SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
OR
PINNACLE WEST CAPITAL CORPORATION
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or in any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x No o
State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $3,404,788,658 as of June 30, 2003
The number of shares outstanding of the registrant’s common stock as of March 11, 2004 was 91,297,881.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 19, 2004 are incorporated by reference into Part III hereof.
TABLE OF CONTENTS
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GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
AFUDC – allowance for funds used during construction
AISA – Arizona Independent Scheduling Administrator
ALJ – Administrative Law Judge
ANPP – Arizona Nuclear Power Project, also known as Palo Verde
APS – Arizona Public Service Company, a subsidiary of the Company
APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company
CC&N – Certificate of Convenience and Necessity
Cholla – Cholla Power Plant
Citizens – Citizens Communications Company
Clean Air Act – the Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
CPUC – California Public Utility Commission
DOE – United States Department of Energy
EITF – the FASB’s Emerging Issues Task Force
El Dorado – El Dorado Investment Company, a subsidiary of the Company
EPA – United States Environmental Protection Agency
ERMC – Energy Risk Management Committee
FASB – Financial Accounting Standards Board
FERC – United States Federal Energy Regulatory Commission
FIN – FASB Interpretation
Financing Order – ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May 2003
FIP – Federal Implementation Plan
Four Corners – Four Corners Power Plant
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
ISO – California Independent System Operator
kW – kilowatt, one thousand watts
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MW – megawatt, one million watts
MWh – megawatt-hours, one million watts per hour
NAC – NAC International Inc., a subsidiary of El Dorado
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
1999 Settlement Agreement – comprehensive settlement agreement related to the implementation of retail electric competition
NOV – Notice of Violation
NRC – United States Nuclear Regulatory Commission
Nuclear Waste Act – Nuclear Waste Policy Act of 1982, as amended
OCI – other comprehensive income
Palo Verde – Palo Verde Nuclear Generating Station
PCAOB – Public Company Accounting Oversight Board
PG&E – PG&E Corp.
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company
PRP – potentially responsible parties under Superfund
PWEC Dedicated Assets – the following Pinnacle West Energy power plants, each of which is dedicated to serving APS’ customers: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
PX – California Power Exchange
RTO – regional transmission organization
Rules – ACC retail electric competition rules
Salt River Project – Salt River Project Agricultural Improvement and Power District
SCE – Southern California Edison Company
SEC – United States Securities and Exchange Commission
SFAS – Statement of Financial Accounting Standards
SNWA – Southern Nevada Water Authority
SPE – special-purpose entity
Standard & Poor’s – Standard & Poor’s Corporation
SunCor – SunCor Development Company, a subsidiary of the Company
Superfund – Comprehensive Environmental Response, Compensation and Liability Act
T&D – transmission and distribution
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Track A Order – ACC order dated September 10, 2002 regarding generation asset transfers and related issues
Track B Order –ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizona’s investor-owned electric utilities
Trading – energy-related activities entered into with the objective of generating profits on changes in market prices
VIE – variable interest entity
WestConnect – WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission lines in the southwestern United States
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PART I
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, our major subsidiary. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States.
Our other significant subsidiaries are Pinnacle West Energy, which owns and operates generating plants; APS Energy Services, which provides competitive energy services and products in the western United States; and SunCor, which is engaged in real estate development activities. We discuss each of these subsidiaries in greater detail below. See “Business of Pinnacle West Energy Corporation,” “Business of APS Energy Services Company, Inc.” and “Business of SunCor Development Company” in this Item 1.
Business Segments
We have three principal business segments (determined by products, services and the regulatory environment):
See Note 17 of Notes to Consolidated Financial Statements in Item 8 for financial information about our business segments.
APS General Rate Case
We believe APS’ general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3 of Notes to Consolidated Financial Statements in Item 8, in this rate case APS has requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by APS as part of the 1999 Settlement Agreement. In its filed
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testimony, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.
Employees
At December 31, 2003, we employed about 7,200 people, including the employees of our subsidiaries. Of these employees, about 6,000 were employees of APS, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. About 1,200 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).
Available Information
We make available free of charge on or through our Internet Website (www.pinnaclewest.com) the following filings as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC: our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. 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. These forward-looking statements are often identified by words such as “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include, but are not limited to:
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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’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates. See Note 3 of Notes to Consolidated Financial Statements in Item 8 for a discussion of the status of electric industry restructuring in Arizona.
The electric utility industry has undergone significant regulatory change in the last few years designed to encourage competition in the sale of electricity and related services. However, the experience in California with deregulation has caused many states, including Arizona, to reexamine retail electric competition.
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As of January 1, 2001, all of APS’ retail customers were eligible to choose an alternate energy supplier. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory. Also, regulatory developments and legal challenges to the ACC’s electric competition rules have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. See “Retail Electric Competition Rules” in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional information.
APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Tucson Electric Power Company and Southwest Gas Corporation) as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations (principally Salt River Project). APS also faces competition from low-cost, hydroelectric power and parties that have access to low-priced preferential, federal power and other governmental subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.
Wholesale
The FERC regulates rates for wholesale power sales and transmission services. During 2003, approximately 19% 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 remained 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 “Track A Order” in Note 3 of Notes to Consolidated Financial Statements in Item 8).
The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with its costs of serving retail customer energy requirements. The division also 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. 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. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emissions allowances and credits.
Regional Transmission Organizations
Federal In a December 1999 order, the FERC established characteristics and functions that must be met by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and nondiscriminatory markets and exclusive authority to maintain short-term reliability. Additionally, in a pending notice of proposed rulemaking, the FERC is considering implementing a standard market design for wholesale markets.
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On October 16, 2001, APS and other owners of electric transmission lines in the Southwest filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic framework for a standard market design for the Southwest. On September 15, 2003, the FERC issued an order granting clarification and rehearing, in part, of its prior orders. In particular, this order approved the use of a physical congestion management scheme, which is used to allocate transmission rights on congested lines, for WestConnect for an initial phase-in period. The FERC indicated that the WestConnect utilities and the appropriate regional state advisory committee should develop a market-based congestion management scheme for subsequent implementation. APS is now participating in a cost/benefit analysis of implementing WestConnect, the results of which are expected to be completed in 2004.
State The Rules also required the formation and implementation of an Arizona Independent Scheduling Administrator. The purpose of the AISA is to oversee the application of operating protocols to ensure statewide consistency for transmission access. The AISA is anticipated to be a temporary organization until the implementation of an independent system operator or RTO. 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. 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
APS was incorporated in 1920 under the laws of Arizona and currently has more than 931,500 customers. APS does not distribute any products. During 2003, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 4% of consolidated electric revenues. See “Current Status – General” and “Regulation and Competition” above for additional background information about APS’ business, including its marketing and trading division.
At December 31, 2003, APS employed approximately 6,000 people, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. APS’ principal executive offices are located at 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-1000).
Purchased Power and Generating Fuel
See “Properties – Capacity” in Item 2 for information about our power plants by fuel types.
2003 Energy Mix
Our consolidated sources of energy during 2003 were: purchased power – 54.4% (approximately 90.0% of which was for wholesale power operations); coal – 20.1%; nuclear – 14.7%; gas – 10.7%; and other (includes oil, hydro and solar) – 0.1%.
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APS’ sources of energy during 2003 were: purchased power – 55.3% (approximately 75.0% of which was for wholesale power operations); coal – 24.5%; nuclear – 17.9%; gas – 2.2%; and other (includes oil, hydro and solar) – 0.1%.
Coal Supply
Cholla Cholla is a coal-fired power plant located in northeastern Arizona. It is a jointly-owned facility operated by APS. APS purchases most of Cholla’s coal requirements from a coal supplier that mines all of the coal under a long-term lease of coal reserves owned by the Navajo Nation, the federal government and private landholders. Cholla has sufficient coal under current contracts to ensure a reliable fuel supply through 2007. This includes our expected requirements for low sulfur coal, which is required for limited operating conditions; however, if necessary, low sulfur coal may be purchased on the open market. APS may purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options. Following expiration of current contracts, APS believes that numerous competitive fuel supply options will exist to ensure the continued operation of Cholla for its useful life.
Four Corners Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. It is a jointly-owned facility operated by APS. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. The Four Corners coal contract runs through July 2016, with options to extend the contract for five to fifteen additional years beyond the plant site lease expiration in 2017.
Navajo Generating Station The Navajo Generating Station is a coal-fired power plant located in northern Arizona. It is a jointly-owned facility operated by Salt River Project. The Navajo Generating Station’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through the plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. The lease provides for the potential to renegotiate the coal royalty in 2007 and 2017 and a five-year price review, each of which may impact the fuel price.
See “Properties – Capacity” in Item 2 for information about APS’ ownership interests in Cholla, Four Corners and the Navajo Generating Station. See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding our coal mine reclamation obligations.
Natural Gas Supply
See Note 11 of Notes to Consolidated Financial Statements in Item 8 for a discussion of our natural gas requirements.
Nuclear Fuel Supply
Palo Verde Fuel Cycle Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. It is a jointly-owned facility operated by APS. The fuel cycle for Palo Verde is comprised of the following stages:
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The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2008. The Palo Verde participants have also contracted for all of Palo Verde’s enrichment services through 2010 and fuel assembly fabrication services until at least 2015.
Spent Nuclear Fuel and Waste Disposal See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Consolidated Financial Statements in Item 8 for a discussion of spent nuclear fuel and waste disposal.
Purchased Power Agreements
In addition to its own available generating capacity (see “Properties” in Item 2), APS purchases electricity under various arrangements. One of the most important of these is a long-term contract with Salt River Project. The amount of electricity available to APS is based in large part on customer demand within certain areas now served by APS pursuant to a related territorial agreement. The generating capacity available to APS pursuant to the contract was 343 MW from January through May 2003, and starting in June 2003, it changed to 350 MW. In 2003, APS received approximately 952,146 MWh of energy under the contract and paid about $64.4 million for capacity availability and energy received. This contract may be canceled by Salt River Project on three years’ notice, given no earlier than December 31, 2003. To date, Salt River Project has not given any notice to cancel. APS may also cancel the contract on five years’ notice, given no earlier than December 31, 2006.
