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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______ TO ______
COMMISSION FILE NUMBER 1-8962
PINNACLE WEST CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
ARIZONA 86-0512431
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
400 North Fifth Street, P.O. Box 53999 (602) 250-1000
Phoenix, Arizona 85072-3999 (Registrant's telephone number,
(Address of principal executive including area code)
offices,
including zip code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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Name Of Each Exchange On
Title Of Each Class Which Registered
- --------------------------------------------------------------------------------
Common Stock, New York Stock Exchange
No Par Value Pacific Stock Exchange
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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 [ ]
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 [ ]
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: $3,348,326,875 as of June 28, 2002
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 21, 2003 are incorporated by reference
into Part III hereof.
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TABLE OF CONTENTS
PAGE
GLOSSARY..................................................................... 1
PART I
Item 1. Business.......................................................... 4
Item 2. Properties........................................................ 22
Item 3. Legal Proceedings................................................. 27
Item 4. Submission of Matters to a Vote of Security Holders............... 27
Supplemental Item.
Executive Officers of the Registrant.............................. 28
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters............................................. 30
Item 6. Selected Consolidated Financial Data.............................. 31
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 35
Item 7A. Quantitative and Qualitative Disclosures about Market Risk........ 71
Item 8. Financial Statements and Supplementary Data....................... 73
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure........................................139
PART III
Item 10. Directors and Executive Officers of the Registrant................139
Item 11. Executive Compensation............................................139
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters...................................139
Item 13. Certain Relationships and Related Transactions....................141
Item 14. Controls and Procedures...........................................142
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..142
SIGNATURES...................................................................173
i
GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ADEQ - Arizona Department of Environmental Quality
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 - the Company's Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
FIN - FASB Interpretation
Financing Application - APS application filed with the ACC on September 16, 2002
FIP - Federal Implementation Plan
Fitch - Fitch, Inc.
Four Corners - Four Corners Power Plant
GAAP - accounting principles generally accepted in the United States of America
Interim Financing Application - APS application filed with the ACC on November
8, 2002
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
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
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
SMD - standard market design
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
System - non-trading energy related activities
T&D - transmission and distribution
2
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
3
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. APS is an electric utility that
provides either retail or wholesale electric service to substantially all of the
state of Arizona, with the major exceptions of the Tucson metropolitan area and
about one-half of the Phoenix metropolitan area. Electricity is delivered
through a distribution system owned by APS. APS also generates, sells and
delivers electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our competitive
electricity generation operations;
* APS Energy Services, which provides competitive commodity-related
energy services (such as direct access commodity contracts, energy
procurement and energy supply consultation) and energy-related
products and services (such as energy master planning, energy use
consultation and facility audits, cogeneration analysis and
installation and project management) to commercial, industrial and
institutional retail customers in the western United States;
* SunCor, a developer of residential, commercial and industrial real
estate projects in Arizona, New Mexico and Utah; and
* El Dorado, which owns a majority interest in NAC (specializing in
spent nuclear fuel technology) and holds miscellaneous small
investments, including interests in Arizona community-based ventures.
We discuss each of these subsidiaries in greater detail below.
MARKETING AND TRADING
In early 2003, we moved our marketing and trading division from Pinnacle
West to APS for future marketing and trading activities (existing wholesale
contracts will remain at Pinnacle West) as a result of the ACC's Track A Order
prohibiting the previously required transfer of APS' generating assets to
Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" below).
The marketing and trading division sells, in the wholesale market, APS and
Pinnacle West Energy generation output that is not needed for APS' Native Load,
which includes loads for retail customers and traditional cost-of-service
wholesale customers. The division focuses primarily on managing APS' purchased
power and fuel risks in connection with its costs of serving retail customer
energy requirements. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors Affecting Our Financial Outlook"
in Item 7 for a discussion of APS' implementation of an
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ACC-mandated process by which APS must competitively procure energy.
Additionally, the marketing and trading division, subject to specific
parameters, markets, hedges and trades in electricity, fuels and emission
allowances and credits. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in Item 7 for information about the
historical and prospective contribution of the marketing and trading activities
to our financial results.
