below for further details on our critical accounting policies.
REGULATORY ACCOUNTING
For our 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 obligations to make refunds to customers for previous collections of costs not likely to be incurred.
We are required to discontinue applying SFAS No. 71 when deregulatory legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated. In 1999, we discontinued the application of SFAS No. 71 for APS' generation operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a discussion of the 1999 Settlement Agreement.
In 2002, the ACC directed APS not to transfer its generation assets, as previously required by the 1999 Settlement Agreement (see "Track A Order" in Note 3). Accordingly, we now consider APS generation to be cost-based, rate-regulated and subject to the requirements of SFAS No. 71. The impact of this change was immaterial to our consolidated financial statements.
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 to current period earnings. We had $241 million of regulatory assets included on the Consolidated Balance Sheets at December 31, 2002. See Notes 1 and 3 for more information.
PENSIONS AND OTHER POSTRETIREMENT BENEFIT ACCOUNTING
We sponsor a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for our employees and employees of our subsidiaries. Our reported costs of providing defined pension and other postretirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension and other postretirement benefit costs, for example, are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions we make to the plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension and other postretirement benefit costs. Pension and other postretirement benefit
costs may also be significantly affected by changes in key actuarial assumptions, including the expected long-term rate of return on plan assets and the discount rates used in determining the projected benefit obligation and pension and other postretirement benefit costs.
Pinnacle West's pension and other postretirement plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension and other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and the expected long-term rate of return on plan assets could also increase or decrease recorded pension and other postretirement benefit costs.
We account for our defined benefit pension plans in accordance with SFAS No. 87, "Employers' Accounting for Pensions," which requires amounts recognized in our financial statements to be determined on an actuarial basis. Changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.
The following chart reflects the sensitivities associated with a one percent increase or decrease in certain actuarial assumptions related to our defined benefit pension plans. Each sensitivity below reflects the impact of changing only that assumption. The chart shows the increase (decrease) each change in assumption would have on the 2002 projected benefit obligation, our 2002 reported pension liability on the Consolidated Balance Sheets and our 2002 reported annual pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions).
Increase/(Decrease) ------------------------------------------------------------------- Impact on Projected Impact on Impact on Benefit Pension Pension Actuarial Assumption Obligation Liability Expense ------------------------------------------------------------------- Discount rate: Increase 1% $ (143) $ (107) $ (4) Decrease 1% 177 130 9 Expected long-term rate of return on plan assets: Increase 1% -- -- (4) Decrease 1% -- -- 4
At the end of each year, we determine the discount rate to be used to calculate the present value of plan liabilities. The discount rate is an estimate of the current interest rate at which the pension liabilities could be effectively settled at the end of the year. The discount rate is selected by comparison to current yields on high-quality, long-term bonds. We changed our discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31, 2002.
In 2002, we assumed that the expected long-term rate of return on plan assets would be 10%. However, the plan assets have earned a rate of return substantially less than 10% in the last three years due to sharp declines in the equity markets. For 2003, we decreased our expected long-term rate of return on plan assets to 9%, as a result of continued declines in general equity and bond market returns.
The following chart reflects the sensitivities associated with a one percent increase or decrease in certain actuarial assumptions related to our other postretirement benefit plans. Each sensitivity below reflects the impact of changing only that assumption. The chart shows the increase (decrease) each change in assumption would have on the 2002 accumulated other postretirement benefit obligation and our 2002 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions).
Increase/(Decrease) ---------------------------------------------------------------------- Impact on Accumulated Impact on Other Postretirement Benefit Postretirement Benefit Actuarial Assumption Obligation Expense ---------------------------------------------------------------------- Discount rate: Increase 1% $(38) $ (2) Decrease 1% 43 2 Health care cost trend rate (a): Increase 1% 54 5 Decrease 1% (43) (4) Expected long-term rate of return on plan assets - pretax: Increase 1% -- (1) Decrease 1% -- 1
(a) This assumes a 1% change in the initial and ultimate health care cost trend rate.
The discount rate is selected by comparison to current yields on high-quality, long-term bonds. We changed our discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31, 2002.
In selecting our health care cost trend rate, we consider past performance and forecasts of health care costs. In 2002, we increased our initial health care cost trend rate to 8% from 7% based on an analysis of our actual plan experience. We also assume an ultimate health care cost trend rate of 5% is reached in 2007.
In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. The market value of the plan assets has been affected by sharp declines in the equity markets. For 2003, we decreased our 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 returns.
Pension and other postretirement benefit costs and cash funding requirements may increase in future years without a substantial recovery in the equity markets. Due to the actual investment performance of our pension and other postretirement benefit funds and the changes in the actuarial assumptions discussed above, we expect an increase of approximately $29 million before income taxes in 2003 expense over 2002. See Note 8 for further details about our pension and other postretirement benefit plans.
DERIVATIVE ACCOUNTING
We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged 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.
We examine contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133 scope exception, we account for the contract on an accrual basis with associated revenues and costs recorded at the time the contracted commodities are delivered or received. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard. Most 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.
For contracts that qualify as a derivative and do not meet a SFAS No. 133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. Changes in the fair value of the effective portion of derivative instruments that qualify for cash flow hedge accounting treatment are recognized as either an asset or liability and in common stock equity (as a component of accumulated other comprehensive income (loss)). Gains and losses related to 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 a contract does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period through mark-to-market accounting.
On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the accounting 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. 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 Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See "Other Accounting Matters - Accounting for Derivative and Trading
Activities" below for details on the change in accounting for energy trading contracts. See Note 18 for further discussion on derivative accounting.
MARK-TO-MARKET ACCOUNTING
Under mark-to-market accounting, the purchase or sale of energy commodities is reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as assets and liabilities from risk management and trading activities in the Consolidated 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 shape 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.
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.
A credit valuation adjustment is also recorded to represent 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 "Factors Affecting our Financial Outlook - Market Risks - Commodity Price Risk" below and Note 18 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. To illustrate, as presented in the "Factors Affecting our Financial Outlook - Market Risks - Commodity Price Risk" section below, a 10% increase in the price of trading commodities would result in only a $2 million decrease in pretax income. Our practice is to hedge within timeframes established by the ERMC.
OTHER ACCOUNTING MATTERS
ACCOUNTING FOR DERIVATIVE AND TRADING ACTIVITIES
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. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 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. 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 Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133.
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 Consolidated 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, results of operations or cash flows.
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. See Notes 1 and 18 for further information on accounting for derivatives under SFAS No. 133.
ASSET RETIREMENT OBLIGATIONS
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 will be 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. 143.
STOCK-BASED COMPENSATION
In the third quarter of 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." We recorded approximately $500,000 in stock option expense before income taxes in our Consolidated Statements of Income for 2002. See Notes 1 and 16 for further information on the impacts of adopting the fair value method provided in SFAS No. 123.
VARIABLE INTEREST ENTITIES
See "Liquidity and Capital Resources - Off-Balance Sheet Arrangements" and Note 20 for discussion of VIEs.
OTHER
See Note 2 for discussion of other new accounting standards that are not expected to have a material impact on the Company.
FACTORS AFFECTING OUR FINANCIAL OUTLOOK
REGULATORY MATTERS
GENERAL
On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy on or before that date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed APS not to transfer its generation assets to Pinnacle West Energy.
1999 SETTLEMENT AGREEMENT
The 1999 Settlement Agreement has affected, and will affect, our results of operations. As part of the 1999 Settlement Agreement, APS agreed to reduce retail electricity prices for standard-offer, full-service customers with loads less than three megawatts in a series of annual decreases of 1.5% on July 1, 1999 through July 1, 2003, for a total of 7.5%. For customers with loads three megawatts or greater, standard-offer rates were reduced in annual increments totaling 5% in the years 1999 through 2002.
The 1999 Settlement Agreement also removed, as a regulatory disallowance, $234 million before income taxes ($183 million net present value) from ongoing regulatory cash flows. APS recorded this regulatory disallowance as a net reduction of regulatory assets and reported it as a $140 million after-tax extraordinary charge on the 1999 Consolidated Statement of Income. As discussed under "APS General Rate Case" below, APS intends to seek recovery of this $234 million write-off in its next general rate case.
Prior to the 1999 Settlement Agreement, the ACC accelerated the amortization of substantially all of APS' regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):
1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $ 86 $ 18 $686
See Note 3 for additional information regarding the 1999 Settlement Agreement.
APS FINANCING APPLICATION
On September 16, 2002, APS filed an application with the ACC requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or a combination of both, not to exceed $500 million in the aggregate. In its application, APS stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing that we provided to fund the construction of Pinnacle West Energy generation assets or from effectively competing in the wholesale markets. On March 27, 2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. See "ACC Applications" in Note 3 for further discussion of the approval and related conditions.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order. See "Track A Order" in Note 3.
COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things, established a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order, which documented the decision made by the ACC at its open meeting on February 27, 2003 addressing this requirement. Under the ACC's Track B Order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS will be required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets." The order recognizes APS' right to reject any bids that are unreasonable, uneconomical or unreliable.
APS expects to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply APS' electricity requirements. See "Track B Order" in Note 3 for additional information.
APS GENERAL RATE CASE
As required by the 1999 Settlement Agreement, on or before June 30, 2003, APS will file a general rate case with the ACC. In this rate case, APS will update its cost of service and rate design. In addition, APS expects to seek:
* rate base treatment of certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3);
* recovery of the $234 million pretax asset write-off recorded by APS as part of the 1999 Settlement Agreement ($140 million extraordinary charge recorded on the 1999 Consolidated Statement of Income); and
* recovery of costs incurred by APS in preparation for the previously required transfer of generation assets to Pinnacle West Energy.
We assume that the ACC will make a decision in this general rate case by the end of 2004.
WHOLESALE POWER MARKET CONDITIONS
The marketing and trading division, which we moved to APS in early 2003 for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting APS' transfer of generating assets to Pinnacle West Energy, focuses primarily on managing APS' purchased power and fuel risks in connection with its costs of 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. Earnings contributions from our marketing and trading division were lower in 2002 compared to 2001 due to weak wholesale power market conditions in the western United States, which
included a lack of market liquidity, fewer creditworthy counterparties, lower wholesale market prices and resulting decreases in sales volumes. Our 2003 earnings will be affected by the strength (or weakness) of the wholesale power market.
GENERATION CONSTRUCTION
See "Capital Needs and Resources - Pinnacle West Energy" above and Note 11 for information regarding Pinnacle West Energy's generation construction program. The planned additional generation is expected to increase revenues, fuel expenses, operating expenses and financing costs.