In September 1990, APS entered into a thirty-year seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2003, APS received approximately 571,392 MWh of energy under the capacity exchange. APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2003, PacifiCorp received offers of 1,091,450 MWh and purchased about 168,000 MWh.
In December 2003, APS issued a request for proposals for the purchase of at least 500 MW of long-term power supply resources for delivery beginning June 1, 2007 to be used for APS’ anticipated retail load. For additional information, see “Request for Proposals” in Note 3 of Notes to Consolidated Financial Statements in Item 8.
Consistent with the ACC’s Track B Order, APS issued a request for proposals (“RFP”) in March 2003 and, as a result of that RFP, on or before May 6, 2003, APS entered into contracts with three parties, including Pinnacle West Energy, to meet a portion of APS’ capacity and energy requirements for the years 2003 through 2006. See “Track B Order” in Note 3 of Notes to
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Consolidated Financial Statements in Item 8 for additional information about the contracts and the Track B Order.
Construction Program
During the years 2001 through 2003, APS incurred approximately $1.4 billion in capital expenditures. APS’ capital expenditures for the years 2004 through 2006 are expected to be primarily for expanding transmission and distribution capabilities to meet growing customer needs, for upgrading existing utility property and for environmental purposes. APS’ capital expenditures were approximately $429 million in 2003. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2004 through 2006 have been estimated as follows:
(dollars in millions)
The above amounts exclude capitalized interest costs and include capitalized property taxes and approximately $30 million per year for nuclear fuel. These amounts include only APS’ generation (production) assets. APS conducts a continuing review of its construction program.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Needs and Resources by Company” in Item 7 for additional information about APS’ and Pinnacle West Energy’s construction programs.
Environmental Matters
EPA Environmental Regulation
Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These new regulations require states to submit, by 2008, implementation plans to eliminate all man-made emissions causing visibility impairment in certain specified areas, including Class I Areas in the Colorado Plateau, and to consider and potentially apply the best available retrofit technology for major stationary sources.
The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. Five western states, including Arizona, have submitted proposed State Implementation Plans (SIPs) to the EPA to implement this alternative plan. If the EPA approves Arizona’s SIP, APS does not anticipate any new emission reduction requirements for its Arizona plants through 2013.
With respect to hazardous air pollutants emitted by electric utility steam generating units, the EPA determined in 2000 that mercury emissions and other hazardous air pollutants from coal and oil-fired power plants should be regulated. The EPA recently proposed two alternatives to regulate mercury emissions from these plants. Under the first alternative, the EPA would promulgate a Maximum Achievable Control Technology (MACT) standard establishing mercury emission limitations for coal- and oil-fired power plants, effective 2008. APS is currently assessing the need
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for additional controls to meet this proposed alternative. Under the second alternative, the EPA would rescind its 2000 finding requiring the establishment of a MACT standard for such plants, and would instead establish a two-phased mercury emissions trading program under the Clean Air Act’s new source performance standards provisions. If this second alternative is adopted, APS does not anticipate any emission reduction requirements under the first phase of the program (from 2010 through 2018). Because the ultimate requirements that the EPA may impose are not yet known, we cannot currently estimate the capital expenditures, if any, which may be required.
Federal Implementation Plan In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and Four Corners. The FIP is similar to current Arizona regulation of the Navajo Generating Station and New Mexico regulation of Four Corners, with minor modifications. APS does not currently expect the FIP to have a material adverse effect on its financial position, results of operations or liquidity.
Superfund The Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a “potentially responsible party” in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this superfund site. The EPA has only recently begun to study the OU3 site. Because the ultimate remediation requirements the EPA may require are not yet known, we cannot currently estimate the expenditures, if any, which may be required.
Manufactured Gas Plant Sites APS is currently investigating properties which it now owns or which were previously owned by it or its corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. Where appropriate, APS conducts clean-up activities for these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or liquidity.
Arizona Department of Environmental Quality
ADEQ issued two NOVs to APS in 2001 alleging, among other things, the burning of unauthorized materials and storage of hazardous waste without a permit at the Cholla Power Plant. APS, the Attorney General for the State of Arizona and ADEQ have reached an agreement (in the form of a Consent Judgment) to settle this matter. The Consent Judgment (No. CV2004-000731) was entered on January 26, 2004, and on February 2, 2004, pursuant to its terms, APS paid a $200,000 penalty to the State of Arizona.
ADEQ issued an NOV to APS in January 2004 alleging that, among other things, the discharge limit for lead was exceeded at the Saguaro Power Plant. APS is in the process of investigating this matter.
Navajo Nation Environmental Issues
Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. APS is the Four Corners operating agent. APS owns a 100% interest in Four Corners Units
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1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating Station Units 1, 2 and 3.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Nation as to Four Corners and Navajo Generating Station. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement. APS cannot currently predict the outcome of this matter.
In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Indian tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants and the Navajo Generating Station participants that could limit the Navajo Nation’s environmental regulatory authority over the Navajo Generating Station and Four Corners. APS believes that the Clean Air Act does not supersede these pre-existing agreements. APS cannot currently predict the outcome of this matter.
In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. We believe the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo Generating Station participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. We cannot currently predict the outcome of this matter.
Water Supply
Assured supplies of water are important for our generating plants. At the present time, APS has adequate water to meet its needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions.
Both groundwater and surface water in areas important to APS’ operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding before a state court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. (State of New Mexico, in the relation of S.E. Reynolds, State Engineer vs. United States of America, City of Farmington, Utah International, Inc., et al., San Juan County, New Mexico, District Court No. 75-184). An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for a then-agreed upon cost, sufficient water from its allocation to offset the loss.
A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. (In re The General Adjudication of All
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Rights to Use Water in the Gila River System and Source, Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As project manager of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Three of APS’ other power plants and two of Pinnacle West Energy’s power plants are also located within the geographic area subject to the summons. APS’ claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues will continue in the trial court. No trial date concerning APS’ water rights claims has been set in this matter.
APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court. (In re The General Adjudication of All Rights to Use Water in the Little Colorado River System and Source, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417). APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. APS’ claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’ water rights claims has been set in this matter.
Although the above matters remain subject to further evaluation, APS expects that the described litigation will not have a material adverse impact on its financial position, results of operations or liquidity.
The Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants in 2004, as well as later years if adequate moisture is not received in the watershed that supplies the area. We are negotiating agreements with various parties to provide backup supplies of water for 2004, if required, and are continuing to work with area stakeholders to implement additional agreements to minimize the effect, if any, on operations of the plant for 2005 and later years. The effect of the drought cannot be fully assessed at this time, and we cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.
BUSINESS OF PINNACLE WEST ENERGY CORPORATION
Pinnacle West Energy was incorporated in 1999 under the laws of the State of Arizona and is engaged principally in the operation of generating plants. Pinnacle West Energy had approximately 100 employees as of December 31, 2003. Pinnacle West Energy’s principal offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone (602) 250-4145).
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See “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of Pinnacle West Energy’s capital expenditures.
Pinnacle West Energy’s Arizona plants were built as a result of what we believed was a regulatory restriction against APS’ construction of additional plants and based on the requirement in the 1999 Settlement Agreement that APS transfer its generation assets. As discussed under “APS General Rate Case and Retail Rate Adjustment Mechanisms” in Note 3 of Notes to Consolidated Financial Statements in Item 8, as part of its general rate case, APS is seeking rate base treatment of the PWEC Dedicated Assets.
At December 31, 2003, Pinnacle West Energy had total assets of $1.4 billion. Pinnacle West Energy had a net loss of $1 million in 2003, a net loss of $19 million in 2002 and net income of $18 million in 2001. See footnote (c) in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Earnings Contributions by Subsidiary and Business Segments” in Item 7 for a discussion of Pinnacle West Energy’s contract to supply purchase power requirements in summer months through September 2006.
BUSINESS OF APS ENERGY SERVICES COMPANY, INC.
APS Energy Services was incorporated in 1998 under the laws of the State of Arizona and 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. APS Energy Services had approximately 100 employees as of December 31, 2003. APS Energy Services’ principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone (602) 250-5000).
APS Energy Services had net income of $16 million in 2003, pretax income of $28 million in 2002, and a pretax loss of $10 million in 2001. Income taxes related to APS Energy Services were recorded by the parent company prior to 2003. At December 31, 2003, APS Energy Services had total assets of $90 million.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
SunCor was incorporated in 1965 under the laws of the State of Arizona and is a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe, Arizona 85281 (telephone (480) 317-6800). SunCor and its subsidiaries had approximately 800 full- and part-time employees at December 31, 2003.
At December 31, 2003, SunCor had total assets of about $439 million. SunCor’s assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor intends to continue its focus on real estate development of master-planned communities, mixed-use residential, commercial, office and industrial projects.
SunCor projects under development include seven master-planned communities and several commercial projects. The commercial projects and four of the master-planned communities are in
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Arizona. Other master-planned communities are located near St. George, Utah, Boise, Idaho and Santa Fe, New Mexico.
SunCor has implemented an accelerated asset sales program for 2004 and 2005. As a result of this program, SunCor expects to have net income of approximately $30 – 40 million a year in this period. SunCor also expects to make cash distributions of $80 – 100 million annually to the parent in this time frame.
For the past three years, SunCor’s operating revenues were approximately: $362 million in 2003; $201 million in 2002; and $169 million in 2001. For those same periods, SunCor’s net income was approximately $56 million in 2003; $19 million in 2002; and $3 million in 2001.