BUSINESS SEGMENTS
We have three principal business segments (determined by products, services
and the regulatory environment):
* our regulated electricity segment (76% of operating revenues in 2002),
which consists of regulated traditional retail and wholesale
electricity businesses and related activities, and includes
electricity transmission, distribution and generation;
* our marketing and trading segment (12% of operating revenues in 2002),
which consists of our competitive energy business activities,
including wholesale marketing and trading and APS Energy Services'
commodity-related energy services; and
* our real estate segment (9% of operating revenues in 2002), which
consists of SunCor's real estate development and investment
activities.
See Note 17 of Notes to Consolidated Financial Statements in Item 8 for
financial information about our business segments.
EMPLOYEES
At December 31, 2002, we employed about 7,200 people, including the
employees of our subsidiaries. Of these employees, about 5,100 were employees of
our major subsidiary, APS, and employees assigned to jointly-owned generating
facilities for which APS serves as the generating facility manager. About 2,100
people were employed by Pinnacle West and our other subsidiaries. Our principal
executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004
(telephone 602-250-1000).
OVERVIEW OF ARIZONA REGULATORY DEVELOPMENTS
As discussed in "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors Affecting Our Financial Outlook"
in Item 7, we believe pending Arizona regulatory matters are among the key
factors affecting our financial outlook.
GENERAL
On September 21, 1999, the ACC approved Rules that provided a framework for
the introduction of retail electric competition in Arizona. On September 23,
1999, the ACC approved a comprehensive settlement agreement among APS and
various parties related to the implementation of retail electric competition in
Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was
required to transfer all of its competitive electric assets and services to an
unaffiliated party or parties or to a separate corporate affiliate or affiliates
no later than December 31, 2002. Consistent with that requirement, APS had been
addressing the legal and regulatory requirements necessary to complete the
transfer of its generation assets to Pinnacle West Energy on or before that
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date. On September 10, 2002, the ACC issued the Track A Order, which, among
other things, directed APS not to transfer its generation assets to Pinnacle
West Energy. See Note 3 of Notes to Consolidated Financial Statements in Item 8
for additional information about the 1999 Settlement Agreement, the Rules
(including legal challenges to the Rules) and the Track A Order.
APS FINANCING APPLICATION
On September 16, 2002, APS filed an application with the ACC requesting the
ACC to allow APS to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to the Company; to guarantee up to $500 million of
Pinnacle West Energy's or the Company's debt; or a combination of both, not to
exceed $500 million in the aggregate. In its application, APS stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between APS and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing that we
provided to fund the construction of Pinnacle West Energy generation assets or
from effectively competing in the wholesale markets. On March 27, 2003, the ACC
authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up
to $500 million of Pinnacle West Energy debt or a combination of both, not to
exceed $500 million in the aggregate. See "ACC Applications" in Note 3 of Notes
to Consolidated Financial Statements in Item 8 for additional information.
COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that APS competitively procure certain power
requirements. On March 14, 2003, the ACC issued the Track B Order, which
documented the decision made by the ACC at its open meeting on February 27,
2003, addressing this requirement. Under the order, APS will be required to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, APS will be required to solicit competitive
bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or
approximately 20% of APS' total retail energy requirements. The bid amounts are
expected to increase in 2004 and 2005 based largely on growth in APS' retail
load and APS' retail energy sales. The Track B Order also confirmed that it was
"not intended to change the current rate base status of [APS'] existing assets."
The order recognizes APS' right to reject any bids that are unreasonable,
uneconomical or unreliable.
APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements. See "Track B Order" in Note 3 of
Notes to Consolidated Financial Statements in Item 8 for additional information.
APS GENERAL RATE CASE
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
APS will file a general rate case with the ACC. In this rate case, APS will
update its cost of service and rate design. In addition, APS expects to seek:
6
* rate base treatment of certain power plants currently owned by
Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
Phoenix Units 4 and 5 and Saguaro Unit 3);
* recovery of the $234 million pretax asset write-off recorded by APS as
a result of the 1999 Settlement Agreement; and
* recovery of costs incurred by APS in preparation for the previously
required transfer of generation assets to Pinnacle West Energy.
We assume that the ACC will make a decision in this general rate case by the end
of 2004.
AVAILABLE INFORMATION
We make available free of charge on or through our Internet website
(www.pinnaclewest.com) our Annual Report on Form 10-K, Quarterly Reports on Form
10-Q, Current Reports on Form 8-K and, if applicable, amendments to those
reports filed or furnished pursuant to Section 13(a) of the Securities Exchange
Act of 1934 as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. The information on our website is not
part of this report.