FACTORS AFFECTING OPERATING REVENUES
GENERAL Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale bulk 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. Competitive sales of energy and energy-related products and services are made by APS Energy Services in western states that have opened to competitive supply.
CUSTOMER GROWTH Customer growth in APS' service territory averaged about 3.6% a year for the three years 2000 through 2002; we currently expect customer growth to average about 3.5% per year from 2003 to 2005. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in 2003 through 2005, before the retail effects of weather variations. The customer growth and sales growth referred to in this paragraph applies to energy delivery customers. As previously noted, under the 1999 Settlement Agreement, we agreed to retail electricity price reductions of 1.5% annually through July 1, 2003 (see Note 3).
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
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.
OPERATIONS AND MAINTENANCE EXPENSES Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors. In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $36 million before taxes in voluntary severance costs in the second half of 2002. In addition, we are expecting to produce annual operating expense savings of approximately $30 million beginning in 2003 as a result of this workforce reduction.
DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property, changes in regulatory asset amortization and our generation construction program. West Phoenix Unit 4 was placed in service in June 2001. Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in
July 2002. West Phoenix Unit 5 is expected to be on line in mid-2003 and Silverhawk is expected to be in service in mid-2004 (see Note 11 for further details about our generation construction program). The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):
1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $ 86 $ 18 $ 686
PROPERTY TAXES Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.7% of assessed value for 2002 and 9.3% for 2001. We expect property taxes to increase primarily due to our generation construction program and our additions to existing facilities.
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 recording capitalized interest on a project when it is placed in commercial operation. As noted above, we have placed new power plants in commercial operation in 2001 and 2002 and we expect to bring additional plants on-line in 2003 and 2004. We are continuing to evaluate our generation construction program. Interest expense is affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company's future liquidity needs.
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 in Arizona. Although some very limited retail competition existed in APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory.
SUBSIDIARIES In the case of SunCor, we are undertaking an aggressive effort to accelerate asset sales activities to approximately double SunCor's annual earnings in 2003 to 2005 compared to the $19 million in earnings recorded in 2002. A portion of these sales could be reported as discontinued operations on the Consolidated Statements of Income.
The annual earnings contribution from APS Energy Services is expected to be positive over the next several years due primarily to a number of retail electricity contracts in California. APS Energy Services' had pretax earnings of $28 million in 2002.
El Dorado's historical results are not necessarily indicative of future performance for El Dorado. El Dorado's strategies focus on prudently realizing the value of its existing investments.
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.
MARKET RISKS
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.
INTEREST RATE AND EQUITY RISK
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 pension plan (see Note 8) and nuclear decommissioning trust fund (see Note 12). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan and nuclear decommissioning fund also have risks associated with changing market values of equity investments. Pension (APS only) and nuclear decommissioning costs are recovered in regulated electricity prices. See "Critical Accounting Policies - Pension and Other Postretirement Benefit Accounting" for a sensitivity analysis on the long-term rate of return on plan assets.
The tables below present contractual balances of our consolidated long-term debt and commercial paper at the expected maturity dates as well as the fair value of those instruments on December 31, 2002 and 2001. The interest rates presented in the tables below represent the weighted-average interest rates for the years ended December 31, 2002 and 2001.
Expected Maturity/Principal Repayment December 31, 2002 (dollars in thousands)
Expected Maturity/Principal Repayment December 31, 2001 (dollars in thousands)
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 derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. The ERMC, consisting of senior officers, 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 enter into derivative transactions to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged 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.
Prior to October 1, 2002, we accounted for our energy trading contracts at fair value in accordance with EITF 98-10. On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 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. 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 Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See Note 18 for details on the change in accounting for energy trading contracts and further discussion regarding derivative accounting.
Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Consolidated Balance Sheets. For non-trading derivative instruments that qualify for hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of accumulated 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.
Derivatives associated with trading activities are adjusted to fair value through income. 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. Most 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.
Our assets and liabilities from risk management and trading activities are presented in two categories consistent with our business segments:
* System - our regulated electricity business segment, which consists of non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements; and
* Marketing and Trading - our non-regulated, competitive business segment, which includes both non-trading and trading derivative instruments.
The following tables show the changes in mark-to-market of our system and marketing and trading derivative positions in 2002 and 2001 (dollars in millions):
Marketing and System Trading ------ ------- Mark-to-market of net positions at December 31, 2001 $(107) $ 138 Cumulative effect adjustment due to adoption of EITF 02-3 -- (109) Change in mark-to-market gains for future period deliveries (13) 47 Changes in cash flow hedges recorded in OCI 57 16 Ineffective portion of changes in fair value recorded in earnings 11 -- Mark-to-market losses/(gains) realized during the year 3 (38) Change in valuation techniques -- 3 ----- ----- Mark-to-market of net positions at December 31, 2002 $ (49) $ 57 ===== =====
Marketing and System Trading ------ ------- Mark-to-market of net positions at December 31, 2000 $ -- $ 12 Cumulative effect adjustment due to adoption of SFAS No. 133 95 -- Change in mark-to-market (losses)/gains for future period deliveries (12) 203 Changes in cash flow hedges recorded in OCI (166) -- Ineffective portion of changes in fair value recorded in earnings (6) -- Mark-to-market gains realized during the year (18) (77) Change in valuation techniques -- -- ----- ----- Mark-to-market of net positions at December 31, 2001 $(107) $ 138 ===== =====
The Company no longer reports non-derivative energy contracts or physical inventories at fair value. Since July 1, 2002, the Company has not recognized a dealer profit or unrealized gain or loss at the inception of a derivative unless the fair value of that instrument (in its entirety) is evidenced by quoted market prices or current market transactions. Prior to the change in our policy, we recorded net gains at inception of $10 million in 2002 and $3 million in 2001. These amounts included a reasonable marketing margin.
The tables below show the maturities of our system and marketing and trading derivative positions at December 31, 2002 by the type of valuation that is performed to calculate the fair value of the contract (dollars in millions). See "Critical Accounting Policies - Mark-to-Market Accounting" above for more discussion on our valuation methods.
SYSTEM
MARKETING AND TRADING
The table below shows the impact hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in millions).
(a) These contracts are 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. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 33% of our $181 million of risk management and trading assets as of December 31, 2002. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated 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 "Critical Accounting Policies - Mark-to-Market Accounting" above for a discussion of our credit valuation adjustment policy.
RISK FACTORS
Exhibit 99.3, which is hereby incorporated by reference, contains a discussion of risk factors affecting the Company.
FORWARD-LOOKING STATEMENTS
The above discussion 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 laws. 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 the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition; the outcome of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including price caps and other market constraints imposed by the FERC; regional economic and market conditions, including the California energy situation and 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; weather variations affecting local and regional customer energy usage; the effect of conservation programs on energy usage; power plant performance; the successful completion of our generation construction program; regulatory issues associated with generation construction, such as permitting and licensing; our ability to compete successfully outside traditional regulated markets (including the wholesale market); our ability to manage our marketing and trading activities and the use of derivative contracts in our business; technological developments in the electric industry; the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommissioning trust funds; the strength of the real estate market in SunCor's market areas, which include Arizona, New Mexico and Utah; and other uncertainties, all of which are difficult to predict and many of which are beyond our control.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See "Factors Affecting Our Financial Outlook - Market Risks" in Item 7 for a discussion of quantitative and qualitative disclosures about market risk.
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ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
Independent Auditors' Report................................................. 74 Consolidated Statements of Income for 2002, 2001 and 2000.................... 75 Consolidated Balance Sheets as of December 31, 2002 and 2001................. 76 Consolidated Statements of Cash Flows for 2002, 2001 and 2000................ 78 Consolidated Statements of Changes in Common Stock Equity for 2002, 2001 and 2000.................................................... 79 Notes to Consolidated Financial Statements................................... 80 Financial Statement Schedule for 2002, 2001 and 2000 Schedule II - Valuation and Qualifying Accounts for 2002, 2001 and 2000...................................................................138
See Note 13 for the selected quarterly financial data required to be presented in this Item.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Pinnacle West Capital Corporation Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries ("the Corporation") as of December 31, 2002 and 2001 and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index. These financial statements and financial statement schedule are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the 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 consolidated financial statements present fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries at December 31, 2002 and 2001 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 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 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 18 to the consolidated financial statements, in 2002 Pinnacle West Capital Corporation changed its method of accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."
As discussed in Note 18 to the consolidated financial statements, in 2001 Pinnacle West Capital Corporation 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 February 3, 2003 (March 4, 14, 26 and 27, 2003 as to Note 24)
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF INCOME (dollars and shares in thousands, except per share amounts)
See Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands)
See Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands)
See Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)
See Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY For the Years Ended December 31, 2002, 2001 and 2000 (dollars in thousands)
See Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION AND NATURE OF OPERATIONS
The consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). Significant intercompany accounts and transactions between the consolidated companies have been eliminated.
APS is an 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 half of the Phoenix metropolitan area. Electricity is delivered through a distribution system owned by APS. APS also generates, sells and delivers electricity to wholesale customers in the western United States. In early 2003, the marketing and trading division of Pinnacle West was moved to APS for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting the previously required transfer of APS' generating assets to Pinnacle West Energy. See Note 3 for a discussion of the Track A Order. Pinnacle West Energy, which was formed in 1999, is the subsidiary through which we conduct our competitive generation operations. APS Energy Services was formed in 1998 and provides competitive commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah. El Dorado is an investment firm, and its principal investment is in NAC, which is a company specializing in spent nuclear fuel technology.
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
We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We examine contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," scope exception, we account for the contract on an accrual basis with associated revenues and costs recorded at the time the contracted commodities are delivered or received. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard. Most 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.
For contracts that qualify as a derivative and do not meet a SFAS No. 133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. Changes in the fair value of the effective portion of derivative instruments that qualify for cash flow hedge accounting treatment are recognized as either an asset or liability and in common stock equity (as a component of accumulated other comprehensive income (loss)). Gains and losses related to 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 a contract does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period through mark-to-market accounting.
On October 1, 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. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 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. 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 Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See Note 18 for more details on the change in accounting for energy trading contracts and for further discussion on derivative accounting.
MARK-TO-MARKET ACCOUNTING
Under mark-to-market accounting, the purchase or sale of energy commodities is reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as assets and liabilities from risk management and trading activities in the Consolidated 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
A credit valuation adjustment is also recorded to represent 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 18 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
APS is 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 obligations to make refunds to customers for previous collections of costs not likely to be incurred.