See Note 6 of Notes to Consolidated Financial Statements in Item 8 for information regarding SunCor’s long-term debt and “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of SunCor’s capital expenditures.
BUSINESS OF EL DORADO INVESTMENT COMPANY
El Dorado was incorporated in 1983 under the laws of the State of Arizona. El Dorado’s largest holding is a majority interest in NAC, a company specializing in spent nuclear fuel technology. El Dorado also owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. On a long-term basis, we may use El Dorado, when appropriate, as our subsidiary for investments that are strategic to our principal business of generating, distributing and marketing electricity. El Dorado’s offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone (602) 250-3517). El Dorado had approximately 100 employees (all NAC) at December 31, 2003.
El Dorado had pretax income of $7 million in 2003, a pretax loss of $55 million in 2002 and net income of $0.2 million in 2001. The parent company recorded income taxes related to El Dorado in 2003 and 2002. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for information regarding El Dorado’s 2002 losses. At December 31, 2003, El Dorado had total assets of $27 million.
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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:
Pinnacle West Energy – Permitted Capacities
Pinnacle West Energy’s present generating facilities have permitted capacities as follows:
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Reserve Margin
APS’ 2003 peak one-hour demand on its electric system was recorded on July 14, 2003 at 6,332,400 kW, compared to the 2002 peak of 5,802,900 kW recorded on July 9, 2002. Firm purchases totaling 4,198,000 kW, including short-term seasonal purchases and unit contingent purchases, were in place at the time of the peak, ensuring the ability to meet the load requirement, with an actual reserve margin of 12.1%. Taking into account additional capacity then available to 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 14, 2003 amounted to 6,371,600 kW, for an installed reserve margin of 1.0%. The power actually available to APS from its resources fluctuates from time to time due in part to outages, both planned and unplanned, and technical problems. The available capacity from sources actually operable at the time of the 2003 peak amounted to 3,736,500 kW, for a margin of negative 50.4%.
See “Business of Arizona Public Service Company – Purchased Power Agreements” in Item 1 for information about certain of APS’ long-term power agreements. See “Request for Proposals” in Note 3 of Notes to Consolidated Financial Statements in Item 8 for information regarding a request for proposals issued by APS in December 2003 for the purchase of at least 500 MW of long-term power supply resources for delivery beginning June 1, 2007.
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
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”
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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. The 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, 2003:
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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.
Transmission Access
APS’ transmission facilities consist of approximately 5,000 pole miles of overhead lines and approximately 35 miles of underground lines, all of which are located within the State of Arizona. APS’ distribution facilities consist of approximately 12,000 pole miles of overhead lines and approximately 13,000 miles of underground lines, all of which are located within the State of Arizona. In June 2003 APS energized a new 37-mile 500-kilovolt transmission line that runs from Palo Verde to the Phoenix area. See also “Regional Transmission Organizations” in Item 1 above.
Other Information Regarding Our Properties
See “Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of our power plants.
See “Construction Program” in Item 1 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 for a discussion of our construction program.
Information Regarding SunCor’s Properties
See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s properties. SunCor’s debt is collateralized by interests in certain real property.
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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.
ITEM 4. SUBMISSION OF MATTERS TO AVOTE OF SECURITY HOLDERS
Not applicable.
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SUPPLEMENTAL ITEM.EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers are as follows:
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:
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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 President effective February 2001 and Chief Operating Officer effective September 2003. 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 also 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. Brandt was elected to his present position in September 2003 and was Senior Vice President and Chief Financial Officer (December 2002 – September 2003). Prior to that time he was Senior Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services company). Mr. Brandt was elected Executive Vice President and Chief Financial Officer of APS in September 2003. He was also Senior Vice President and Chief Financial Officer of APS (January 2003 – September 2003).
Mr. Flores was elected to his present position in September 2003. Prior to that time he was Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 – September 2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 – July 1999).
Mr. Froggatt was elected to his present position in October 2002. Prior to that time he was Vice President and Controller of Pinnacle West (August 1999 – October 2002), Controller of Pinnacle West (July 1999 – August 1999) and Controller of APS (July 1997 – July 1999).
Ms. Gomez was elected to her present position in February 2004. Prior to that time, she was Treasurer (August 1999 – February 2004) and Manager, Treasury Operations of APS (1997 – 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in February 2004.
Mr. Levine was elected Executive Vice President of APS in July 1999 and President and Chief Executive Officer 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. Robinson was elected to his present position in September 2003. Prior to that time he was Vice President, Finance and Planning of APS (October 2002 – September 2003), Vice President, Regulation and Planning of Pinnacle West (June 2001 – October 2002) and Director, Accounting, Regulation and Planning of Pinnacle West (prior to June 2001).
Mr. Wheeler was elected to his present position in September 2003. Prior to that time he was Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 – September 2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle
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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. MARKET FOR REGISTRANT’S COMMONSTOCK 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 11, 2004, our common stock was held of record by approximately 35,623 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE
STOCK SYMBOL: PNW
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ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSISOF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with the Consolidated Financial Statements and the related Notes that appear in Item 8 of this report.
OVERVIEW
We own all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States. APS has historically accounted for a substantial part of our revenues and earnings. Growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.
Pinnacle West Energy is our unregulated generation subsidiary. We formed Pinnacle West Energy in 1999 as a result of the ACC’s requirement that APS transfer all of its competitive assets and services to an affiliate or to a third party by the end of 2002. We planned to transfer APS’ generation assets to Pinnacle West Energy. Additionally, Pinnacle West Energy constructed several power plants to meet growing energy needs (1790 MW in Arizona and 570 MW in Nevada). In September 2002, the ACC issued the Track A Order, which prohibited APS from transferring its generation assets to Pinnacle West Energy. As a result of the Track A Order, we are seeking to transfer the plants built by Pinnacle West Energy in Arizona to APS to unite the Arizona generation under one common owner, as originally intended.
SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow, particularly during the years 2003 through 2005 due to accelerated asset sales activity. Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial, industrial and institutional retail customers in the western United States.
The earnings contributions of our marketing and trading segment significantly decreased over the past two years due to lower market liquidity and deteriorating counterparty credit in the wholesale power markets in the western United States. The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with APS’ costs of serving retail customer energy requirements. We currently expect contributions from our trading activities to be negligible for 2004 and approximately $10 million (pretax) annually thereafter.
We continue to focus on solid operational performance in our electricity generation and delivery activities. In the generation area, 2003 represented the twelfth consecutive year Palo Verde was the largest power producer in the United States. In the delivery area, we focus on superior reliability and expanding our transmission and distribution system to meet growth and sustain reliability.
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We believe APS’ general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3 in Item 8, in this rate case APS has requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by APS as part of the 1999 Settlement Agreement. In its filed testimony, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.
Other factors affecting our past and future financial results include customer growth; purchased power and fuel costs; operations and maintenance expenses, including those relating to plant outages; weather variations; depreciation and amortization expenses, which are affected by net additions to existing utility plant and other property and changes in regulatory asset amortization; and the expected performance of our subsidiaries, SunCor and El Dorado.
EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENTS
The following tables summarize net income and segment details for the years ended December 31, 2003, 2002 and 2001 for Pinnacle West and each of our subsidiaries (dollars in millions):
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See Note 17 for additional financial information regarding our business segments.
RESULTS OF OPERATIONS
Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. 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 primarily includes El Dorado’s investment in NAC, which we began consolidating in our financial statements in July 2002. Other gross margin also includes amounts related to APS Energy Services’ energy consulting services. In addition, we have reclassified certain prior period amounts to conform to our current period presentation, including netting of certain revenues and purchased power amounts as a result of the adoption of EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in Issue No. 02-3” (see Note 18).
2003 Compared with 2002
Our consolidated net income for the year ended December 31, 2003 was $241 million compared with $149 million for the prior year. The 2002 net income includes a $66 million after-tax charge for the cumulative effect of a change in accounting for trading activities due to the 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” (see Note 18). Excluding the accounting change, the $26 million increase in the period-to-period comparison reflects the following changes in earnings by segment:
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Additional details on the major factors that increased (decreased) income from continuing operations and net income for the year ended December 31, 2003 compared with the prior year are contained in the following table (dollars in millions).
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The increase in operating and interest costs related to new power plants placed in service by Pinnacle West Energy, net of purchased power savings and increased gross margin from generation sales other than Native Load, totaled approximately $30 million after income taxes in the year ended December 31, 2003 compared with the prior-year period.
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $88 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:
Marketing and Trading Segment Revenues
Marketing and trading segment revenues were $105 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:
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Real Estate Segment Revenues
Real estate segment revenues were $161 million higher in the year ended December 31, 2003 compared with the prior year primarily as a result of increased asset, land and home sales related to SunCor’s effort to accelerate asset sales.
Other Revenues
Other revenues were $24 million higher in the year ended December 31, 2003 compared with the prior year primarily due to our consolidation of NAC’s financial statements beginning in the third quarter of 2002, partially offset by decreased sales activity at NAC.
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). Net income for 2002 includes income from discontinued operations of $9 million after-tax related to our real estate segment (see Note 22). Excluding the accounting changes and discontinued operations, the $121 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:
Additional details on the major factors that increased (decreased) income from continuing operations and net income for the year ended December 31, 2002 compared with the prior year are contained in the following table (dollars in millions).
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Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $94 million lower in the year ended December 31, 2002, compared with the prior year as a result of:
Marketing and trading segment revenues were $183 million lower in the year ended December 31, 2002, compared with the prior year as a result of:
Real Estate segment revenues were $32 million higher in the year ended December 31, 2002 compared with the prior year primarily as a result of increased land, asset and home sales.
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Other revenues were $50 million higher in the year ended December 31, 2002 compared with the prior year primarily due to the consolidation of NAC’s financial statements beginning in the third quarter of 2002.
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, 2003 and estimated capital expenditures for the next three years.
CAPITAL EXPENDITURES(dollars in millions)
Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs.