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current
expectations and we assume no obligation to update these statements or make any
further statements on any of these issues, except as required by applicable law.
Because actual results may differ materially from expectations, we caution
readers not to place undue reliance on these statements. A number of factors
could cause future results to differ materially from historical results, or from
results or outcomes currently expected or sought by us. These factors include
the ongoing restructuring of the electric industry, including the introduction
of retail electric competition in Arizona and decisions impacting wholesale
competition; the outcome of regulatory and legislative proceedings relating to
the restructuring; state and federal regulatory and legislative decisions and
actions, including price caps and other market constraints imposed by the FERC;
regional economic and market conditions, including the California energy
situation and completion of generation and transmission construction in the
region, which could affect customer growth and the cost of power supplies; the
cost of debt and equity capital and access to capital markets; weather
variations affecting local and regional customer energy usage; the effect of
conservation programs on energy usage; power plant performance; the successful
completion of our generation construction program; regulatory issues associated
with generation construction, such as permitting and licensing; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); our ability to manage our marketing and trading activities
and the use of derivative contracts in our business; technological developments
in the electric industry; the performance of the stock market, which affects the
amount of our required contributions to our pension plan and nuclear
decommissioning trust funds; the strength of the real estate market in SunCor's
market areas, which include Arizona, New Mexico and Utah; and other
uncertainties, all of which are difficult to predict and many of which are
beyond our control.
7
REGULATION AND COMPETITION
RETAIL
The ACC regulates APS' retail electric rates and its issuance of
securities. The ACC must also approve any transfer of APS' utility property and
certain transactions between APS and affiliated parties. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Factors Affecting Our Financial Outlook" in Item 7 and Note 3 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the status of
electric industry restructuring in Arizona.
APS is subject to varying degrees of competition from other utilities in
Arizona (such as Tucson Electric Power Company, Southwest Gas Corporation and
Citizens Communications Company) as well as cooperatives, municipalities,
electrical districts and similar types of governmental organizations
(principally Salt River Project). APS also faces competition from low-cost
hydroelectric power and parties that have access to low-priced preferential
federal power and other subsidies. In addition, some customers, particularly
industrial and large commercial customers, may own and operate facilities to
generate their own electric energy requirements. Although some very limited
retail competition existed in APS' service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to APS' customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter APS' service territory. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.
WHOLESALE
GENERAL
The FERC regulates rates for wholesale power sales and transmission
services. During 2002, approximately 20% of our electric operating revenues
resulted from such sales and services. In early 2003, we moved our marketing and
trading division from Pinnacle West to APS for all future marketing and trading
activities (existing wholesale contracts will remain at Pinnacle West) as a
result of the ACC's Track A Order prohibiting the previously required transfer
of APS' generating assets to Pinnacle West Energy (see "Overview of Arizona
Regulatory Developments" above). The marketing and trading division sells, in
the wholesale market, APS and Pinnacle West Energy generation output that is not
needed for APS' Native Load and, in doing so, competes with other utilities,
power marketers and independent power producers. The division focuses primarily
on managing APS' purchased power and fuel risks in connection with its costs of
serving retail customer energy requirements. See "Track B Order" in Note 3 of
Notes to Consolidated Financial Statements in Item 8 for information regarding
an ACC-mandated process by which APS must competitively procure energy. See Note
11 of Notes to Consolidated Financial Statements in Item 8 for information
regarding our generation construction plans.
REGIONAL TRANSMISSION ORGANIZATIONS
On December 20, 1999, the FERC issued its Order No. 2000 regarding regional
transmission organizations. In its order, the FERC set minimum characteristics
and functions that must be met by utilities that participate in RTOs. The
characteristics for an acceptable RTO include independence from market
8
participants, operational control over a region large enough to support
efficient and nondiscriminatory markets and exclusive authority to maintain
short-term reliability.
As stated in Order No. 2000, the FERC believes that a number of benefits
will result from the formation of RTOs throughout the country, and it has moved
aggressively to ensure that all public utilities participate in an RTO or
demonstrate why such participation is not feasible. According to the FERC, the
benefits it expects to result from RTO formation include: (1) improvements in
transmission system operations with resulting enhancements to inter-regional
trade, congestion management, reliability and coordination; and (2) improved
performance of energy markets, including greater incentives for efficient
generator performance and enhanced potential for demand response.