We are required to discontinue applying SFAS No. 71 when deregulatory legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated. In 1999, we discontinued the application of SFAS No. 71 for APS' generation operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a discussion of the 1999 Settlement Agreement.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As a result, we tested the generation assets for impairment and determined the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, a regulatory disallowance removed $234 million pretax ($183 million net present value) from ongoing regulatory cash flows and was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extraordinary charge on the 1999 Consolidated Statement of Income.
In 2002, the ACC directed APS not to transfer its generation assets, as previously required by the 1999 Settlement Agreement (see "Track A Order" in Note 3). Accordingly, we now consider APS generation to be cost-based, rate-regulated and subject to the requirements of SFAS No. 71. The impact of this change was immaterial to our consolidated financial statements.
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.
Prior to the 1999 Settlement Agreement, the ACC accelerated the amortization of substantially all of APS' regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):
1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $ 86 $ 18 $ 686
Regulatory assets are reported as deferred debits on the Consolidated Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the following (dollars in millions):
December 31, -------------- 2002 2001 ---- ---- Remaining balance recoverable under the 1999 Settlement Agreement (a) $104 $219 Spent nuclear fuel storage (Note 11) 46 43 Electric industry restructuring transition costs (Note 3) 40 34 Other 51 46 ---- ---- Total regulatory assets $241 $342 ==== ====
(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).
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory liabilities are included in deferred credits and other on the Consolidated Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the following (dollars in millions):
December 31, -------------- 2002 2001 ---- ---- Deferred gains on utility property $ 20 $ 20 Other 6 7 ---- ---- Total regulatory liabilities $ 26 $ 27 ==== ====
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 June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense in the Consolidated 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; * 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, plus removal costs less salvage realized, to accumulated depreciation. See Note 2 for information on a new accounting standard that impacts accounting for removal costs.
We record depreciation on utility property 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, 2002 were as follows:
* Fossil plant - 22 years; * Nuclear plant - 22 years; * Transmission - 34 years; * Distribution - 28 years; and * Other utility property - 9 years.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years 2000 through 2002 the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 20%. The weighted-average rate was 3.35% for 2002 and 3.40% for 2001 and 2000. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.
EL DORADO INVESTMENTS
El Dorado accounts for its investments using the consolidated (if controlled), equity (if significant influence) and cost (less than 20% ownership) methods. Beginning in the third quarter of 2002, El Dorado began consolidating the operations of NAC. See Note 22 for further details on El Dorado's investment in NAC.
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. Capitalized interest does not represent current cash earnings. The rate used to calculate capitalized interest was a composite rate of 4.80% for 2002, 6.13% for 2001 and 6.62% for 2000.
ELECTRIC REVENUES
Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of energy 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 energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Other than revenues and purchased power costs related to energy trading activities, revenues are reported on a gross basis in our Consolidated 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 Consolidated Statements of Income on a net basis.
SUNCOR
SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed. A single method of recognizing income is applied to all sales transactions within an entire home, land or commercial development project. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERCENTAGE OF COMPLETION - NAC
Certain NAC contract revenues are accounted for under the percentage-of-completion method. Revenues are recognized based upon total costs incurred to date compared to total costs expected to be incurred for each contract. Revisions in contract revenue and cost estimates are reflected in the accounting period when known. Provisions are made for the full amounts of anticipated losses in the periods in which they are first determined. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and income, and are recognized in the period in which revisions are determined. Profit incentives are included in revenues when their realization is reasonably assured.
Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs and depreciation costs. General and administrative costs are charged to expense as incurred.
CASH AND CASH EQUIVALENTS
For purposes of the Consolidated Statements of Cash Flows, we consider all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.
NUCLEAR FUEL
APS charges 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. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
APS also charges 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 APS $0.001 per kWh of nuclear generation. See Note 11 for information about spent nuclear fuel disposal and Note 12 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." We file our federal income tax return on a consolidated basis and we file our 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 each subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between the aforementioned allocations and the consolidated (and unitary) income tax liability is attributed to the parent company.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
REACQUIRED DEBT COSTS
For debt related to the regulated portion of APS' business, APS amortizes those gains and losses incurred upon early retirement over the original remaining life of the debt. In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate 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 Consolidated Statements of Income.
REAL ESTATE INVESTMENTS
Real estate investments primarily include SunCor's land, home inventory and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting.
STOCK-BASED COMPENSATION
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 method allowed in Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees."
The following chart compares our net income, stock compensation expense and earnings per share 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 2002 (dollars in thousands, except per share amounts):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2002 2001 2000 --------- --------- --------- Net Income: As reported $ 149,408 $ 312,166 $ 302,332 Pro forma (fair value method) 148,013 309,874 301,102 Stock compensation expense (net of tax): As reported 300 -- -- Pro forma (fair value method) 1,395 2,292 1,230
Earnings per share - basic: As reported $ 1.76 $ 3.68 $ 3.57 Pro forma (fair value method) $ 1.74 $ 3.66 $ 3.55 Earnings per share - diluted: As reported $ 1.76 $ 3.68 $ 3.56 Pro forma (fair value method) $ 1.74 $ 3.65 $ 3.55
In order to calculate the fair value of the 2002 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:
2002 2001 2000 ------ ------ ------ Risk-free interest rate 4.17% 4.08% 5.81% Dividend yield 4.17% 3.70% 3.48% Volatility 22.59% 27.66% 32.00% Expected life (months) 60 60 60
See Note 16 for further discussion about our stock compensation plans.
2. ACCOUNTING MATTERS
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 will be 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 fossil 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 net regulatory liability of $40 million for our asset retirement obligations
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. 143.
In November 2002, the EITF reached a consensus on EITF 00-21, "Revenue Arrangements with Multiple Deliverables." EITF 00-21 addresses certain aspects of the accounting by a vendor for arrangements under which it will perform multiple revenue-generating activities. EITF 00-21 specifically addresses how to determine whether an arrangement has identifiable, separable revenue-generating activities. EITF 00-21 does not address when the criteria for revenue recognition are met or provide guidance on the appropriate revenue recognition convention. EITF 00-21 is effective for revenue arrangements entered into after July 1, 2003. We are currently evaluating the impacts of this new guidance, but we do not believe it will have a material impact on our financial statements.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and the accounting and reporting provisions for the disposal of a segment of a business. This standard did not impact our financial statements at adoption. For each of the years 2002, 2001 and 2000, items requiring discontinued operations reporting were immaterial.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements Nos. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which, among other things, supersedes previous guidance for reporting gains and losses from extinguishment of debt. This standard did not impact our financial statements at adoption.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The guidance will be applied to exit or disposal activities initiated after December 31, 2002. This standard did not impact our financial statements at adoption.
In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), "Accounting for Certain Costs Related to Property, Plant, and Equipment." This proposed SOP would create a project timeline framework for capitalizing costs related to property, plant and equipment construction. It would require that property, plant and equipment assets be accounted for at the component level and require administrative and general costs incurred in support of capital projects to be expensed in the current period. In November 2002, the AICPA announced they would no longer issue general purpose SOPs. The work they have performed on the proposed SOP will be transitioned to the FASB staff. In February 2003, the FASB determined that the AICPA should continue their deliberations on certain aspects of the proposed SOP. We are waiting for further guidance from the FASB staff and the AICPA on the timing of the final guidance.
See the following Notes for other new accounting standards:
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* Notes 1 and 16 for a new accounting standard (SFAS No. 148) related to stock-based compensation;
* Note 18 for a new EITF issue (EITF 02-3) related to accounting for energy trading contracts;
* Note 20 for a new interpretation (FIN No. 46) related to VIEs;
* Note 21 for a new standard (SFAS No. 142) related to goodwill and intangible assets; and
* Note 23 for a new interpretation (FIN No. 45) on guarantees.
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy on or before that date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed APS not to transfer its generation assets to Pinnacle West Energy. See "Track A Order" below.
On September 16, 2002, APS filed an application with the ACC requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or a combination of both, not to exceed $500 million in the aggregate. In its application, APS stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing provided by the Company to fund the construction of Pinnacle West Energy generation assets or from effectively competing in the wholesale markets. On March 27, 2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. See "ACC Applications" below.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things, established a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order which documented the decision made by the ACC at its open meeting on February 27, 2003, addressing this requirement. Under the order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS will be required to solicit competitive bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets." The order recognizes APS' right to reject any bids that are unreasonable, uneconomical or unreliable.
APS expects to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply APS' electricity requirements. See "Track B Order" below.
These regulatory developments and legal challenges to the Rules have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. These matters are discussed in more detail below.
1999 SETTLEMENT AGREEMENT
The following are the major provisions of the 1999 Settlement Agreement, as approved by the ACC:
* APS has reduced, and will reduce, 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; and approximately $28 million ($17 million after taxes), effective July 1, 2002. The final price reduction is to be implemented July 1, 2003. For 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 APS 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 will be 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
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
limited circumstances. Neither the ACC nor APS will be 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 APS' cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.
* APS 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.
* APS' 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. APS opened its 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 in Arizona. Although some very limited retail competition existed in APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory.
* Prior to the 1999 Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). APS will not be allowed to recover $183 million net present value (in 1999 dollars) of the above amounts. The 1999 Settlement Agreement provides that APS 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 due to sales volume variances.
* APS will form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its competitive electric assets and services at book value as of the date of transfer, and will complete the transfers no later than December 31, 2002. APS will be allowed to defer and later collect, beginning July 1, 2004, 67% of its costs to accomplish the required transfer of generation assets to an affiliate. However, as noted above and discussed in greater detail below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing an order preventing APS from transferring its generation assets.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RETAIL ELECTRIC COMPETITION RULES
The Rules approved by the ACC included the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by the ACC, including APS.
* Effective January 1, 2001, retail access became available to all APS 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, APS received a waiver to allow transfer of its competitive electric assets and services to affiliates no later than December 31, 2002. However, as noted above and discussed in greater detail below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require APS to transfer its 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, APS 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 APS' property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
appealed the ruling to the Arizona Court of Appeals, as a result of which the Superior Court's ruling is automatically stayed pending further judicial review. That appeal is still pending. In a similar appeal concerning the issuance of competitive telecommunications CC&N's, the Arizona Court of Appeals invalidated rates for competitive carriers due to the ACC's failure to establish a fair value rate base for such carriers. That decision was upheld by the Arizona Supreme Court.
PROVIDER OF LAST RESORT OBLIGATION
Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is the "provider of last resort" for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in APS' cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS' current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power.