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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. APS completed the Southwest Valley transmission project in 2003 at a cost of approximately $70 million. Major transmission projects are driven by strong regional customer growth. APS will begin major projects each year for the next several years, and expects to spend about $200 million on major transmission projects during the 2004 to 2006 time frame. These amounts are included in “APS-Delivery” in the table above. Completion of these projects will stretch from 2005 through at least 2008.
Generation capital expenditures are comprised of various improvements to 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 includes nuclear fuel expenditures of approximately $30 million annually for 2004 to 2006.
Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall outage of 2003 at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. These generators will be installed in Unit 1 (scheduled completion in 2005) and Unit 3 (scheduled completion in 2007). Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million, which will be spent through 2008. In 2004 through 2006, approximately $90 million of the Unit 1 and Unit 3 costs are included in the generation capital expenditures table above and will be funded with internally-generated cash or external financings.
Contractual Obligations
The following table summarizes contractual requirements as of December 31, 2003 (dollars in millions):
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Off-Balance Sheet Arrangements
In 2003, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities,” as it applies to special-purpose entities. FIN No. 46R requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. In 1986, 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 assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs. Certain provisions of FIN No. 46R have a future effective date. We do not expect these provisions to have a material impact on our financial statements.
APS is 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, 2003, APS would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.
Guarantees and Letters of Credit
We and certain of our subsidiaries have issued guarantees and letters of credit 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 21 for additional information regarding guarantees and letters of credit.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of March 11, 2004 are shown below and are considered to be “investment-grade” ratings. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market
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price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 18).
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet the covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for each of the Company and APS individually. At December 31, 2003, the ratio was approximately 54% for Pinnacle West. At December 31, 2003, the ratio was approximately 53% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. Based on 2003 results, the coverages were approximately 4 times for the Company, 4 times for the APS bank financing 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 financial condition or financial prospects.
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Capital Needs and Resources by Company
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders; 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) and equity infusions into our subsidiaries, primarily Pinnacle West Energy. On October 22, 2003, our board of directors increased the common stock dividend to an indicated annual rate of $1.80 per share from $1.70 per share, effective with the December 1, 2003 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 2001 through 2003, total dividends from APS were $510 million and total distributions from SunCor were $121 million. For the year ended December 31, 2003, dividends from APS were approximately $170 million and distributions from SunCor were approximately $108 million. We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2004 and 2005 due to anticipated accelerated asset sales activity. As discussed in Note 3 under “ACC Financing Orders,” APS must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce its common equity below that threshold. As defined in the Financing Order, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At December 31, 2003, APS’ common equity ratio was approximately 46%.
On May 12, 2003, APS issued $500 million of debt as follows: $300 million aggregate principal amount of its 4.65% Notes due 2015 and $200 million aggregate principal amount of its 5.625% Notes due 2033. Also on May 12, 2003, APS made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy distributed the net proceeds of that loan to us to fund our repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. See “ACC Financing Order” in Note 3 for additional information. With Pinnacle West Energy’s distribution to us on May 12, 2003, we repaid the outstanding balance ($167 million) under a credit facility. We used a portion of the remaining proceeds to redeem our $250 million Floating Rate Notes due 2003 on June 2, 2003 and to repay other short-term debt. On November 12, 2003, we issued $165 million of our Floating Rate Senior Notes due 2005.
At December 31, 2003, the parent company’s outstanding long-term debt, including current maturities, was $681 million. At December 31, 2003, we had unused credit commitments from various banks totaling $275 million, which were available to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2003, we had no commercial paper outstanding and no short-term borrowings. We ended 2003 in an invested position.
Pinnacle West sponsors a pension plan that covers employees of Pinnacle West and our subsidiaries. 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
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those years was zero. Specifically, we contributed $73 million for 2002 ($46 million of which was contributed in June 2003); $24 million for 2001; $44 million for 2000 ($20 million of which was contributed in 2001); and $25 million for 1999. APS and other subsidiaries fund their share of the pension contribution, of which APS represents approximately 89% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. Under current law, we are required to contribute approximately $100 million to our pension plans in 2004 and expect to contribute approximately $50 million to our other postretirement benefit plan in 2004. If currently pending legislation is enacted, our required pension contribution in 2004 would decrease to the $25 to $50 million range.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See “Pinnacle West (Parent Company)” above and Note 3 for discussion of the $500 million financing arrangement between APS and Pinnacle West Energy approved by the ACC in 2003 and 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. See “Pinnacle West (Parent Company)” above for a discussion of common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
On April 7, 2003, APS redeemed approximately $33 million of its First Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, APS redeemed approximately $54 million of its First Mortgage Bonds, 7.25% Series due 2023.
On February 15, 2004, $125 million of APS 5.875% Notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of APS’ First Mortgage Bonds, 6.625% Series due 2004 were redeemed at maturity. APS used cash from operations and short-term debt to redeem the maturing debt.
APS’ outstanding debt was approximately $2.6 billion at December 31, 2003. At December 31, 2003, APS had unused credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2003, APS had no outstanding commercial paper or bank borrowings. APS ended 2003 in an invested position.
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 2,360 MW of generating capacity from 2000 through 2004 are expected to be about $1.4 billion, of which $1.35 billion has been incurred
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through December 31, 2003. This does not reflect the proceeds from an anticipated sale in 2004 to SNWA of a 25% interest in the 570 MW Silverhawk Combined Cycle Plant 20 miles north of Las Vegas, Nevada, which would equal about $100 million (plus capitalized interest) of Pinnacle West Energy’s cumulative capital expenditures in the project. SNWA has agreed to purchase a 25% interest in the project upon completion. Such purchase is subject to an appropriation of funds by SNWA. Pinnacle West Energy’s capital requirements are currently funded 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 2003 and projected capital expenditures for the next three years.
See Note 3 and “Pinnacle West (Parent Company)” above for a discussion of the $500 million financing arrangement between APS and Pinnacle West Energy authorized by the ACC pursuant to the Financing Order.
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 2003 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings.
In 2003, SunCor acquired or issued $10 million in long-term debt, and redeemed, refinanced or repaid $1 million in long-term debt (see Note 6).
SunCor’s outstanding long and short-term debt was approximately $104 million as of December 31, 2003. SunCor’s total short-term debt was $86 million at December 31, 2003. SunCor had a $120 million line of credit, under which $50 million of short-term borrowings were outstanding at December 31, 2003. SunCor’s long-term debt, including current maturities, totaled $18 million at December 31, 2003.
We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2004 and 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.
APS Energy Services’ cash requirements during the past three years were funded with cash infusions from the parent company and with cash from operations. See the capital expenditures table above regarding APS Energy Services’ actual capital expenditures for 2003 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,
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expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $165 million of regulatory assets on the Consolidated Balance Sheets at December 31, 2003. See Notes 1 and 3 for more information about regulatory assets and APS’ general rate case.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the 2003 projected benefit obligation, our 2003 reported pension liability on the Consolidated Balance Sheets and our 2003 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on our Consolidated Statements of Income (dollars in millions):
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the 2003 accumulated other postretirement benefit obligation and our 2003
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reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on our Consolidated Statements of Income (dollars in millions):
See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)). See “Market Risks - Commodity Price Risk” below for quantitative analysis. See Note 18 for a further discussion on derivative and energy trading accounting.
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 “Market Risks - Commodity Price Risk” below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.
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OTHER ACCOUNTING MATTERS
Accounting for Derivative and Trading Activities
We adopted EITF 03-11 effective October 1, 2003. EITF 03-11 provides guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs, reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows.
We adopted EITF 02-3 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. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
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.
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 is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. (See Note 1 for more information regarding our previous accounting for removal costs.)
We determined that we have asset retirement obligations for our nuclear facilities (nuclear decommissioning) and certain other generation, transmission and distribution assets. On January 1, 2003, we recorded a liability of $219 million for our asset retirement obligations including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a regulatory liability of $40 million for our asset retirement obligations related to our regulated utility. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of
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Regulation” (see Note 1) and SFAS No. 143 (see Note 12). Adopting SFAS No. 143 had no impact on our Consolidated Statements of Income or our Consolidated Statements of Cash Flow.
Variable Interest Entities
See “Liquidity and Capital Resources - Off-Balance Sheet Arrangements” and Note 20 for discussion of VIEs.
FACTORS AFFECTING OUR FINANCIAL OUTLOOK
We believe APS’ general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3, in this rate case APS has requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by APS as part of the 1999 Settlement Agreement. In its filed testimony, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.
Wholesale Power Market Conditions
The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with its costs of serving retail customer demand. We moved this division to APS in early 2003 for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting APS’ transfer of generating assets to Pinnacle West Energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities. Based on the erosion in the market and on the market outlook, we currently expect contributions from our trading activities to be negligible for 2004, and approximately $10 million (pretax) annually thereafter.
Generation Construction Program
See “Liquidity and Capital Resources - Pinnacle West Energy” for information regarding Pinnacle West Energy’s generation construction program, which is nearing completion. The
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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 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 3.4% a year for the three years 2001 through 2003; we currently expect customer growth to average about 3.5% per year from 2004 to 2006. We currently estimate that total retail electricity sales in kilowatt-hours will grow 4.9% on average, from 2004 through 2006, before the retail effects of weather variations. The customer and sales growth referred to in this paragraph applies to Native Load customers. Customer growth for the year ended December 31, 2003 compared with the prior year period was 3.3%.
Retail Rate Changes As part of the 1999 Settlement Agreement, APS agreed to a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. The final price reduction was implemented July 1, 2003. See “1999 Settlement Agreement” in Note 3 for further information. In addition, the Company has requested a 9.8% retail rate increase to be effective July 1, 2004. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” in Note 3 for further information.
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. See “Natural Gas Supply” in Note 11 for more information on fuel costs.
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.
Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to existing utility plant and other property, changes in regulatory asset amortization and our generation construction program. 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 was placed in service in July 2003 and Silverhawk is expected to be in service in mid-2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):
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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 9.3% of assessed value for 2003 and 9.7% for 2002. We expect property taxes to increase primarily due to our generation construction program, as the plants phase-in to the property tax base over a five-year period, 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 accruing capitalized interest on a project when it is placed in commercial operation. As noted above, we placed new power plants in commercial operation in 2001, 2002 and 2003 and we expect to bring an additional plant on-line in 2004. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs. In addition, see Note 1 for a discussion of AFUDC.
Retail Competition The regulatory developments and legal challenges to the Rules discussed in Note 3 have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in 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, efforts to accelerate asset sales activities in 2003 were successful. A portion of these sales have been, and additional amounts may be required to be, reported as discontinued operations on our Consolidated Statements of Income. The annual earnings contribution from SunCor was $56 million after tax in 2003. See Note 22 for further discussion. We anticipate SunCor’s annual earnings contributions in 2004 and 2005 will be in the $30-$40 million range after tax.
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 after tax earnings of $16 million in 2003.
We expect SunCor and APS Energy Services to have combined earnings of approximately $10 million per year after tax beyond 2005.
El Dorado’s historical results are not necessarily indicative of future performance for El Dorado. In addition, we do not currently expect material losses related to NAC in the future.
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.
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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 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. On January 29, 2004, we entered into a fixed-for-floating interest rate swap transaction (see Note 6 for additional information). The nuclear decommissioning fund also has risk associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2003. The interest rates presented in the tables below represent the weighted-average interest rates for the year ended December 31, 2003 (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 instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk
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parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:
The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions in 2003 and 2002 (dollars in millions):
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The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2003 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Mark-to-Market Accounting,” for more discussion on our valuation methods.
Regulated Electricity
Marketing and Trading
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The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on the Consolidated Balance Sheets at December 31, 2003 (dollars in millions).
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 37% of our $237 million of risk management and trading assets as of December 31, 2003. See Note 1, “Mark-to-Market Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.
Risk Factors
Exhibit 99.1, which is hereby incorporated by reference, contains a discussion of risk factors affecting the Company.
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This document contains forward-looking statements based on current expectations, and we assume no obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “predict”, “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include, but are not limited to:
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ITEM 7A. QUANTITATIVE AND QUALITATIVEDISCLOSURES 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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS ANDFINANCIAL STATEMENT SCHEDULE
See Note 13 for the selected quarterly financial data required to be presented in this Item.
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MANAGEMENT’S REPORT ON INTERNAL CONTROLOVER FINANCIAL REPORTING
Management at Pinnacle West has always understood and accepted responsibility for our financial statements and related disclosures and the effectiveness of internal control over financial reporting (“internal control”). Just as we do throughout all aspects of our business, we continuously strive to identify opportunities to enhance the effectiveness and efficiency of internal control.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act will require our 2004 Annual Report to contain a management’s report and an independent accountants’ report regarding the effectiveness of internal control. However, in this 2003 Annual Report, we chose to voluntarily include this report on internal control. As a basis for our report, we tested and evaluated the design, documentation, and operating effectiveness of internal control.
In early March 2004, the PCAOB issued its auditing standard, which may require changes to the processes we utilize to test and evaluate the design, documentation, and operating effectiveness of internal control and may affect our future internal control disclosures. Based on our assessment as of December 31, 2003, we make the following assertion:
March 11, 2004
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INDEPENDENT ACCOUNTANTS’ REPORT
Board of Directors and StockholdersPinnacle West Capital CorporationPhoenix, Arizona
We have examined the accompanying management’s assertion that Pinnacle West Capital Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2003, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting. Our responsibility is to express an opinion on management’s assertion based on our examination.
Our examination was conducted in accordance with attestation standards established by the American Institute of Certified Public Accountants (“AICPA”) and, accordingly, included obtaining an understanding of the internal control over financial reporting, testing and evaluating the design and operating effectiveness of the internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion.
Because of inherent limitations in any internal control, misstatements due to error or fraud may occur and not be detected. Also, projections of any evaluation of the internal control over financial reporting to future periods are subject to the risk that the internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assertion that the Company maintained effective internal control over financial reporting as of December 31, 2003 is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
An examination of management’s assertion regarding the effectiveness of internal control under AICPA standards may not be the same in scope as an audit of internal control under the current proposed standards of the Public Company Accounting Oversight Board (the “PCAOB”) and, accordingly, may not necessarily result in the same conclusion or disclose all matters in internal control that might ultimately be noted in performing an audit under PCAOB standards when they are finally adopted. Accordingly, our examination of the accompanying Management’s Report on Internal Control Over Financial Reporting is not intended to comply with, and should not be relied upon for compliance with, the U.S. Securities and Exchange Commission rule relating to Section 404 or Section 103 of the Sarbanes-Oxley Act of 2002.
DELOITTE & TOUCHE LLP
Phoenix, Arizona
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INDEPENDENT AUDITORS’ REPORT
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2003 and 2002 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, 2003. Our audits also included the financial statement schedule listed in the Index. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic 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 2003 the Company changed its method of accounting for non-trading derivatives in order to comply with the provisions of Emerging Issues Task Force Issue No. 03-11,Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3.
As discussed in Note 18 to the consolidated financial statements, in 2002 the Company 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 the Company changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
Phoenix, ArizonaMarch 11, 2004
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PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED STATEMENTS OF INCOME(dollars and shares in thousands, except per share amounts)
See Notes to Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED BALANCE SHEETS(dollars in thousands)
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PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED STATEMENTS OF CASH FLOWS(dollars in thousands)
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PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY(dollars in thousands)
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PINNACLE WEST CAPTAL CORPORATIONNOTES 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 a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. 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 remained 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 unregulated 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, Idaho 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.
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. 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 account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires that
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entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.
Prior to the fourth quarter of 2002, we accounted for our trading activity at fair value, with changes in fair value reported in earnings as required by EITF 98-10 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” In the fourth quarter of 2002, we adopted EITF 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which rescinded EITF 98-10. 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. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy trading contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
See Note 18 for additional information about our derivative and energy trading accounting policies.
Under mark-to-market accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as current or long-term assets and liabilities from risk management and trading activities in the 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.
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
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adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.
The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. See Note 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.
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 the recovery of expected future costs in current customer rates.
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
As part of the 1999 Settlement Agreement with the ACC (see Note 3), we continue to amortize certain regulatory assets over an eight-year period as follows (dollars in millions):
The detail of regulatory assets is as follows (dollars in millions):
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The detail of regulatory liabilities is as follows (dollars in millions):
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:
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We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Prior to 2003, we charged removal costs, less salvage, to accumulated depreciation. Effective January 1, 2003, we applied the provisions of SFAS 143 (see Note 12).
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2003 were as follows:
For the years 2001 through 2003, the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 12.5%. The weighted-average rate was 3.35% for 2003, 3.35% for 2002 and 3.40% for 2001. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.
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.
Capitalized Interest
Capitalized interest represents the cost of debt funds used to finance construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. The rate used to calculate capitalized interest was a composite rate of 4.55% for 2003, 4.80% for 2002 and 6.13% for 2001. Capitalized interest ceases to accrue when construction is complete.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
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AFUDC was calculated by using a composite rate of 8.55% for 2003. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
In 2003, APS returned to the AFUDC method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This is consistent with APS returning to a vertically-integrated utility, as evidenced by APS’ recent general rate case filing, which includes the request for rate recognition of generation assets. Previously, APS capitalized interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” Although AFUDC both increases the plant balance and results in higher current earnings during the construction period, AFUDC is realized in future revenues through depreciation provisions included in rates. This change increased earnings by $11 million in 2003 as compared to what it would have been under SFAS No. 34.
Electric Revenues
We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. However, the determination and billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers since the date of the last meter reading and billing and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis in our 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.
We adopted EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provides guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows (see Note 18 for additional information).
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
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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. SunCor recognizes income only after the assets’ title has passed. 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. In addition, see Note 22 – Real Estate Activities – Discontinued Operations.
Percentage of Completion – NAC
Certain NAC contract revenues are accounted for under the percentage-of-completion method. These revenues are reported in other revenue on the Consolidated Statements of Income. 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
We consider all highly liquid investments 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.
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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 that method and the consolidated (and unitary) income tax liability is attributed to the parent company. See Note 4.
Reacquired Debt Costs
For debt related to the regulated portion of APS’ business, APS defers those gains and losses incurred upon early retirement and is seeking recovery in the APS general rate case (see Note 3). In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate the amortization of reacquired debt costs over an eight-year period that will end June 30, 2004. All regulatory asset amortization is included in depreciation and amortization expense in the 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 that, 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. In 2003, SunCor acquired two joint ventures for $10 million and consolidated $53 million of assets and $43 million of liabilities, which are included in the Consolidated Balance Sheets at December 31, 2003. The $10 million cash investment is included on the other investing line of the Consolidated Statements of Cash Flow at December 31, 2003. In addition, see Note 22 – Real Estate Activities – Discontinued Operations.
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.”
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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 2003 (dollars in thousands, except per share amounts):
In order to calculate the fair value of the 2003, 2002 and 2001 stock option grants and the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options:
See Note 16 for further discussion about our stock compensation plans.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets on our Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. The Company’s gross intangible assets (which are primarily capitalized software costs) were $237 million at December 31, 2003 and $214 million at December 31, 2002. The related accumulated amortization was $128 million at December 31, 2003 and $104 million at December 31, 2002. Amortization expense was
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$25 million in 2003, $21 million in 2002, and $22 million in 2001. Estimated amortization expense on existing intangible assets over the next five years is $28 million in 2004, $27 million in 2005, $25 million in 2006, $20 million in 2007, and $9 million in 2008. At December 31, 2003, the weighted average amortization period for intangible assets is 7 years.