On October 16, 2001, APS and other owners of electric transmission lines in
the Southwest filed with the FERC a request for a declaratory order confirming
that their proposal to form WestConnect RTO, LLC would satisfy the FERC's
requirements for the formation of an RTO. APS and the other filing parties have
agreed to fund the start-up of WestConnect's operations, which are subject to
FERC approval. WestConnect has been structured as a for-profit RTO and evolved
from DesertSTAR, a not-for-profit corporation in which APS participated, which
was originally designed to serve as an RTO for the southwestern United States.
The success of WestConnect will be largely dependent on participation by all
major transmission owners in the Southwest. The success is also dependent on
support from the affected state regulatory commissions.
On October 10, 2002, the FERC issued an order finding that the WestConnect
proposal, if modified to address specified issues, could meet the FERC's RTO
requirements and provide the basic framework for a standard market design for
the Southwest. In its order, the FERC also stated that its approval of various
WestConnect provisions addressed in the order would not be overturned or
affected by the final rule the FERC intends to ultimately adopt in response to
its July 31, 2002 Notice of Proposed Rulemaking regarding a standard market
design for the electric utility industry (see "Federal" in Note 3 of Notes to
Consolidated Financial Statements in Item 8 for additional information regarding
the Notice of Proposed Rulemaking). On November 12, 2002, APS and other owners
filed a request for rehearing and clarification on portions of the October 10,
2002 order.
On December 23, 2002, the FERC issued its order on rehearing. In it, the
FERC clarified the RTO elements that it had approved. In its order, the FERC
stated that it envisions the Seams Steering Group - Western Interconnection
(SSG-WI) as the entity that will facilitate a common market design for the West.
The SSG-WI consists of western transmission owners, including members of
WestConnect. The FERC also noted that its prior WestConnect order did not
address other elements of market design that are currently being considered in
the pending SMD proposal and/or through the SSG-WI process. The FERC clarified
that there are only three areas that would be subject to the final SMD rule: (1)
transmission credits; (2) resource adequacy; and (3) market monitoring.
The order also stated that the FERC's approval of the for-profit structure
will not predetermine its decision in the final SMD rule regarding whether a
for-profit independent transmission company should be permitted to perform all
the functions of an independent transmission provider. To the extent that the
FERC has not addressed aspects of WestConnect's for-profit proposal or
WestConnect's proposed particular functions, such elements will be subject to
review for consistency with Order No. 2000 and other related decisions regarding
9
functions that may be performed by an independent transmission company. The
WestConnect applicants sought further clarification of that aspect of the
rehearing order. The FERC has indicated that it will issue an order on the
WestConnect applicants' motion for clarification before April 14, 2003.
The ACC Rules also required the formation and implementation of an Arizona
Independent Scheduling Administrator. The purpose of the AISA is to oversee the
application of operating protocols to ensure statewide consistency for
transmission access. The AISA is anticipated to be a temporary organization
until the implementation of an independent system operator or RTO. APS
participated in the creation of the AISA, a not-for-profit entity, and the
filing at the FERC for approval of its operating protocols. The operating
protocols were partially rejected and the remainder are currently under review.
On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to the AISA with several other pending ACC
dockets. In its Track B Order, the ACC directed that a hearing be held on
whether or not APS should be required to continue funding the AISA.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
Following is a discussion of the business of APS, our major subsidiary.
GENERAL
APS was incorporated in 1920 under the laws of Arizona and currently has
more than 902,000 customers. APS provides either retail or wholesale electric
service to substantially all of the state of Arizona, with the major exceptions
of the Tucson metropolitan area and about one-half of the Phoenix metropolitan
area. Electricity is delivered through a distribution system that APS owns. APS
also generates, sells and delivers electricity to wholesale customers in the
western United States. APS' marketing and trading division sells, in the
wholesale market, APS and Pinnacle West Energy's generation output that is not
needed for APS' Native Load, which includes loads for retail customers and
cost-of-service wholesale customers. APS does not distribute any products.
During 2002, no single purchaser or user of energy (other than Pinnacle West)
accounted for more than 4% of consolidated electric revenues.
At December 31, 2002, APS employed approximately 5,100 people, which
includes employees assigned to jointly-owned generating facilities for which APS
serves as the generating facility manager. APS' principal executive offices are
located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone
602-250-1000).
PURCHASED POWER AND GENERATING FUEL
See "Properties - Capacity" in Item 2 for information about our power
plants by fuel types.