GENERIC DOCKET
In January 2002, the ACC opened a "generic" docket to "determine if changed circumstances require the [ACC] to take another look at electric restructuring in Arizona." In February 2002, the ACC docket relating to APS' October 2001 filing was consolidated with several other pending ACC dockets, including the generic docket. On May 2, 2002, the ACC issued a procedural order stating that hearings would begin on June 17, 2002 on various issues, including APS' planned divestiture of generation assets to Pinnacle West Energy and associated market and affiliate issues. The procedural order also stated that consideration of the competitive bidding process required by the Rules would proceed concurrently with the Track A issues.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order, which documents decisions made by the ACC at an open meeting on August 27, 2002. The major provisions of the Track A Order include, among other things:
Provisions related to the reversal of the generation asset transfer requirement:
* The ACC reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets either to an unrelated third party or to a separate corporate affiliate; and
* the ACC unilaterally modified the 1999 Settlement Agreement, which authorized APS' transfer of its generating assets, and directed APS to cancel its activities to transfer its generation assets to Pinnacle West Energy.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Provisions related to the wholesale competitive energy procurement process (Track B issues):
* The ACC stayed indefinitely the requirement of the Rules that APS acquire 100% of its energy needs for its standard offer customers from the competitive market, with at least 50% obtained through a competitive bid process;
* the ACC established a requirement that APS competitively procure, at a minimum, any required power that it cannot produce from its existing assets in accordance with the ultimate outcome of the Track B proceedings;
* the ACC directed the parties to develop a competitive procurement ("bidding") process that can begin by March 1, 2003; and
* the ACC stated that "the [Pinnacle West Energy] generating assets that APS may acquire from [Pinnacle West Energy] shall not be counted as APS assets in determining the amount, timing and manner of the competitive solicitation" for Track B purposes, thereby bifurcating the regulatory treatment of the existing APS assets and the Pinnacle West Energy assets.
On November 15, 2002, APS 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, APS and the ACC staff agreed to principles for resolving certain issues raised by APS in its appeals of the Track A Order. APS and the ACC are the only parties to the Track A Order appeals. The major provisions of this document include, among other things, the following:
* The parties agreed that it would be appropriate for the ACC to consider the following matters in APS' upcoming general rate case, anticipated to be filed before June 30, 2003:
* the generating assets to be included in APS' rate base, including the question of whether certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and Saguaro Unit 3) should be included in APS' rate base;
* the appropriate treatment of the $234 million pretax asset write-off agreed to by APS as part of a 1999 settlement agreement approved by the ACC among APS and various parties related to the implementation of retail competition in Arizona; and
* the appropriate treatment of costs incurred by APS 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 the Financing Application, with appropriate conditions, APS' 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On February 21, 2003, a Notice of Claim was filed with the ACC and the Arizona Attorney General on behalf of APS, Pinnacle West and Pinnacle West Energy to preserve their and our rights relating to the Track A Order.
TRACK B ORDER
The ACC Staff has conducted workshops on the Track B issues with various parties to determine and define the appropriate process to be used for competitive power procurement. On September 10, 2002, the ACC issued an order that, among other things, established a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order which documented the decision made by the ACC at its open meeting on February 27, 2003 addressing this requirement. The order adopted most of the provisions of an ACC ALJ's recommendation that was issued on January 30, 2003. Under the ACC's Track B Order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS will be required to solicit competitive bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets."
The order recognizes APS' right to reject any bids that are unreasonable, uneconomical or unreliable. The Track B procurement process will involve the ACC Staff and an independent monitor. The Track B Order also contains requirements relating to standards of conduct between APS and any affiliate of APS that may participate in the competitive solicitation, requires that APS treat bidders in a non-discriminatory manner and requires APS to file a protocol regarding short-term and emergency procurements. The order permits the provision 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 confidential APS bidding information that is not available to other bidders. The order directs APS 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, APS will prepare a report evaluating environmental issues relating to the procurement and a series of workshops on environmental risk management will be commenced thereafter.
APS expects to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply APS' electricity requirements.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ACC APPLICATIONS
On September 16, 2002, APS filed a Financing Application requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or a combination of both, not to exceed $500 million in the aggregate. The loan and/or the guarantee would be used to refinance debt incurred to fund the construction of Pinnacle West Energy generation assets.
The Financing Application addressed, among other things, the following matters:
* APS noted that its April 19, 2002 filing with the ACC had sought unification of "[Pinnacle West Energy] Assets" (West Phoenix Units 4 and 5, Redhawk Units 1 and 2, and Saguaro Unit 3) and APS generation assets under a common financial and regulatory regime. APS further noted that the Track A Order's language regarding the treatment of the Pinnacle West Energy Assets for Track B purposes appears to postpone a decision regarding the inclusion of the Pinnacle West Energy Assets in APS' rate base, thereby effectively precluding the consolidation of the Pinnacle West Energy Assets at APS under a common financial and regulatory regime at the present time.
* APS stated that it did not intend or desire to foreclose the possibility that it would acquire all or part of the Pinnacle West Energy Assets or that it may propose that the Pinnacle West Energy Assets be included in APS' rate base or afforded cost-of-service regulatory treatment to the extent the Pinnacle West Energy Assets are used by APS customers. APS stated that these issues would be appropriate topics in APS' 2003 general rate case and noted that the Track A Order specifically stated that the ACC would not pre-judge the eventual rate treatment of the Pinnacle West Energy Assets.
* APS stated that the Track A Order's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing provided by the Company to fund the construction of the Pinnacle West Energy Assets or from effectively competing in the wholesale markets. APS noted that Pinnacle West Energy had previously received investment-grade credit ratings contingent upon its receipt of APS generation assets and that the Company's credit ratings could be adversely affected if Pinnacle West Energy is unable to finance its capital requirements. On November 4, 2002, Standard & Poor's lowered the Company's senior unsecured debt rating from "BBB" to "BBB-."
* APS stated that the amount of the requested loan and/or guarantee is APS' present estimate of the amount of credit support necessary through APS to restore Pinnacle West Energy and the Company to their credit status prior to the ACC's issuance of the Track A Order. APS further stated that if the requested amount proves to be inadequate, APS reserves the right to submit a second financing application seeking additional credit support.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 27, 2003, the ACC approved the Financing Application, subject to the following principal conditions:
* any debt issued by APS pursuant to the order must be unsecured;
* APS will be permitted to loan up to $500 million to Pinnacle West Energy (the "APS Loan"), guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate;
* the APS Loan must be callable and secured by certain Pinnacle West Energy assets;
* the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on APS 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 APS' cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;
* APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its 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 APS and its affiliates will be 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
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, with an expected commercial operation date in mid-2003, 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 if SNWA exercises its existing purchase option to do so.
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.
In mid-2003, the Company will need to refinance approximately $475 million of parent company indebtedness. We expect that this indebtedness will be repaid through funds borrowed by Pinnacle West Energy from APS under the APS Loan.
On November 22, 2002, the ACC approved APS' request to permit APS to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West's short-term debt, subject to certain conditions. See Note 5.
FEDERAL
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 has 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, and the FERC has announced that it will issue an additional white paper on the proposed Standard Market Design in April 2003. We are reviewing the proposed rulemaking and 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.
GENERAL
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 in Arizona. Although some very limited retail competition existed in APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory. 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. INCOME TAXES
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.
APS has recorded a regulatory asset related to income taxes on its 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. APS amortizes this amount as the differences reverse. In accordance with ACC settlement agreements, APS is 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 our Consolidated Statements of Income.
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction has 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 our 2001 federal consolidated income tax return.
The components of income tax expense for income before accounting change are (dollars in thousands):
Year Ended December 31, ----------------------------------------- 2002 2001 2000 --------- --------- --------- Current: Federal $ (43,492) $ 184,893 $ 189,779 State (14,732) 45,845 42,306 --------- --------- --------- Total current (58,224) 230,738 232,085
Deferred 196,324 (17,203) (37,885) --------- --------- --------- Total income tax expense $ 138,100 $ 213,535 $ 194,200 ========= ========= =========
The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, ---------------------------------- 2002 2001 2000 --------- --------- --------- Federal income tax expense at 35% statutory rate $ 123,639 $ 189,316 $ 173,786 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 16,478 23,353 19,848 Other (2,017) 866 566 --------- --------- --------- Income tax expense $ 138,100 $ 213,535 $ 194,200 ========= ========= =========
The following table sets forth the net deferred income tax liability recognized on the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands):
December 31, ------------------------- 2002 2001 ----------- ----------- Current asset/(liability) $ 4,094 $ (3,244) Long term liability (1,209,074) (1,064,993) ----------- ----------- Accumulated deferred income taxes - net $(1,204,980) $(1,068,237) =========== ===========
The components of the net deferred income tax liability were as follows (dollars in thousands):
December 31, ------------------------- 2002 2001 ----------- ----------- DEFERRED TAX ASSETS Pension liability $ 72,835 $ 19,422 Risk management and trading activities 43,542 73,043 Deferred gain on Palo Verde Unit 2 sale-leaseback 23,562 25,374 Other 99,054 90,580 ----------- ----------- Total deferred tax assets 238,993 208,419 ----------- ----------- DEFERRED TAX LIABILITIES Plant-related (1,316,636) (1,069,207) Regulatory asset for income taxes (80,635) (121,757) Risk management and trading activities (46,702) (85,692) ----------- ----------- Total deferred tax liabilities (1,443,973) (1,276,656) ----------- ----------- Accumulated deferred income taxes - net $(1,204,980) $(1,068,237) =========== ===========
5. LINES OF CREDIT AND SHORT-TERM BORROWINGS
APS had committed lines of credit with various banks of $250 million at December 31, 2002 and 2001, which were available either to support the issuance of commercial paper or to be used for bank borrowings. These lines of credit
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
mature in June 2003. The commitment fees at December 31, 2002 and 2001 for these lines of credit were 0.09% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2002 and 2001.
APS had no commercial paper borrowings outstanding at December 31, 2002 and $171 million at December 31, 2001. The weighted average interest rate on commercial paper borrowings was 2.47% for the year ended December 31, 2002 and 4.72% for the year ended December 31, 2001. By Arizona statute, APS' short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC.
Pinnacle West had committed lines of credit of $475 million at December 31, 2002 and $250 million at December 31, 2001, which were available either to support the issuance of commercial paper or to be used for bank borrowings. Outstanding amounts at December 31, 2002 were $72 million, and there were no short-term bank borrowings outstanding at December 31, 2001. The commitment fees ranged from 0.10% to 0.15% in 2002 and 2001. Pinnacle West commercial paper borrowings outstanding were $24 million at December 31, 2002 and $235 million at December 31, 2001. The weighted average interest rate on commercial paper borrowings was 2.06% for the year ended December 31, 2002 and 3.50% for the year ended December 31, 2001.