2. Accounting Matters
See the following Notes for information about new accounting standards and other accounting matters:
3. Regulatory Matters
Electric Industry Restructuring
State
1999 Settlement Agreement
The following are the major provisions of the 1999 Settlement Agreement, as approved by the ACC:
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Retail Electric Competition Rules
The Rules approved by the ACC include the following major provisions:
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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 appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute.
Provider of Last Resort Obligation
Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is, under the Rules, the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows 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. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below for a discussion of retail rate adjustment mechanisms that were the subject of ACC hearings in April 2003.
Track A Order
On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things:
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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 the principles include, among other things, the following:
On August 27, 2003, APS, Pinnacle West and Pinnacle West Energy filed a lawsuit asserting damage claims relating to the Track A Order. Arizona Public Service Company et al. v. The State of Arizona ex rel., Superior Court of the State of Arizona, County of Maricopa, No. CV2003-016372.
Track B Order
On March 14, 2003, the ACC issued the Track B Order, which required APS to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003,
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PINNACLE WEST CAPITAL CORPORATIONNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS was 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. The ACC staff and an independent monitor participated in the Track B procurement process. The Track B Order also contains requirements relating to standards of conduct between APS and any affiliate of APS participating 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 by APS 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, the decision requires APS to prepare a report evaluating environmental issues relating to the procurement, and a series of workshops on environmental risk management will be commenced thereafter.
APS issued requests for proposals in March 2003 and, by May 6, 2003, APS entered into contracts to meet all or a portion of its requirements for the years 2003 through 2006 as follows:
ACC Financing Orders
On April 4, 2003, the ACC issued the Financing Order authorizing 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 (the “APS Loan”), subject to the following principal conditions:
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The ACC also ordered the ACC staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003,
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APS submitted its report on these matters to the ACC staff. The ACC has indicated that the preliminary investigation would be addressed in the pending general rate case (see below).
On May 12, 2003, APS issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to us to fund the repayment of a portion of the debt we incurred to finance the construction of the PWEC Dedicated Assets. See Note 6.
On November 22, 2002, the ACC issued an order approving APS’ request to permit APS to make short-term advances to Pinnacle West in the form of an interaffiliate line of credit in the amount of $125 million. As of December 31, 2003, there were no borrowings outstanding under this financing arrangement, and this authority expired on December 4, 2003.
APS General Rate Case and Retail Rate Adjustment Mechanisms
As noted above, on June 27, 2003, APS filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, to become effective July 1, 2004. In this rate case, APS updated its cost of service and rate design.
Major Components of the Request The major reasons for the request include:
Requested Rate Increase The requested rate increase totals $175.1 million, or 9.8%, and is comprised of the following items (dollars in millions):
Test Year The filing is based on an adjusted historical test year ended December 31, 2002.
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Cost of Capital The proposed weighted average cost of capital for the test year ended December 31, 2002 is 8.67%, including an 11.5% return on equity.
Rate Base The request is based on a rate base of $4.2 billion, calculated using Original Cost Less Depreciation (“OCLD”) methodology. The OCLD rate base approximates the ACC-jurisdictional portion of the net book value of utility plant, net of accumulated depreciation and deferred taxes, as of December 31, 2002, except as set forth below.
The requested rate base includes the PWEC Dedicated Assets, with a total combined capacity of approximately 1,800 MW. These assets were included at their estimated July 1, 2004 net book value. Upon approval of the request, the PWEC Dedicated Assets would be transferred to APS from Pinnacle West Energy.
The filing also includes calculated amounts for Fair Value Rate Base and Replacement Cost New Depreciated (“RCND”) rate base. The ACC is required by the Arizona Constitution to make a finding of Fair Value Rate Base, which has traditionally been defined by the ACC as the arithmetic average of OCLD rate base and RCND rate base.
Recovery of Previous $234 Million Write-Off The request includes recovery, over a fifteen year period, of the write-off of $234 million pretax of regulatory assets by APS as a result of the 1999 Settlement Agreement. See “1999 Settlement Agreement” above.
Estimated Timeline APS has asked the ACC to approve the requested rate increase by July 1, 2004. The ACC ALJ has issued a procedural schedule setting a hearing date on the application of May 25, 2004. Based on the schedule and existing ACC regulations, we believe the ACC will be able to make a decision in this general rate case by the end of 2004.
The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the Rules.
On November 4, 2003, the ACC approved the issuance of an order which authorizes a rate adjustment mechanism allowing APS to recover changes in purchased power costs (but not changes in fuel costs) incurred after July 1, 2004. The other rate adjustment mechanisms authorized in the 1999 Settlement Agreement (such as the costs associated with complying with the ACC electric competition rules) were also tentatively approved for subsequent implementation in the general rate case. The provisions of this order will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend, modify or reconsider, in its entirety, this November 4 order during the rate case.
Testimony As required by the procedural schedule, on February 3, 2004, the following parties filed their initial written testimony with the ACC on all issues except cost of service (i.e., cost allocation among customer classes) and rate design:
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ACC Staff Recommendations In its filed testimony, the ACC staff recommended, among other things, that the ACC:
The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard.
The ACC staff also submitted testimony indicating that APS and its affiliates had violated the “spirit, if not the letter” of the Rules, the Code of Conduct and the 1999 Settlement Agreement.
RUCO Recommendations In its filed testimony, RUCO recommended, among other things, that the ACC:
APS believes that its rate request is necessary to ensure APS’ continued ability to reliably serve one of the fastest growing regions in the country and views any ultimate decision that would deny recovery of the Company’s investment in the PWEC Dedicated Assets as constituting a
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regulatory “taking.” APS will vigorously oppose the recommendations of the ACC staff, RUCO, and other parties offering similar recommendations.
Request for Proposals
In early December 2003, APS issued a request for proposals (“RFP”) for long-term power supply resources, and on January 8, 2004, an ACC Administrative Law Judge issued an order requiring, among other things, APS to file a summary of the proposals with the ACC. On January 27, 2004, APS filed a summary of the proposals with the ACC. APS is negotiating with certain of the parties that submitted proposals.
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 adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule. On April 28, 2003, the FERC Staff issued an additional white paper on the proposed Standard Market Design. The white paper discusses several policy changes to the proposed Standard Market Design, including a greater emphasis on flexibility for regional needs. We cannot currently predict what, if any, impact there may be to the Company if the FERC adopts the proposed rule or any modifications proposed in the comments.
The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in 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.
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
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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 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. In 2003, we resolved certain prior-year issues with the taxing authorities and recorded an $18 million tax benefit associated with tax credits and other reductions to income tax expense.
The components of income tax expense for income from continuing operations are as follows (dollars in thousands):
The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
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The following table sets forth the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
The components of the net deferred income tax liability were as follows (dollars in thousands):
5. Lines of Credit and Short-Term Borrowings
APS had committed lines of credit with various banks of $250 million at December 31, 2003 and 2002, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The current line matures in May 2004, and the document allows for a 364-day extension of the termination date without lender consent. The commitment fees at December 31, 2003 and 2002 for these lines of credit were 0.175% and 0.09% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2003 and 2002.
APS had no commercial paper borrowings outstanding at December 31, 2003 and 2002. By Arizona statute, APS’ short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC.
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Pinnacle West had committed lines of credit of $275 million at December 31, 2003 and $475 million at December 31, 2002, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The current lines mature in November and December of 2004 and the $150 million facility allows for a 364-day extension of the termination date without lender consent. Pinnacle West had no outstanding borrowings at December 31, 2003 and $72 million was outstanding at December 31, 2002. The commitment fees ranged from 0.125% to 0.175% in 2003 and ranged from 0.10% to 0.15% in 2002. Pinnacle West had no commercial paper borrowings outstanding at December 31, 2003. Commercial paper borrowings outstanding were $24 million at December 31, 2002. The weighted average interest rate on commercial paper borrowings was 2.06% for the year ended December 31, 2002.
All APS and Pinnacle West bank lines of credit and commercial paper agreements are unsecured.
On November 22, 2002, the ACC approved APS’ request to permit APS to make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million. This interim loan matured in December 2003, and there were never any borrowings on this line.
SunCor had revolving lines of credit totaling $120 million at December 31, 2003 and $140 million at December 31, 2002. The commitment fees were 0.125% in 2003 and 2002. SunCor had $50 million outstanding at December 31, 2003 and $126 million outstanding at December 31, 2002. The weighted-average interest rate was 4.50% at December 31, 2003 and was 3.75% at December 31, 2002. Interest for 2003 and 2002 was based on LIBOR plus 2% or prime plus 0.5%. The balance is included in short-term debt on the Consolidated Balance Sheets. SunCor had other short-term loans in the amount of $36 million at December 31, 2003 and $6 million outstanding at December 31, 2002. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2003 and 2002. In addition, two notes acquired in 2003 had interest rates of 3.37% and 3.87%.
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 short and long-term 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, 2003 and 2002 (dollars in thousands):
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Pinnacle West’s and APS’ debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet the covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for each of the Company and APS individually. At December 31, 2003, the ratio was approximately 54% for Pinnacle West. At December 31, 2003, the ratio was approximately 53% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. Based on 2003 results, the coverages were approximately 4 times for the Company, 4 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.
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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.
The following is a list of payments due on total long-term debt and capitalized lease requirements through 2008:
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, 2003, 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.
The mortgage currently constitutes a lien on substantially all of the property of APS. We anticipate that in early April 2004, all first mortgage bonds issued by APS under its existing mortgage and deed of trust, other than the first mortgage bonds securing APS’ senior notes, will have been paid and retired. At that time, APS’ obligation to make payment on the first mortgage bonds securing the senior notes will also be deemed to be satisfied and discharged and the senior note first mortgage bonds will cease to secure the senior notes. APS is then obligated to take all steps necessary to terminate its existing mortgage and deed of trust and cannot issue any additional first mortgage bonds under that mortgage.