2002 ENERGY MIX
Our consolidated sources of energy during 2002 were: purchased power -
49.9% (approximately 90% of which was for wholesale power operations); coal -
23.8%; nuclear -17.7%; gas - 8.5%; and other (includes oil, hydro and solar) -
0.1%.
10
APS' sources of energy during 2002 were: purchased power - 30.4%
(approximately 60% of which was for wholesale power operations); coal - 37.2%;
nuclear - 27.7%; gas - 4.6%; 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, including low
sulfur coal, under current contracts to ensure a reliable fuel supply through
2007. APS purchases 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
northwest 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. Four Corners is
under contract for coal through 2004, with options to extend the contract
through 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, which may impact the fuel price.
See "Properties - Capacity" in Item 2 for information about APS' ownership
interest 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
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. APS' and Pinnacle West Energy's natural gas supply is transported
pursuant to a firm, full requirements transportation service agreement with El
Paso Natural Gas Company. The transportation agreement features a 10-year rate
moratorium established in a comprehensive rate case settlement entered into in
1996.
In a pending FERC proceeding, El Paso Natural Gas Company has proposed
allocating its gas pipeline capacity in such a way that the gas transportation
rights of APS and Pinnacle West Energy (and other companies with the same
contract type) could be significantly impacted. Various parties, including APS
and Pinnacle West Energy, have challenged this allocation as being inconsistent
with El Paso Natural Gas Company's existing contractual obligations and a 1996
settlement. On May 31, 2002, the FERC issued an order requiring the conversion
11
of all firm, full requirements contracts to contract demand contracts by
November 1, 2002. In addition, the FERC order set forth procedures to encourage
parties to resolve the details of such conversions through a settlement process.
APS and other full requirements contract holders sought rehearing of the FERC
order and requested a stay of the November 1, 2002 implementation date. On
September 20, 2002, the FERC issued another order clarifying the capacity
allocation methodology, extending the conversion implementation date from
November 1, 2002 to May 1, 2003 and approving the reallocation of costs for the
transportation service. APS and other full requirements contract holders have
sought rehearings of this FERC order. The FERC has indicated that it intends to
issue an order on the merits in this proceeding by April 14, 2003. Although we
cannot predict the outcome of this matter, we currently do not expect this
matter to have a material adverse impact on our financial position, results of
operations or liquidity. We are continuing to analyze the market to determine
the most favorable source and method of meeting 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:
* mining and milling of uranium ore to produce uranium concentrates;
* conversion of uranium concentrates to uranium hexafluoride;
* enrichment of uranium hexafluoride;
* fabrication of fuel assemblies;
* utilization of fuel assemblies in reactors; and
* storage and disposal of spent nuclear fuel.
The Palo Verde participants have contracted for all of Palo Verde's
requirements for uranium concentrates and conversion services through 2008,
except for a small percentage of 2003 uranium concentrates and 2004 conversion
requirements that will be obtained under contracts currently being finalized.
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 Nuclear power plant operators are
required to enter into spent nuclear fuel disposal contracts with the DOE, and
the DOE is required to accept and dispose of all spent nuclear fuel and other
high-level radioactive wastes generated by domestic power reactors. Although the
Nuclear Waste Act required the DOE to develop a permanent repository for the
storage and disposal of spent nuclear fuel by 1998, the DOE has announced that
the repository cannot be completed before 2010 and that it does not intend to
begin accepting spent nuclear fuel prior to that date. In November 1997, the
United States Court of Appeals for the District of Columbia Circuit (D.C.
Circuit) issued a decision preventing the DOE from excusing its own delay, but
refused to order the DOE to begin accepting spent nuclear fuel. Based on this
decision and the DOE's delay, a number of utilities filed damages lawsuits
against the DOE in the Court of Federal Claims.
In February 2002, the U.S. 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. In July
2002, Congress approved the development of the Yucca Mountain, Nevada site,
overriding the Nevada veto. It is now expected that the DOE will submit a
12
license application to the NRC late in 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.
Facility funding is a further complication. While all nuclear utilities pay
an amount calculated on the basis of the output of their respective plants into
a so-called nuclear waste fund, the annual Congressional appropriations for the
permanent repository have been for amounts less than the amounts paid into the
waste fund (the balance of which is being used for other purposes).