On July 31, 2002, Pinnacle West completed a $300 million bank credit facility, which was subsequently reduced to $225 million by applying $75 million of the proceeds from the equity offering in December 2002 (see Note 7). The borrowings are LIBOR-based, can be drawn upon as needed and are expected to be used primarily to fund Pinnacle West Energy capital requirements. The facility matures in July 2003. The majority of these borrowings were used to fund Pinnacle West Energy capital expenditures. At December 31, 2002, Pinnacle West had borrowed $67 million under the credit facility.
On November 22, 2002, the ACC approved APS' request to permit APS to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West's short-term debt, subject to certain conditions. This interim loan matures in December 2003. There have been no borrowings on this line.
SunCor had revolving lines of credit totaling $140 million at December 31, 2002 and 2001. The commitment fees were 0.125% in 2002 and 2001. SunCor had $126 million outstanding at December 31, 2002 and $128 million outstanding at December 31, 2001. The balance is included in long-term debt on the Consolidated Balance Sheets (see Note 6). SunCor had short-term loans in the amount of $6 million at December 31, 2002 and no short-term loans outstanding at December 31, 2001.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. LONG-TERM DEBT
Borrowings under the APS mortgage bond indenture are secured by substantially all utility plant. APS also has unsecured debt. SunCor's debt is collateralized by interests in certain real property and Pinnacle West's debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2002 and 2001 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) This schedule does not reflect the timing of redemptions that may occur prior to maturity. (b) On March 15, 2002, APS redeemed at maturity $125 million of its First Mortgage Bonds, 8.125% Series due 2002. (c) On April 15, 2002, APS redeemed $122 million of its First Mortgage Bonds, 8.75% Series due 2024. (d) The weighted-average rate was 1.94% at December 31, 2002 and 2.55% at December 31, 2001. Changes in short-term interest rates would affect the costs associated with this debt. (e) In November 2001, these bonds were converted to a one-year fixed rate of 3.30%. These bonds were previously adjustable rate and, from January 1, 2001 until October 31, 2001, the weighted average rate was 2.72%. (f) 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 APS 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. (g) APS currently has 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 (f) above. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity and redemption provisions as the senior notes. APS' payments of principal, premium and/or interest on the senior notes satisfy its 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 APS repays all of its 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. (h) The weighted-average rate was 3.75% at December 31, 2002 and was 5.31% at December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 2% or prime plus 0.5%. (i) Multiple notes primarily with variable interest rates based mostly on the lenders' prime plus 1.75% and lenders' prime plus .25%. (j) Includes three series of notes: $25 million at 6.87% due in 2003, $300 million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of December 31, 2002. (k) The weighted average rate was 2.85% at December 31, 2002 and was 4.65% at December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 0.98%.
Pinnacle West's and APS' significant debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS are in compliance with such covenants and each anticipates it will continue to meet all the significant covenant requirement levels. 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.
Neither Pinnacle West's nor APS' financing agreements 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, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All of Pinnacle West's bank agreements contain "cross-default" provisions under which a default by it or APS in a specified amount under another agreement would result in a default and the potential acceleration of payment under the agreements. All of APS' bank agreements contain cross-default provisions under which a default by APS in a specified amount under another agreement would result in a default and the potential acceleration of payment under the agreements. Pinnacle West's and APS' credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's financial condition or financial prospects.
The following is a list of payments due on total long-term debt and capitalized lease requirements through 2007:
* $281 million in 2003; * $552 million in 2004; * $405 million in 2005; * $390 million in 2006; * $3 million in 2007; and * $1,539 million, thereafter.
APS' 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. APS may pay dividends on its 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, 2002, the amount "available" under the mortgage would have allowed APS to pay approximately $3 billion of dividends compared to APS' current annual common stock dividends of $170 million.
7. COMMON STOCK AND TREASURY STOCK
Our common stock and treasury stock activity during each of the three years 2002, 2001 and 2000 is as follows (dollars in thousands, except shares):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLANS
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 our subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance pension plan for all new employees in place of the defined benefit plan and, effective April 1, 2003, the new plan will be 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 plan covers officers of the company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay. We fund the qualified plan by contributing at least the minimum amount required under IRS regulations but no more than the maximum tax-deductible amount. The assets in the qualified plan at December 31, 2002 were mostly domestic common stocks and bonds and real estate.
Total pension expense, including administrative costs and after consideration of amounts capitalized or billed to electric plant participants, was:
* $14 million in 2002; * $11 million in 2001; and
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* $6 million in 2000.
The following table shows the components of net periodic pension cost before consideration of amounts capitalized or billed to electric plant participants for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):
The following table shows a reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets as of December 31, 2002 and 2001 (dollars in thousands):
2002 2001 ---------- --------- Funded status - pension plan assets less than projected benefit obligation $ (348,770) $(166,773) Unrecognized net transition asset (10,327) (13,554) Unrecognized prior service cost 23,148 26,170 Unrecognized net actuarial losses 293,223 108,422 ---------- --------- Accrued pension benefit liability recognized in the Consolidated Balance Sheets $ (42,726) $ (45,735) ========== =========
The following table sets forth the defined benefit pension plans' change in projected benefit obligation for the plan years 2002 and 2001 (dollars in thousands):
2002 2001 ---------- --------- Projected pension benefit obligation at beginning of year $ 931,646 $ 840,485 Service cost 30,333 27,640 Interest cost 71,242 66,549 Benefit payments (35,230) (33,282) Actuarial losses 71,696 21,632 Plan amendments (110) 8,622 ---------- --------- Projected pension benefit obligation at end of year $1,069,577 $ 931,646 ========== =========
The following table sets forth the qualified defined benefit pension plans' change in the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2002 2001 --------- --------- Fair value of pension plan assets at beginning of year $ 764,873 $ 775,196 Actual loss on plan assets (36,966) (22,876) Employer contributions 26,600 44,200 Benefit payments (33,700) (31,647) --------- --------- Fair value of pension plan assets at end of year $ 720,807 $ 764,873 ========= =========
The following table sets forth the defined benefit pension plans' amounts recognized in the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands):
2002 2001 --------- --------- Accrued pension benefit liability $ (42,726) $ (45,735) Additional minimum liability (141,155) (3,297) Intangible asset 23,148 1,697 Accumulated other comprehensive loss - pretax 118,007 1,600
The following table shows the accumulated benefit obligation in relation to the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands):
2002 2001 ---------- --------- Projected benefit obligation $1,069,577 $ 931,646 Accumulated benefit obligation 904,687 752,230 Fair value of plan assets 720,807 764,873
The following are weighted-average assumptions as of December 31, 2002 and 2001:
2002 2001 ---------- --------- Discount rate 6.75% 7.50% Rate of increase in compensation levels 4.00% 4.00% Expected long-term rate of return on assets 9.00% 10.00%
EMPLOYEE SAVINGS PLAN BENEFITS
Pinnacle West sponsors a defined contribution savings plan for the employees of Pinnacle West and our subsidiaries. In a defined contribution savings plan, the benefits a participant will receive result from regular contributions they make to a participant account. Under this plan, we make matching contributions in Pinnacle West stock to participant accounts. After a five-year vesting period, participants have a choice to change the employer
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
contribution match to other investments. At December 31, 2002, approximately 25% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately $5 million for 2002 and 2001 and $4 million for 2000.
OTHER POSTRETIREMENT BENEFITS
Pinnacle West sponsors other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide 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. We retain the right to change or eliminate these benefits.
Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds. The other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, was:
* $12 million for 2002; * $6 million for 2001; and * $3 million for 2000.
The following table shows the components of net periodic other postretirement benefit costs before consideration of amounts capitalized or billed to electric plant participants for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):
The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the other postretirement benefit plan's change in accumulated postretirement benefit obligation for the plan years 2002 and 2001 (dollars in thousands):
(a) The plan was amended January 1, 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 other postretirement benefit plan's change in the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands):
2002 2001 --------- --------- Fair value of other postretirement benefit plan assets at beginning of year $ 237,810 $ 249,154 Actual loss on plan assets (27,802) (12,550) Employer contributions 23,600 11,400 Benefit payments (10,134) (10,194) --------- --------- Fair value of other postretirement benefit plan assets at end of year $ 223,474 $ 237,810 ========= =========
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following are weighted-average assumptions as of December 31, 2002 and 2001:
2002 2001 ------- ------- Discount rate 6.75% 7.50% Expected long-term rate of return on assets - pretax 9.00% 10.00% Expected long-term rate of return on assets - after tax 7.84% 8.71% Initial health care cost trend rate - under age 65 8.00% 7.00% Initial health care cost trend rate - age 65 and over 8.00% 7.00% Ultimate health care cost trend rate 5.00% 5.00% Year ultimate health care trend rate is reached 2007 2006
The following table shows the effect of a 1% increase or decrease in the initial and ultimate health care expense and cost trend rate (dollars in millions):
SEVERANCE CHARGES
In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $36 million before taxes in voluntary severance costs in 2002. No further charges are expected.
9. LEASES
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being 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 20 for a discussion of VIEs, including the SPEs involved in the Palo Verde sale-leaseback transactions.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Consolidated Statements of Income was $62 million in 2002, $56 million in 2001 and $58 million in 2000.
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, APS is 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 Consolidated Statements of Income. The balance of this regulatory asset at December 31, 2002 was $14 million.
Estimated future minimum lease payments for our operating leases are approximately as follows (dollars in millions):
Year ------------------ 2003 $ 70 2004 66 2005 64 2006 63 2007 63 Thereafter 478 ----- Total future lease commitments $ 804 =====
10. JOINTLY-OWNED FACILITIES
APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS' interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2002. APS' share of operating and maintaining these facilities is included in the Consolidated Statements of Income in operations and maintenance expense.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
11. COMMITMENTS AND CONTINGENCIES
ENRON
We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. This amount is comprised of a $15 million reserve for the Company's net exposure to Enron and its affiliates and additional expenses of $6 million primarily related to 2002 power contracts with Enron that were canceled. These charges take into consideration our rights of set-off with respect to the Enron related contractual obligations. The APS portion of the write-off was $13 million. 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 APS 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 Consolidated Balance Sheets.
PALO VERDE NUCLEAR GENERATING STATION
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
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
before 2010 and 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 filed damages actions against the DOE in the Court of Federal Claims.
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.