7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2003, 2002 and 2001 is as follows (dollars in thousands):
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8. Retirement Plans and Other Benefits
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 plan for all new employees in place of the defined benefit plan, and, as of April 1, 2003, the plan was offered as an alternative to the defined benefit plan for all existing employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all of our employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by 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.
Pinnacle West also 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.
In December 2003, FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to enhance disclosures of relevant accounting information by
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providing additional information on plan assets, obligations, cash flows, and net cost. The revisions are reflected in this Note. Pinnacle West uses a December 31 measurement date for its plans.
On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug costs. We have not yet quantified the effect, if any, on accumulated projected benefit obligation or the net periodic postretirement benefit cost in our financial statements and accompanying notes. Specific accounting guidance for this subsidy, including transition rules, is pending.
The following table provides details of the plan’s benefit costs. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants (dollars in thousands):
The following table sets forth the plan’s change in the benefit obligations for the plan years 2003 and 2002 (dollars in thousands):
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The following table sets forth the qualified defined benefit plan and other benefit plan changes in the fair value of plan assets for the years 2003 and 2002 (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, 2003 and 2002 (dollars in thousands):
The following sets forth the details related to benefits included on the Consolidated Balance Sheets (dollars in thousands):
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The following table sets forth the other comprehensive income arising from the change in additional minimum liability for the years ended December 31, 2003 and 2002 (dollars in thousands):
The following table sets forth the projected benefit obligation and the accumulated benefit obligation for pension plans in excess of plan assets for the plan years 2003 and 2002 (dollars in thousands):
Below are the weighted-average assumptions for both the pension and other benefits used to determine each respective benefit obligation and net periodic benefit cost:
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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. For the year 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 conditions. For the year 2004 we are assuming a 9% rate of return on plan assets. This rate is reflective of the market returns earned historically on our target asset allocation. As recent history has demonstrated, markets may decline and increase dramatically. However, the long-term rate of return on plan assets of 9% is reasonable given our asset allocation in relation to historical and expected future performance.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
Plan Assets
Pinnacle West’s qualified pension plan asset allocation at December 31, 2003, and 2002 is as follows:
The Board of Directors has established an investment policy for the pension plan assets and has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with a stated tolerance of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.
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Pinnacle West’s other postretirement benefit plan asset allocation at December 31, 2003, and 2002, is as follows:
The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the postretirement benefit plans. The investment policy for other post retirement benefit plan assets is similar to that of the pension plan assets described above.
Contributions
Under current law, we are required to contribute approximately $100 million to our pension plans in 2004 and expect to contribute approximately $50 million to our other postretirement benefit plans in 2004. If currently pending legislation is enacted, our required pension contribution in 2004 would decrease to the $25 to $50 million range.
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and subsidiaries. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account. Under this plan, the Company matches a percentage of the participants’ contributions in the form of Pinnacle West stock. After a five year vesting period, participants have an option to transfer the Company matching contributions out of the Pinnacle West Stock Fund to other investment funds within the plan. At December 31, 2003, approximately 23% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately $5 million for each of the years 2003, 2002 and 2001.
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
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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.
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 $67 million in 2003, $67 million in 2002 and $59 million in 2001.
The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2004 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, 2003 was $5 million.
Estimated future minimum lease payments for our operating leases are approximately as follows (dollars in millions):
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, 2003. APS’ share of operating and maintaining these facilities is included in the Consolidated Statements of Income in operations and maintenance expense (dollars in thousands):
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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. In February 2004, Enron filed an adversary proceeding against APS in bankruptcy court regarding differences in the valuation of trading positions involving APS. Enron North America v. Arizona Public Service Company, Adversary Proceeding No. 04-02366 (ALJ). APS will vigorously defend this action and does not believe it will have any material adverse impact on its anticipated exposure to Enron described above.
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Spent Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. Arizona Public Service Company v. United States of America, United States Court of Federal Claims, 03-2832C.
In February 2002, the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the President’s recommendation. Congress approved the Yucca Mountain site, overriding the Nevada veto. It is now expected that the DOE will submit a license application to the NRC in late 2004. The State of Nevada has filed several lawsuits relating to the Yucca Mountain site. We cannot currently predict what further steps will be taken in this area.
APS has existing fuel storage pools at Palo Verde and is operating a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, 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 2003 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, 2003, APS had spent $7 million and recorded a liability of $42 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. APS has recorded a corresponding regulatory asset of $49 million and is seeking recovery of these costs through future rates (see “APS General Rate Case and Retail Rate Mechanisms” in Note 3).
APS has reclassified prior year spent nuclear fuel costs of approximately $44 million previously included in accumulated amortization of nuclear fuel to the liability for asset retirements and removals on our Consolidated Balance Sheets at December 31, 2002. Upon adoption of SFAS No. 143 in 2003, APS reclassified this liability to a regulatory liability because no legal obligation for removal exists.
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APS believes that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, APS acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which APS is less able to predict. APS expects to vigorously protect and pursue its rights related to this matter.
Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $10 million per incident. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. 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 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 2004 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $209 million in 2004; $68 million in 2005; $66 million in 2006; $51 million in 2007; $51 million in 2008 and $461 million thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
Of the various purchased power and fuel contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for the supply of its coal and nuclear fuel supply have take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2016. The current take-or-pay nuclear fuel contracts expire in 2004 and had not been renewed as of December 31, 2003.
The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions):
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Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. Our coal mine reclamation obligation was $60 million at December 31, 2003 and $59 million at December 31, 2002 and is included in deferred credits-other in the 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. 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. The FERC is still considering the evidence and refund amounts have not yet been finalized. 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.
The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Court of Appeals (Ninth Circuit).
Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.
On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its Staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions
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that allegedly violated certain provisions of the ISO tariff. APS and the FERC staff have settled this matter, and the settlement was approved by the FERC.
SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO. PG&E filed for bankruptcy protection in 2001.
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 a 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 California independent system operator markets, including APS, attempting 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, which has now been moved back to state court. James Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court, Case No. 407867. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California
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unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against 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 motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations or liquidity.
Citizens 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 the 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.
Consolidated capital expenditures in 2004 are estimated to be (dollars in millions):
APS and Pinnacle West Energy purchase the majority of their natural gas requirements for their gas-fired plants under contracts with a number of natural gas suppliers. Effective September 1, 2003, APS’ and Pinnacle West Energy’s natural gas supply is transported pursuant to a firm, contract demand service agreement with El Paso Natural Gas Company. Pursuant to the terms of a comprehensive settlement entered into in 1996, the rates charged for transportation are subject to a 10-year rate moratorium extending through December 31, 2005.
Prior to September 1, 2003, APS’ and Pinnacle West Energy’s natural gas supply was transported pursuant to a firm, full requirements transportation service agreement. On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement by requiring all firm, full requirements contract holders to convert to contract demand service agreements effective September 1, 2003. This required conversion has imposed additional
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limitations on the former full requirements contract holders’ ability to nominate firm transportation capacity. In order for APS and Pinnacle West Energy to meet their natural gas supply and capacity requirements, they must make market purchases, which we expect to increase costs by approximately $5 million per year for natural gas supply and by approximately $14 million per year for capacity. APS and Pinnacle West Energy have sought appellate review of the FERC’s July 9 order and related issues on the grounds that the FERC decision to abrogate the full requirements contracts is arbitrary and capricious and is not supported by substantial evidence.Arizona Public Service Company and Pinnacle West Energy Corporation v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1209. This petition for review was consolidated with a petition filed by the ACC and other full requirements contract holders.Arizona Corporation Commission et al v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1206. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements.
Litigation
We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our consolidated financial statements, results of operations or liquidity.
On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The standard requires that these liabilities be recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Prior to January 1, 2003, we accrued asset retirement obligations over the life of the related asset through depreciation expense.
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term. Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets. The asset retirement obligations associated with our non-regulated assets are immaterial.
On January 1, 2003 and in accordance with SFAS No. 143, APS recorded a liability of $219 million for its asset retirement obligations, including the accretion impacts; a $67 million increase in
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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, APS recorded a net regulatory liability of $40 million for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. APS believes it can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. The adoption of SFAS No. 143 did not have a material impact on our net income for the year ended December 31, 2003.
APS has reclassified prior year removal costs of approximately $557 million previously included in accumulated depreciation to the liability for asset retirements and removals on our Consolidated Balance Sheets. In 2003, APS reclassified the portion of this liability for which no legal obligation for removal exists to a regulatory liability.
In accordance with SFAS No. 71, APS will continue to accrue for removal costs for its regulated assets, even if there is no legal obligation for removal. At December 31, 2003, regulatory liabilities shown on our Consolidated Balance Sheets included approximately $480 million of estimated future removal costs that are not considered legal obligations.
The following schedule shows the change in our asset retirement obligations during the twelve-month period ended December 31, 2003 (dollars in millions):
The following schedule shows the change in our pro forma liability for the years ended December 31, 2002 and 2001, as if we had recorded an asset retirement obligation based on the guidance in SFAS No. 143 (dollars in millions):
The pro forma effects on net income for 2002 and 2001 are immaterial.
To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and domestic equity securities and classifies them as available for sale. The following
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table shows the cost and fair value of APS’ nuclear decommissioning trust fund assets which are on the Consolidated Balance Sheets at December 31, 2003 and December 31, 2002 (dollars in millions):
Consolidated quarterly financial information for 2003 and 2002 is as follows (dollars in thousands, except per share amounts):
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Income From ContinuingOperations – EPS:
Net Income – EPS:
We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2003 and 2002 due to their short maturities.
We hold investments in fixed income and domestic equity securities for purposes other than trading. The December 31, 2003 and 2002 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.