APS has existing fuel storage pools at Palo Verde and has completed 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 that spent
nuclear fuel storage or disposal methods will be available for use by Palo Verde
to allow its continued operation through the term of the operating license for
each Palo Verde unit. See "Palo Verde Nuclear Generating Station" in Note 11 of
Notes to Consolidated Financial Statements in Item 8 for a discussion of interim
spent nuclear fuel storage costs.
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 that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
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.
PURCHASED POWER AGREEMENTS
In addition to that available from its own 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 336 MW from January through May 2002, and starting in June 2002, it
changed to 343 MW. In 2002, APS received approximately 1,104,973 MWh of energy
under the contract and paid about $46.2 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. 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 2002, 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 2002, PacifiCorp received offers of 1,129,600 MWh and
purchased about 115,750 MWh.
13
CONSTRUCTION PROGRAM
During the years 2000 through 2002, APS incurred approximately $1.4 billion
in capital expenditures. APS' capital expenditures for the years 2003 through
2005 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 $501 million in 2002. APS' capital expenditures, including
expenditures for environmental control facilities, for the years 2003 through
2005 have been estimated as follows:
(dollars in millions)
BY YEAR BY MAJOR FACILITIES
----------------- --------------------------
2003 $ 401 Production $ 386
2004 379 T&D 877
2005 498 Other 15
------- -------
Total $ 1,278 Total $ 1,278
======= =======
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" in Item 7 for additional
information about APS' construction program and for information about Pinnacle
West Energy's generation construction plans.
MORTGAGE REPLACEMENT FUND REQUIREMENTS
So long as any of its first mortgage bonds are outstanding, APS is required
for each calendar year to deposit with the trustee under its mortgage cash in a
formularized amount related to net additions to its mortgaged utility plant. APS
may satisfy all or any part of this "replacement fund" requirement by using
redeemed or retired bonds, net property additions or property retirements. For
2002, the replacement fund requirement amounted to approximately $161 million.
Certain of the bonds APS has issued under the mortgage that are callable prior
to maturity are redeemable at their par value plus accrued interest with cash
APS deposits in the replacement fund. These call provisions are subject in many
cases to a period of time after the original issuance of the bonds during which
they may not be redeemed in this manner. See Note 6 of Notes to Consolidated
Financial Statements in Item 8 for information regarding APS' first mortgage
bonds.
ENVIRONMENTAL MATTERS
EPA ENVIRONMENTAL REGULATION
CLEAN AIR ACT We are subject to a number of requirements under the Clean
Air Act. The Clean Air Act addresses, among other things:
* "acid rain";
* visibility in certain specified areas;
* hazardous air pollutants; and
14
* areas that have not attained national ambient air quality standards.
With respect to "acid rain," the Clean Air Act established a system of
sulfur dioxide emissions "allowances" to offset each ton of sulfur dioxide
emitted by affected power plants. Based on EPA allowance allocations, we will
have sufficient allowances to permit continued operation of our plants at
current levels without installing additional equipment. The Clean Air Act also
requires the EPA to set nitrogen oxides emissions limitations for certain
coal-fired units. The EPA rule allows emissions from all units in a plant to be
averaged to demonstrate compliance with the emission limitation. Currently,
nitrogen oxides emissions from all of our units are within the limitations
specified under the EPA's rules. We do not currently expect this rule to have a
material impact on our financial position, results of operations or liquidity.
The Clean Air Act required the EPA to establish a Grand Canyon Visibility
Transport Commission to complete a study on visibility impairment in sixteen
"Class I Areas" (large national parks and wilderness areas) on the Colorado
Plateau. The Navajo Generating Station, Cholla and Four Corners are located near
several Class I Areas on the Colorado Plateau. The Visibility Commission
completed its study and on June 10, 1996 submitted its final recommendations to
the EPA.
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. The 2008 implementation plans
must also include consideration and potential application of best available
retrofit technology for major stationary sources which came into operation
between August 1962 and August 1977, such as the Navajo Generating Station,
Cholla and Four Corners.
The rules allow the nine western states and tribes that participated in the
Visibility Commission process to follow an alternate implementation plan and
schedule for the Class I Areas considered by the Visibility Commission. Under
this option, those states and tribes would submit implementation plans by 2003,
which would incorporate certain regional sulfur dioxide emissions milestones for
the years 2003, 2008, 2013 and 2018 (which include the application of best
available retrofit technology). If the regional emissions in those years were
within those milestones, there would be no further emission reduction
requirements, and if they were exceeded, then an emission trading program would
be implemented to maintain the emissions within those milestones.