APS has existing fuel storage pools at Palo Verde and is in the process of completing construction of a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, APS believes 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, APS is currently shipping low-level waste to off-site facilities. APS currently believes 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.
APS currently estimates it will incur $115 million (in 2002 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2002, APS had spent $2 million and recorded accumulated spent nuclear fuel amortization of $44 million and a regulatory asset of $46 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date.
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 $200 million ($300 million effective January 1, 2003) 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, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per incident. Based on APS' interest in the three Palo Verde units, APS' maximum potential assessment per incident for all three units is approximately $77 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. APS has 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
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
PURCHASED POWER AND FUEL COMMITMENTS
APS and Pinnacle West are parties to various purchased power and fuel contracts with terms expiring from 2003 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $173 million in 2003; $82 million in 2004; $28 million in 2005; $31 million in 2006; $17 million in 2007 and $162 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 APS has for the supply of its coal and nuclear fuel supply have take-or-pay provisions. The current take-or-pay nuclear fuel contracts expire in 2003 and had not been renewed as of December 31, 2002. The current take-or-pay coal contracts have terms that expire in 2007.
The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions):
Estimated Years Ending December 31, -------------------------------------------- 2003 2004 2005 2006 2007 ---- ---- ---- ---- ---- Coal $ 43 $ 44 $ 9 $ 9 $ 9 Nuclear Fuel 22 -- -- -- -- ---- ---- ---- ---- ---- Total take-or-pay commitments (a) $ 65 $ 44 $ 9 $ 9 $ 9 ==== ==== ==== ==== ====
(a) Total take-or-pay commitments are approximately $136 million. The total net present value of these commitments is approximately $119 million.
COAL MINE RECLAMATION OBLIGATIONS
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. Our coal mine reclamation obligation is about $59 million at December 31, 2002 and is included in deferred credits-other in the Consolidated 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, APS is 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 Consolidated Statements of Income.
CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST
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. This order calls for a hearing, with findings of fact due to the FERC after the ISO and PX provide necessary historical data. The FERC directed
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
an ALJ to make findings of fact with respect to: (1) the mitigated price in each hour of the refund period; (2) the amount of refunds owed by each supplier according to the methodology established in the order; and (3) the amount currently owed to each supplier (with separate quantities due from each entity) by the CAISO, the California Power Exchange, the investor-owned utilities and the State of California.
APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. On December 12, 2002, the ALJ issued Proposed Findings of Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great majority of the proposed findings, revising only the calculation of natural gas prices for the final determination of mitigated prices in the California markets. Sellers who may actually have paid more for natural gas than the proxy prices adopted by the FERC have 40 days in which to submit necessary data to the FERC, after which a technical conference will be held. Finalization of refund amounts is expected in mid-2003. APS does not anticipate material changes in its exposure and still believes, subject to the finalization of the revised proxy prices, that it will be entitled to a net refund.
On November 20, 2002, the FERC reopened discovery in these proceedings pursuant to instructions of the United States Court of Appeals for the Ninth Circuit, that the FERC permit parties to offer additional evidence of potential market manipulation for the period January 1, 2000 through June 20, 2001. Parties have submitted additional evidence and proposed findings, which the FERC continues to consider.
The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC required that the record establish the volume of the transactions, the identification of the net sellers and net buyers, the price and terms and conditions of the sales contracts and the extent of potential refunds. On September 24, 2001, an ALJ concluded that prices in the Pacific Northwest during the period December 25, 2000 through June 20, 2001 were the result of a number of factors in addition to price signals from the California markets, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ ultimately concluded that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. The FERC is currently reviewing the ALJ's report and recommendations.
On December 19, 2002, the FERC opened a new discovery period to permit the parties to offer additional evidence for the period January 1, 2000 through June 20, 2001. Additional evidence has been submitted and a FERC decision on the newly submitted evidence is expected soon. Based on public comments from the FERC, it is anticipated that this case will be sent back to the ALJ for further proceedings on spot market and balance of month transactions.
Although the FERC has not yet made a final ruling in the Pacific Northwest matter nor 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 26, 2003, 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 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. The report also recommended that the FERC issue an order to show cause why these transactions did not violate the ISO tariff, with potential disgorgement of any unjust profits. Although APS has not yet had an opportunity to review the transactions at issue, it believes that it was not engaged in any such improper transactions. Based on the information available, it also appears that such transactions would not have a material adverse impact on our financial position, results of operations or liquidity.
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.
We are closely monitoring developments in the California energy market and the potential impact of these developments on us and our subsidiaries. Based on our evaluations, we previously reserved $10 million before income taxes for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001. Our evaluations took into consideration our range of exposure of approximately zero to $38 million before income taxes and review of likely recovery rates in bankruptcy situations.
In the second quarter of 2002, PG&E filed its Modified Second Amended Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization. Both plans generally indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstanding, undisputed debts. As a result of these developments, the probable range of our total exposure now is approximately zero to $27 million before income taxes, and our best estimate of the probable loss is now approximately $6 million before income taxes. Consequently, we reversed $4 million of the $10 million reserve in the second quarter of 2002. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us, our subsidiaries or the regional energy market in general.
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 ISO markets, including APS, attempting
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit.
APS was also named in a lawsuit regarding wholesale contracts in California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United States District Court in and for the District of Northern California, Case No. C02-2855 EMC. The complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market. 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 APS 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 preliminary motions are being filed and we cannot currently predict the outcome of this matter. The "United States Justice Foundation" is suing numerous wholesale energy contract suppliers to California, including us, as well as the California Department of Water Resources, based upon an alleged conflict of interest arising from the activities of a consultant for Edison International who also negotiated long-term contracts for the California Department of Water Resources. MCCLINTOCK, ET AL. V. YUDHRAJA, Superior Court in and for the County of Los Angeles, Case No. GC 029447. The California Attorney General has indicated that an investigation by his office did not find evidence of improper conduct by the consultant. We believe the claims against APS and us in the lawsuits mentioned in this paragraph are without merit and will have no material adverse impact on our financial position, results of operations or liquidity.
POWER SERVICE AGREEMENT
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised APS that it believes APS overcharged Citizens by over $50 million under a power service agreement. APS believes its 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, based on its review, "if Citizens filed a complaint with FERC, it probably would lose the central issue in the contract interpretation dispute." APS and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, the Company and Citizens entered into a power sale agreement under which the Company 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.
CONSTRUCTION PROGRAM
Consolidated capital expenditures in 2003 are estimated to be (dollars in millions):
APS $ 401 Pinnacle West Energy 268 SunCor 64 Other (primarily APS Energy Services and Pinnacle West) 17 ----- Total $ 750 =====
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PINNACLE WEST ENERGY'S GENERATION CONSTRUCTION
Pinnacle West Energy's generation construction plan is as follows:
* A 650 MW combined cycle expansion of the West Phoenix Power Plant in Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation in June 2001. Construction has begun on the 530 MW West Phoenix Unit 5, with commercial operation expected to begin in mid-2003.
* The Redhawk Power Plant, two 530 MW combined cycle units, near Palo Verde. Commercial operation began in July 2002. Based on an analysis of the financial situation of the Company and the market as a whole, among other things, Pinnacle West has cancelled plans to construct the additional two 530 MW combined cycle units, Redhawk Units 3 and 4. As a result we recorded a pretax charge of approximately $49 million in December 2002.
* The construction of an 80 MW simple-cycle power plant at Saguaro in Southern Arizona. Commercial operation began in July 2002.
* Development of the 570 MW Silverhawk combined-cycle plant 20 miles north of Las Vegas, Nevada. Construction of the plant began in August 2002, with an expected commercial operation date of mid-2004. Pinnacle West Energy has signed an agreement with Las Vegas-based SNWA under which SNWA has an option to purchase a 25% interest in the project for approximately $100 million.
* A Pinnacle West Energy affiliate is exploring the possibility of creating an underground natural gas storage facility on Company-owned land west of Phoenix. An analysis to determine the feasibility of the project is in progress.
LITIGATION
We are party to various 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 ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our consolidated financial statements, results of operations or liquidity.
12. NUCLEAR DECOMMISSIONING COSTS
APS recorded $11 million for nuclear decommissioning expense in each of the years 2002, 2001 and 2000. APS estimates it will cost approximately $1.8 billion ($528 million in 2002 dollars) to decommission its share of the three Palo Verde units. The majority of decommissioning costs are expected to be incurred over a 14-year period beginning in 2024. APS charges decommissioning costs to expense over each unit's operating license term and APS includes them in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are recovered in rates.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS' current estimates are based on a 2001 site-specific study for Palo Verde that assumes the prompt removal/dismantlement method of decommissioning. An independent consultant prepared this study. APS is required by the ACC to update the study every three years.
To fund the costs APS expects to incur to decommission the plant, APS established external decommissioning trusts in accordance with NRC regulations and ACC orders. APS invests the trust funds primarily in fixed income securities and domestic stock and classifies them as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation in accordance with industry practice. The following table shows the cost and fair value of our nuclear decommissioning trust fund assets, which were reported in investments and other assets on the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in millions):
2002 2001 ----- ----- Trust fund assets - at cost: Fixed income securities $ 113 $ 103 Domestic stock 68 61 ----- ----- Total $ 181 $ 164 ===== =====
Trust fund assets - fair value: Fixed income securities $ 117 $ 106 Domestic stock 77 96 ----- ----- Total $ 194 $ 202 ===== =====
See Note 2 for information on a new accounting standard on accounting for certain liabilities related to closure or removal of long-lived assets.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Consolidated quarterly financial information for 2002 and 2001 is as follows:
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) The fourth quarter of 2002 included pretax losses of $38 million related to our investment in NAC (see Note 22), a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of approximately $11 million.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(b) Electric revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations. We have reclassified certain operating revenues to conform to the current presentation of netting energy trading contracts (see Note 18). (c) NAC financial statements were fully consolidated starting in third quarter 2002 (see Note 22).
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
We believe that the carrying amounts of our cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 2002 and 2001 due to their short maturities.
We hold investments in debt and equity securities for purposes other than trading. The December 31, 2002 and 2001 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount.