On December 31, 2003, the carrying value of our long-term debt (excluding capitalized lease obligations) was $3.32 billion, with an estimated fair value of $3.46 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $3.00 billion on December 31, 2002, with an estimated fair value of $3.21 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
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Dilutive stock options increased average common shares outstanding by approximately 140,000 shares in 2003, 61,000 shares in 2002 and 212,000 shares in 2001. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 91,405,134 shares in 2003, 84,963,921 shares in 2002 and 84,930,140 shares in 2001.
Options to purchase 2,291,646 shares of common stock were outstanding at December 31, 2003 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 1,629,958 at December 31, 2002 and 212,562 at December 31, 2001.
Pinnacle West offers stock-based compensation plans for officers and key employees of the 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 share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.
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The 1994 plan and the 1985 plan each include outstanding options but no new options will be granted under either plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents. Following the approval of the 2002 plan, no further grants have been made under the 1994 plan, except for awards for the annual award of up to 20,000 shares of stock to satisfy stock award obligations under employment contracts to certain executives.
In the third quarter of 2002, 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 $2.1 million in stock option expense before income taxes in our Consolidated Statements of Income in 2003 and approximately $0.5 million in 2002. This amount may not be reflective of the stock option expense we will record in future years because stock options typically vest over several years and additional grants are generally made each year.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” The standard amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. The standard also amends the disclosure requirements of SFAS No. 123. SFAS No. 148 is effective for fiscal years ending after December 15, 2002. We adopted the disclosure requirements in 2002. See Note 1 for our pro forma disclosures on stock-based compensation and our weighted-average assumptions used to calculate the fair value of our stock options.
Total stock-based compensation cost, including stock option cost, was $6 million in 2003, $5 million in 2002 and $3 million in 2001.
The following table is a summary of the status of our stock option plans as of December 31, 2003, 2002 and 2001 and changes during the years ending on those dates:
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The following table summarizes information about our stock options at December 31, 2003:
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, 2003, 2002 and 2001:
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The amounts in our other segment include activity principally related to El Dorado’s investment in NAC, as well as the parent company and other subsidiaries. See Note 18 for information about reclassifications related to the adoption of EITF 03-11. Financial data for the years ended December 31, 2003, 2002 and 2001 by business segments is provided as follows (dollars in millions):
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We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria is met, in common stock equity (as a component of other comprehensive income (loss)). We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.
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In 2001, we recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income (loss)), both as cumulative effects of a change in accounting for derivatives. The charge primarily resulted from electricity option contracts. The credit resulted from unrealized gains on cash flow hedges.
During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts, and on January 1, 2003 for existing contracts, with early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. 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. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. Derivative instruments used for non-trading activities are accounted for in accordance with SFAS No. 133.
Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the 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 other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Certain of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. Derivatives associated with trading activities are adjusted to fair value through income.
EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Previous guidance under EITF 98-10 permitted physically-settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the 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
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revenues and purchased power and fuel costs, but did not have any impact on our financial condition, net income or cash flows.
We adopted EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provided guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs, reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows. Following are the net reclassifications to our previously reported amounts (dollars in thousands):
In November 2003, the FASB revised its derivative guidance in DIG Issue No. C15, “Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” Effective January 1, 2004, the new guidance changes the criteria for the normal purchases and sales scope exception for electricity contracts. We do not expect this guidance to have a material impact on our financial statements.
In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The provisions of SFAS No. 149 that relate to previously issued SFAS No. 133 derivatives implementation guidance should continue to be applied in accordance with the effective dates of the original implementation guidance. In general, other provisions are applied prospectively to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The impact of this standard was immaterial to our financial statements.
The changes in the fair value of our hedged positions included in the Consolidated Statements of Income for the years ended December 31, 2003 and 2002 are comprised of the following (dollars in thousands):
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As of December 31, 2003, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately five years. During the year ending December 31, 2004, we estimate that a net gain of $8 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.
Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments:
The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2003 and 2002 (dollars in thousands):
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Cash or collateral may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties is $1 million at December 31, 2003 and $5 million at December 31, 2002, and is included in investments and other assets on the Consolidated Balance Sheet. Collateral provided to us by counterparties is $12 million at December 31, 2003 and $22 million at December 31, 2002, and is included in other deferred credits on the Consolidated Balance Sheet.
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 37% of our $237 million of risk management and trading assets as of December 31, 2003. 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 Note 1 “Mark-to-Market Accounting” for a discussion of our credit valuation adjustment policy.
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The following table provides detail of other income and other expense for the years ended December 31, 2003, 2002 and 2001 (dollars in thousands):
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On January 1, 2003, we adopted FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure provisions were effective for the year ended December 31, 2002. The initial recognition and measurement provisions of FIN No. 45 were effective on a prospective basis to guarantees issued or modified after December 31, 2002.
We have 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 offer commodity energy and energy-related products and enable El Dorado to support the activities of NAC. 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, 2003 are as follows (dollars in millions):
At December 31, 2003, we had entered into approximately $41 million of letters of credit which support various construction agreements. These letters of credit expire in 2004 and 2005. We intend to provide from either existing or new facilities for the extension, renewal or substitution of
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the letters of credit to the extent required. At December 31, 2003, Pinnacle West has approximately $4 million of letters of credit related to workers’ compensation expiring in 2004.
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2003, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit have expiration dates in 2004 and 2005. APS has also entered into approximately $109 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 expiring in 2004. 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.
We provide indemnifications relating to liabilities arising from or related to certain of our agreements. APS has 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.
Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on our Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Among other guidance, SFAS No. 144 prescribes accounting for discontinued operations and defines certain activities as discontinued operations. We adopted SFAS No. 144 effective January 1, 2002 and determined that activities that would have required discontinued operations reporting in 2002 and 2001 were immaterial.
In 2003, SunCor sold its water utility company, which resulted in an after-tax gain of $8 million ($14 million pretax). The amounts of the gain on the sale and operating income of the water utility company in 2003 and 2002 are classified as discontinued operations on our Consolidated Statements of Income. The amounts related to 2001 were immaterial for reclassification.
In the second quarter of 2002, SunCor sold a retail center, but maintained a continuing involvement through a management contract. In the first quarter of 2003, this management contract was canceled. As a result, the after-tax gain of $6 million ($10 million pre-tax) recorded in operations in 2002 related to this property was reclassified as discontinued operations on our Consolidated Statements of Income. The income from discontinued operations in the year ended December 31, 2002 primarily reflects this sale. The amounts related to 2001 were immaterial for reclassification.
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In the fourth quarter of 2003, SunCor sold a retail center, which resulted in an after-tax gain of $2 million ($3 million pretax). The gain on the sale and the operating income related to this property in 2003 are classified as discontinued operations on our Consolidated Statements of Income. There were no prior-year operations related to this retail center. The amounts related to 2001 were immaterial for reclassification.
The following table provides SunCor’s revenue and income before income taxes related to properties classified as discontinued operations on our consolidated statements of income for the years ended December 31, 2003 and 2002 (dollars in thousands):
The following tables provide the amounts related to properties of discontinued operations which were reclassified to assets and liabilities held for sale on the Consolidated Balance Sheets at December 31, 2003 and 2002 (dollars in thousands):
See Note 17 for information related to the real estate segment.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
(b) Change in Internal Control over Financial Reporting
No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVEOFFICERS 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 19, 2004 (the “2004 Proxy Statement”) and to the Supplemental Item – “Executive Officers of the Registrant” in Part I of this report.
The Company has adopted a Code of Ethics for Financial Professionals that applies to professional employees in the areas of finance, accounting, internal audit, energy risk management, marketing and trading financial control, tax, investor relations, and treasury and also includes the Company’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at the Company’s subsidiaries. The Code of Ethics for Financial Professionals is posted on the Company website at www.pinnaclewest.com. The Company intends to satisfy the requirements under Item 10 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by posting such information on the Company’s website.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to “The Board and its Committees – How are Directors compensated?”; “Performance Graph”; and “Executive Compensation” in the 2004 Proxy Statement.
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ITEM 12. SECURITY OWNERSHIP OFCERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND 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 2004 Proxy Statement.
Securities Authorized For Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2003 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, under which no new options and a limited number of other stock awards may be granted; 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.
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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 and 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 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
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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. 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 2004 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANTFEES AND SERVICES
Reference is hereby made to “Audit Matters – What Fees Were Paid to Our Independent Accountants in 2003 and 2002?” and “– What are the Audit Committee’s pre-approval policies?” in the 2004 Proxy Statement.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENTSCHEDULES, 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
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In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
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aManagement contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
bReports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
cAn additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
dAdditional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.
Reports on Form 8-K
During the quarter ended December 31, 2003, and the period ended March 15, 2004, the Company filed the following Reports on Form 8-K:
Report dated September 30, 2003 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7 and Item 9).
Report dated October 6, 2003 regarding earnings outlook and slides presented at analysts and investors meetings (Item 5, Item 7 and Item 9).
Report dated November 5, 2003 containing a financial statement reclassification and relating to the ACC approval of the issuance of a rate adjustment mechanism order. This Current Report on Form 8-K includes the consolidated balance sheets of Pinnacle West as of December 31, 2002 and
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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. Schedule II – Valuation and Qualifying Accounts is also included (Item 5).
Report dated November 6, 2003 comprised of exhibits to Registration Statement No. 333-101457 (Item 7).
Report dated December 31, 2003 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7 and Item 9).
Report dated January 8, 2004 regarding a delay in the schedule for the hearing for APS’ pending general rate case (Item 5 and Item 7).
Report dated January 27, 2004 regarding APS’ Summary of Responses Received to its Power Supply Resource Request for Proposals dated December 3, 2003 (Item 5 and Item 7).
Report dated January 30, 2004 containing exhibits comprised of a slide presentation for use at an analyst conference (Item 7 and Item 9).
Report dated February 3, 2004 regarding the ACC Staff’s and RUCO’s initial written testimony filed with the ACC (Item 5).
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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.
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.
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INDEX TO EXHIBITS
For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14.