The EPA reviewed an "Annex" to the Visibility Commission recommendations
that specify the regional sulfur dioxide emission milestones. On April 26, 2002,
the EPA proposed to accept the Visibility Commission's Annex, which had been
submitted by the Western Regional Air Partnership (successor to Visibility
Commission) in September 2000. The Annex specifies regional sulfur dioxide
emission reduction milestones. The EPA's final approval of the Annex would allow
the states and tribes to pursue the alternate implementation of the regional
haze rules through 2018. Any states and tribes that implement this option would
have to submit state implementation plans by 2003 to address visibility in areas
identified in the process, and revised implementation plans in 2008 to address
Class I Areas which were not included in the process. The State of Arizona is in
the process of developing a State Implementation Plan to implement the
provisions of the Annex. Because Four Corners is located on the Navajo
Reservation and is currently regulated by EPA Region IX, the provisions of the
Annex currently could become applicable to Four Corners only through a Federal
Implementation Plan promulgated by EPA Region IX. At this time, it is uncertain
15
how the State of Arizona and/or EPA Region IX will proceed to implement the
Annex, so the actual impact on APS cannot yet be determined.
In July 1997, the EPA promulgated final National Ambient Air Quality
Standards for ozone and particulate matter. Pursuant to these rules, the ozone
standard is more stringent and a new ambient standard for very fine particles
has been established. Congress has enacted legislation that could delay the
implementation of regional haze requirements and the particulate matter ambient
standard; however, the legislation does not preclude the Visibility Commission
states and tribes from implementing the alternate regional haze rules discussed
above. Because the actual level of emissions controls, if any, for any unit
cannot be determined at this time, APS currently cannot estimate the capital
expenditures, if any, which would result from the final rules. However, APS does
not currently expect these rules to have a material adverse effect on its
financial position, results of operations or liquidity.
With respect to hazardous air pollutants emitted by electric utility steam
generating units, the EPA has determined that mercury emissions and other
hazardous air pollutants from coal and oil-fired power plants will be regulated.
We expect that the EPA will propose specific rules for this purpose in 2003 and
finalize them by 2004, with compliance required by 2008. 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.
Certain aspects of the Clean Air Act may require APS to make related
expenditures, such as permit fees. APS does not expect any of these expenditures
to have a material impact on its financial position, results of operations or
liquidity.
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 comment period on this proposal ended
in November 1999. 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 impact
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 potentially responsible parties. PRPs may be strictly, and often
jointly and severally, liable for clean-up. The EPA had previously advised APS
that the EPA considers APS to be a PRP in the Indian Bend Wash Superfund Site,
South Area. APS' Ocotillo Power Plant is located in this area. Based on the
information to date, including available insurance coverage and an EPA estimate
of cleanup costs, APS does not expect this matter to have a material impact on
its financial position, results of operations or liquidity.
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. The purpose of this investigation is to determine if:
* waste materials are present;
* such materials constitute an environmental or health risk; and
* APS has any responsibility for remedial action.
16
Where appropriate, APS has begun clean-up of certain of 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 to APS NOVs dated September 25, 2001 and October 15, 2001
alleging, among other things, the burning of unauthorized materials and storage
of hazardous waste without a permit at the Cholla Power Plant. Each NOV requires
APS to achieve and document compliance with specific environmental requirements.
APS has submitted responses to the NOVs as well as additional information
requested by the agency. By letter dated February 28, 2003, the Arizona Attorney
General notified APS that the ADEQ expects to take enforcement action against
APS regarding the violations included in the NOVs, as well as related
violations. APS does not expect these matters to have a material adverse effect
on its financial position, results of operations or liquidity.
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 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 that occur at Four Corners and the Navajo Generating
Station. The Four Corners and Navajo Generating Station participants dispute
that purported authority, and by separate letters dated October 12 and October
13, 1995, the Four Corners participants and the Navajo Generating Station
participants requested the United States Secretary of the Interior to resolve
their dispute with the Navajo Nation regarding whether or not the Navajo Acts
apply to operations of 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, seeking, among other things, a declaratory
judgment that:
* their respective leases and federal easements preclude the application
of the Navajo Acts to the operations of Four Corners and the Navajo
Generating Station; and
* the Navajo Nation and its agencies and courts lack adjudicatory
jurisdiction to determine the enforceability of the Navajo Acts as
applied to Four Corners and the Navajo Generating Station.