On December 31, 2002, the carrying value of our long-term debt (excluding capitalized lease obligations) was $3.15 billion, with an estimated fair value of $3.25 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $2.80 billion on December 31, 2001, with an estimated fair value of $2.82 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
15. EARNINGS PER SHARE
The following table presents earnings per weighted average common share outstanding for the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000 -------- -------- -------- Basic earnings per share: Income before accounting change $ 2.53 $ 3.86 $ 3.57 Cumulative effect of change in accounting (0.77) (0.18) -- -------- -------- -------- Earnings per share-basic $ 1.76 $ 3.68 $ 3.57 ======== ======== ======== Diluted earnings per share: Income before accounting change $ 2.53 $ 3.85 $ 3.56 Cumulative effect of change in accounting (0.77) (0.17) -- -------- -------- -------- Earnings per share-diluted $ 1.76 $ 3.68 $ 3.56 ======== ======== ========
Dilutive stock options increased average common shares outstanding by 60,975 shares in 2002, 212,491 shares in 2001 and 202,738 shares in 2000. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 84,963,921 shares in 2002, 84,930,140 shares in 2001 and 84,935,282 shares in 2000.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Options to purchase 1,629,958 shares of common stock were outstanding at December 31, 2002 but were not included in the computation of diluted earnings per share because the options' exercise price was greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 212,562 at December 31, 2001 and 517,614 at December 31, 2000.
16. STOCK-BASED COMPENSATION
Pinnacle West offers stock-based compensation plans for officers and key employees of our company and our subsidiaries.
In May 2002, 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. The Company 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 option 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 provides for the granting of new options (which may be non-qualified stock options or incentive stock options) of up to 3.5 million shares at a price per option not less than the fair market value on the date the option is granted. The 1985 plan includes outstanding options but no new options will be granted from the 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 provides for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.
In the third quarter of 2002, we 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 $500,000 in stock option expense before income taxes in our Consolidated Statements of Income 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Total stock-based compensation expense, including stock option expense, was $5 million in 2002, $3 million in 2001 and $2 million in 2000.
The following table is a summary of the status of our stock option plans as of December 31, 2002, 2001 and 2000 and changes during the years ending on those dates:
(a) Beginning 2002, we recorded compensation expense related to stock options under SFAS No. 123 (see above discussion).
The following table summarizes information about our stock options at December 31, 2002:
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2002, 2001 and 2000:
(a) Shares are based on estimated ownership of Pinnacle West common stock.
17. BUSINESS SEGMENTS
We have three principal business segments (determined by products, services and the regulatory environment):
* our regulated electricity segment, which consists of regulated traditional retail and wholesale electricity businesses and related activities, and includes electricity transmission, distribution and generation; * our marketing and trading segment, which consists of our competitive business activities, including wholesale marketing and trading and APS Energy Services' commodity-related energy services; and * our real estate segment, which consists of SunCor's real estate development and investment activities.
The amounts in our other segment include activity principally related to NAC in 2002 (see Note 22), as well as the parent company and other subsidiaries. Financial data for the years ended December 31, 2002, 2001 and 2000 by business segments is provided as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. DERIVATIVE AND TRADING ACCOUNTING
We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged 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). 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. See Note 1 for further discussion on our derivative instrument accounting policy.
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), 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In December 2001, the FASB issued revised guidance on the accounting for electricity contracts with option characteristics and the accounting for contracts that combine a forward contract and a purchased option contract. The effective date for the revised guidance was April 1, 2002. The impact of this guidance was immaterial to our financial statements.
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. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 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. 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 Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be 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 Consolidated 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 accumulated 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.
Derivatives associated with trading activities are adjusted to fair value through income. 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. Most 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.
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. Conversely, all non-trading contracts and derivatives are to be reported gross in the income statement. Previous guidance under EITF 98-10 permitted non-financially 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 Consolidated 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, results of operations or cash flows.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our assets and liabilities from risk management and trading activities are presented in two categories consistent with our business segments:
* System - our regulated electricity business segment, which consists of non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements; and
* Marketing and Trading - our non-regulated, competitive business segment, which includes both non-trading and trading derivative instruments.
The changes in derivative fair value included in the Consolidated Statements of Income for the years ended December 31, 2002 and 2001 are comprised of the following (dollars in thousands):
2002 2001 -------- -------- Gains/(losses) on the ineffective portion of derivatives qualifying for hedge accounting (a) $ 11,198 $ (6,056) Losses from the discontinuance of cash flow hedges (8,820) (4,683) Losses from non-hedge derivatives (4,324) (7,157) Prior period mark-to-market losses realized upon delivery of commodities 8,005 25,948 -------- -------- Total pretax gain $ 6,059 $ 8,052 ======== ========
(a) Time value component of options excluded from assessment of hedge effectiveness.
As of December 31, 2002, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately seven years. During the twelve months ending December 31, 2003, we estimate that a net loss of $26 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.
The following table summarizes our assets and liabilities from risk management and trading activities related to system and marketing and trading at December 31, 2002 and 2001 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CREDIT RISK
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 33% of our $181 million of risk management and trading assets as of December 31, 2002. We use a risk management process to assess and monitor the financial exposure of those and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated 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. Credit valuation adjustments
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are established representing our estimated credit losses on our overall exposure to counterparties. See "Mark-to-Market Accounting" in Note 1 for a discussion of our credit valuation adjustment policy.
19. OTHER INCOME AND OTHER EXPENSE
The following table provides detail of other income and other expense for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):
Year Ended December 31, ------------------------------------ 2002 2001 2000 -------- -------- -------- Other income: Environmental insurance recovery $ -- $ 12,349 $ -- Equity earnings - net -- -- 6,882 Interest income 4,410 6,763 8,291 SunCor joint venture earnings 7,471 3,687 3,208 Miscellaneous 3,223 3,617 3,451 -------- -------- -------- Total other income $ 15,104 $ 26,416 $ 21,832 ======== ======== ======== Other expense: Equity losses - net (a) $(10,439) $ (5,126) $ -- Non-operating costs - SunCor -- (7,000) -- Non-operating costs (b) (19,430) (16,807) (16,044) Miscellaneous (3,786) (4,644) (9,285) -------- -------- -------- Total other expense $(33,655) $(33,577) $(25,329) ======== ======== ========
(a) Primarily related to El Dorado's investment losses in NAC prior to consolidation in the third quarter of 2002 (see Note 22).
(b) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and environmental compliance).
20. VARIABLE INTEREST ENTITIES
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities." FIN No. 46 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. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003.
In 1986, APS 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 9 for further information about the sale-leaseback transactions. Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to
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consolidate the Palo Verde SPEs. However, we continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements.
APS is also exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2002, APS would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million.
21. INTANGIBLE ASSETS
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible Assets." This statement addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, "Intangible Assets." We have no goodwill recorded and have separately disclosed other intangible assets on our Consolidated Balance Sheets. The intangible assets continue to be amortized over their finite useful lives. Thus, there was no impact on our financial position as a result of the adoption of SFAS No. 142. The Company's gross intangible assets (which are primarily software) were $214 million at December 31, 2002 and $175 million at December 31, 2001. The related accumulated amortization was $104 million at December 31, 2002 and $88 million at December 31, 2001. Amortization expense was $21 million in 2002, $22 million in 2001 and $20 million in 2000. Estimated amortization expense on existing intangible assets over the next five years is $25 million in 2003, $24 million in 2004, $23 million in 2005, $21 million in 2006 and $15 million in 2007.
22. EL DORADO'S INVESTMENT IN NAC
Through our unregulated wholly-owned subsidiary, El Dorado, we own a majority interest in NAC, a company that develops, markets and contracts for the manufacture of cask designs for spent nuclear fuel storage and transportation. Prior to the third quarter of 2002, our investment in NAC was accounted for under the equity method and our share of NAC's earnings and losses was recorded in other income or expense in our Consolidated Statements of Income. Beginning in the third quarter of 2002, we fully consolidated NAC's financial statements after acquiring a controlling interest in NAC as a result of increased voting representation on NAC's Board of Directors. During the second and third quarters of 2002, we recorded cumulative losses of approximately $21 million before tax ($13 million after tax, $0.15 per share) related to NAC, primarily as a result of expected losses under contracts with two customers, including a contract between NAC and Maine Yankee Atomic Power Company (Maine Yankee).
On January 15, 2003, Maine Yankee notified NAC of its intention to terminate its contract with NAC. We recorded additional NAC losses of approximately $38 million before tax ($23 million after tax, or $0.27 per share) in the fourth quarter of 2002, the substantial majority of which relate to the termination of the Maine Yankee contract. As a result, in 2002, we recorded NAC losses of approximately $59 million before tax ($35 million after tax, or $0.42 per share).
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NAC LITIGATION On March 4, 2003, Maine Yankee Atomic Power Co. filed suit against Pinnacle West, NAC and a surety company in federal court in Portland, Maine. MAINE YANKEE ATOMIC POWER COMPANY V. UNITED STATES FIRE INSURANCE COMPANY, Civil Action Docket No. 03-58-PC, United States District Court, District of Maine. The lawsuit alleges that NAC failed to meet its contractual obligations with respect to certain of NAC's activities relating to the decommissioning of the Maine Yankee nuclear power plant. The lawsuit was filed a few weeks after NAC initiated arbitration against Maine Yankee with respect to matters relating to the same contract. The lawsuit seeks recovery under a parental guarantee signed by Pinnacle West relating to certain of NAC's contractual obligations and under performance and payment bonds issued by the surety which are guaranteed (at least in part) by Pinnacle West. Maine Yankee also alleges damages in excess of $1 million. We are currently evaluating the allegations of the lawsuit and expect to vigorously defend our position.
23. 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 are effective for the year ended December 31, 2002. The initial recognition and measurement provisions of FIN No. 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002.
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction program, transmission service guarantees for West Phoenix Units 4 and 5 and long-term service agreement guarantees for new power plants. Our credit support instruments enable APS Energy Services to provide commodity energy and energy-related products and enable El Dorado to support the activities of NAC. SunCor has a debt guarantee on behalf of an affiliated joint venture. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West's guarantees on behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2002 are as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 2002, we had entered into approximately $42 million of letters of credit which support various construction agreements. These letters of credit expire in 2003 and 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.
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2002, approximately $258 million of letters of credit were outstanding to support existing pollution control bonds of approximately $253 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 2003. APS has also entered into approximately $115 million of letters of credit to support certain equity lessors in the Palo Verde sale-leaseback transactions (see Note 9 for further details on the Palo Verde sale-leaseback transactions). These letters of credit expire in 2005. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements and approximately $5 million of letters of credit related to workers' compensation expiring in 2003. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
In conjunction with our financing agreements, including our sale-leaseback transactions, we generally provide indemnifications relating to liabilities arising from or related to the agreements, except with certain limited exceptions depending on the particular agreement. APS has also 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 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.
PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
24. SUBSEQUENT EVENTS
See "ACC Applications" in Note 3 for information regarding the ACC's approval on March 27, 2003 of a $500 million financing arrangement between APS and Pinnacle West Energy and "Track B Order" in Note 3 for information regarding the ACC order issued on March 14, 2003, mandating a process by which APS must competitively procure energy.
See "California Energy Issues and Refunds in the Pacific Northwest" in Note 11 for information regarding the FERC's adoption on March 26, 2003 of an ALJ's proposed findings, and issuance on March 26, 2003 of a Final Report on Price Manipulation in Western Markets.
See Note 22 for information related to the March 4, 2003 NAC litigation.
PINNACLE WEST CAPITAL CORPORATION SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(a) Represents pro-rata allocations for sale of land. (b) Contract losses related to NAC.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" and to "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 21, 2003 (the "2003 Proxy Statement") and to the Supplemental Item --- "Executive Officers of the Registrant" in Part I of this report.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to "The Board and its Committees - How are Directors Compensated?"; "Performance Graph"; and "Executive Compensation" in the 2003 Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Election of Directors - How many shares of Pinnacle West stock are owned by management and large shareholders?" in the 2003 Proxy Statement.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth information as of December 31, 2002 with respect to our compensation plans and individual compensation arrangements under which our equity securities were authorized for issuance to directors, officers, employees, consultants and certain other persons and entities in exchange for the provision to us of goods or services.
EQUITY COMPENSATION PLANS APPROVED BY SECURITY HOLDERS
The Company has four equity compensation plans that were approved by its shareholders: the Pinnacle West Capital Corporation Stock Option and Incentive Plan, under which no new options may be granted; the Pinnacle West Capital Corporation Directors Stock Option Plan under which no new options may be granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan; and the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan. See Note 16 for additional information regarding these plans.
EQUITY COMPENSATION PLANS NOT APPROVED BY SECURITY HOLDERS
The Company has one equity compensation plan, the Pinnacle West Capital Corporation 2000 Director Equity Plan (the "2000 Plan"), for which the approval of shareholders was not required.
NUMBER OF SHARES SUBJECT TO THE 2000 PLAN. The total number of shares of the Company's common stock granted under the 2000 Plan may not exceed 200,000. In the case of a significant corporate event, such as a reorganization, merger or consolidation, the 2000 Plan provides for adjustment of the above limit, the number of shares to be awarded automatically to eligible non-employee directors, the number of shares of the Company's common stock non-employee directors are required to own to receive an annual grant of common stock and options granted under the 2000 Plan.
ELIGIBILITY FOR PARTICIPATION. Only non-employee directors may participate in the 2000 Plan. A non-employee director is an individual who is a director of the Company but who is not also an employee of the Company or any of its subsidiaries.
TERMS OF AWARDS. The 2000 Plan provides for: (1) annual grants of common stock to eligible non-employee directors, (2) discretionary grants of common stock to eligible non-employee directors and (3) grants of nonqualified stock options to eligible non-employee directors.
ANNUAL GRANTS OF STOCK
Each individual who is a non-employee director as of July 1 of a calendar year, and who meets requirements of ownership of the Company's common stock set forth below, will receive 900 shares of the Company's common stock for such calendar year. In the first calendar year in which a non-employee director is eligible to participate in the 2000 Plan, he or she must own at least 900 shares of the Company's common stock as of December 31 of the same calendar year to receive a grant of 900 shares of the Company's common stock. If the non-employee director owns 900 shares of common stock as of June 30, he or she will receive a grant of 900 shares of common stock as of July 1 of the same calendar year. If the non-employee director does not own 900 shares of the Company's common stock as of June 30, but acquires the necessary shares on or before December 31 of the same year, he or she will receive a grant of 900 shares of common stock within a reasonable time after the Company verifies that the requisite number of shares has been acquired. In each subsequent year, the number of shares of the Company's common stock the non-employee director must own to receive a grant of 900 shares of common stock will increase by 900 shares, until reaching a maximum of 4,500 shares. In each of the subsequent years, the non-employee director must own the requisite number of shares of the Company's common stock as of June 30 of the relevant calendar year.
DISCRETIONARY GRANTS OF STOCK
The Human Resources Committee of the Board of Directors, excluding those members who are not "Non-Employee Directors" under SEC Rule 16b-3(b)(3) (the Committee) administers the 2000 Plan and may grant shares of the Company's common stock to non-employee directors in its discretion. No discretionary grants of common stock have been made under the 2000 Plan.
GRANTS OF NONQUALIFIED STOCK OPTIONS
The Committee can grant nonqualified stock options under the 2000 Plan. The terms and the conditions of the option grant, including the exercise price per share, which may not be less than fair market value on the date of grant, will be set by the Committee in a written award agreement. The Committee will determine the time or times at which any such options may be exercised in whole or in part. The Committee will also determine the performance or other conditions, if any, that must be satisfied before all or part of an option may be exercised. Any such options granted to a participant will expire on the tenth anniversary date of the date of grant, unless the option is earlier terminated, forfeited or surrendered pursuant to a provision of the 2000 Plan or the applicable award agreement. Notwithstanding the foregoing, if a participant ceases to be a Company director for any reason, including death or disability, any such options held by that participant will expire on the second anniversary of the date on which the participant ceased to be a Company director, unless otherwise provided in the applicable award agreement. Unless the Committee provides otherwise, no such options may be sold, transferred, pledged, assigned or otherwise alienated, other than by will, the laws of descent and distribution, or under any other circumstances allowed by the Committee. No options have been granted under the 2000 Plan.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to "Executive Compensation - Human Resources Committee Interlocks and Insider Participation" and "- Employment and Severance Arrangements" in the 2003 Proxy Statement.
ITEM 14.
ITEM 14. CONTROLS AND PROCEDURES
As of a date within 90 days of the date of this report (the "Evaluation Date"), we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer, concluded that, as of the Evaluation Date, our disclosure controls and procedures were adequate to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.
There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation, including any corrective actions with regard to significant deficiencies and internal weaknesses.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See the Index to Consolidated Financial Statements and Financial Statement Schedule in Part II, Item 8.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION - ----------- -----------
4.1 -- Fifty-sixth Supplemental Indenture to the Mortgage dated as of March 1, 2003
4.2 -- Fifty-seventh Supplemental Indenture to the Mortgage dated as of April 1, 2003
10.1(a) -- 2003 Officer Variable Incentive Plan
10.2(a) -- 2003 CEO Variable Incentive Plan
10.3(a) -- Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended
10.4(a) -- Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler
10.5(a) -- Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
12.1 -- Ratio of Earnings to Fixed Charges
21.1 -- Subsidiaries of the Company
23.1 -- Consent of Deloitte & Touche LLP
99.1 -- Certification of William J. Post, the Company's principal executive officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.2 -- Certification of Donald E. Brandt, the Company's principal financial officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.3 -- 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 ss.229.10(d) by reference to the filings set forth below:
- ---------- (a) Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
(b) Reports 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.
(c) An 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.
(d) Additional 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.
REPORTS ON FORM 8-K
During the quarter ended December 31, 2002, and the period ended March 31, 2003, the Company filed the following Reports on Form 8-K:
Report dated September 30, 2002 containing exhibits comprised of financial information and earnings variance explanations.
Report dated October 17, 2002 regarding the Company's earnings outlook and a slide presentation for use at an analyst conference.
Report dated November 14, 2002 regarding an ACC staff recommendation that the Interim Financing Application be approved.
Report dated November 15, 2002 regarding: (i) appeals of the Track A Order and an agreement between APS and the ACC staff; (ii) ACC staff testimony on the Financing Application; and (iii) EITF 02-3.
Report dated November 21, 2002 regarding reclassifications of revenue from electricity trading activities to a net basis of reporting.
Report dated November 22, 2002 regarding ACC approval of the Interim Financing Application and Pinnacle West Energy's decision to cancel Redhawk Units 3 and 4.
Report dated December 17, 2002 containing exhibits to Registration Statement Nos. 333-52476 and 333-101457.
Report dated December 31, 2002 regarding an ACC staff report on Track B and containing exhibits comprised of financial information and earnings variance explanations.
Report dated January 15, 2003 regarding NAC losses and earnings outlook.
Report dated February 27, 2003 regarding the ACC Track B decision.
Report dated March 11, 2003 regarding an ACC ALJ recommendation on the Financing Application.
Report dated March 27, 2003 regarding ACC approval of a financing arrangement.
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.
PINNACLE WEST CAPITAL CORPORATION (Registrant)
Date: March 31, 2003 William J. Post ---------------------------------------- (William J. Post, Chairman of the Board of Directors 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 --------- ----- ----
William J. Post Principal Executive Officer March 31, 2003 - -------------------------------- and Director (William J. Post, Chairman of the Board of Directors and Chief Executive Officer)
Jack E. Davis Principal Accounting March 31, 2003 - -------------------------------- Officer and Director (Jack E. Davis, President)
Donald E. Brandt Principal Financial Officer March 31, 2003 - -------------------------------- (Donald E. Brandt, Senior Vice President and) Chief Financial Officer)
Edward N. Basha, Jr. Director March 31, 2003 - -------------------------------- (Edward N. Basha, Jr.)
Michael L. Gallagher Director March 31, 2003 - -------------------------------- (Michael L. Gallagher)
Pamela Grant Director March 31, 2003 - -------------------------------- (Pamela Grant)
Roy A. Herberger, Jr. Director March 31, 2003 - -------------------------------- (Roy A. Herberger, Jr.)
Martha O. Hesse Director March 31, 2003 - -------------------------------- (Martha O. Hesse)
William S. Jamieson, Jr. Director March 31, 2003 - -------------------------------- (William S. Jamieson, Jr.)
Humberto S. Lopez Director March 31, 2003 - -------------------------------- (Humberto S. Lopez)
Robert G. Matlock Director March 31, 2003 - -------------------------------- (Robert G. Matlock)
Kathryn L. Munro Director March 31, 2003 - -------------------------------- (Kathryn L. Munro)
Bruce J. Nordstrom Director March 31, 2003 - -------------------------------- (Bruce J. Nordstrom)
William L. Stewart Director March 31, 2003 - -------------------------------- (William L. Stewart)
CERTIFICATIONS
I, William J. Post, certify that:
1. I have reviewed this annual report on Form 10-K of Pinnacle West Capital Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 31, 2003.
William J. Post ---------------------------------------- William J. Post Chairman and Chief Executive Officer
I, Donald E. Brandt, certify that:
1. I have reviewed this annual report on Form 10-K of Pinnacle West Capital Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 31, 2003.
Donald E. Brandt ---------------------------------------- Donald E. Brandt Senior Vice President and Chief Financial Officer