On October 18, 1995, the Navajo Nation and the Four Corners and Navajo
Generating Station participants agreed to indefinitely stay these proceedings so
17
that the parties may attempt to resolve the dispute without litigation. The
Secretary and the Court have stayed these proceedings pursuant to a request by
the parties. 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 that 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. 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 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
18
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 foregoing 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 2003, as well as later years if adequate moisture is not received in the
watershed that supplies the area. Various stakeholders in the San Juan Basin,
including the New Mexico State Engineer, are evaluating how water rights might
be affected by the drought conditions, including water rights pursuant to the
New Mexico state permit that provide approximately 30,000 acre feet of water to
Four Corners. We are assessing alternatives for temporary supplies of water and
are working with area stakeholders to minimize the effect, if any, on operations
of the plant. 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 development of generating plants
and production of wholesale electricity. Pinnacle West Energy is the subsidiary
through which we conduct our competitive generation operations. Pinnacle West
Energy had approximately 100 employees as of December 31, 2002. Pinnacle West
Energy's principal offices are located at 400 North Fifth Street, Phoenix,
Arizona 85004 (telephone (602) 250-4145).
Pinnacle West Energy's capital expenditures in 2002 were $374 million.
Projected capital expenditures are $268 million in 2003; $31 million in 2004;
and $20 million in 2005. These amounts exclude capitalized interest costs and
include capitalized property taxes. These capital expenditures do not reflect an
expected reimbursement in 2004 by SNWA of about $100 million of Pinnacle West
Energy's cumulative capital expenditures for the Silverhawk project in exchange
for SNWA's option to purchase a 25% interest in the project.
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
19
transfer its generation assets. The amounts in the preceding paragraph relate
only to Pinnacle West Energy's generation assets. As discussed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Factors Affecting Our Financial Outlook" in Item 7, as part of its 2003 general
rate case, APS intends to seek rate base treatment of certain power plants
currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2,
West Phoenix Units 4 and 5 and Saguaro Unit 3). At December 31, 2002, Pinnacle
West Energy had total assets of $1.2 billion. Pinnacle West Energy reported a
net loss of $19 million in 2002, net income of $18 million in 2001 and a net
loss of $2 million in 2000.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Factors Affecting Our Financial Outlook" in Item 7 for a
discussion of APS' implementation of an ACC-mandated process by which APS must
competitively procure energy. See Note 11 of Notes to Consolidated Financial
Statements in Item 8 for information regarding Pinnacle West Energy's generation
construction plans.
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, 2002. APS Energy Services'
principal offices are located at 400 East Van Buren Street, Phoenix, Arizona
85004 (telephone (602) 250-5000).
APS Energy Services reported pretax income of $28 million in 2002 and
pretax losses of $10 million in 2001 and $13 million in 2000. Income taxes
related to APS Energy Services are recorded by the parent company. At December
31, 2002, 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, 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, 2002.
SunCor's assets consist primarily of land with improvements, commercial
buildings and other real estate investments. SunCor's largest project is the
Palm Valley master-planned community, which has approximately 6,900 acres
remaining to be developed west of Phoenix in the area of the towns of Avondale,
Goodyear and Litchfield Park, Arizona. SunCor has completed the master plan for
development of Palm Valley.
SunCor projects under development include seven master-planned communities
and several commercial projects. The commercial projects and five of the
master-planned communities are in Arizona. Other master-planned communities are
located near St. George, Utah, and Santa Fe, New Mexico. Several of the
master-planned communities and commercial projects are joint ventures with other
developers, financial partners or landowners. SunCor opened two new projects in
2002:
20
* Hayden Ferry Lakeside - an 18-acre, mixed-use commercial and
residential project located in Tempe, Arizona that opened its first
office building in July 2002; and
* StoneRidge - an 1,850-acre, master-planned community with a golf
course in Prescott Valley, Arizona that opened its initial phase of
home and lot sales and its golf course in 2002.
For the past three years, SunCor's operating revenues were about: $236
million in 2002; $169 million in 2001; and $158 million in 2000. For those same
periods, SunCor's net income was about: $19 million in 2002; $3 million in 2001;
and $11 million in 2000.
SunCor's capital needs consist primarily of capital expenditures for land
development and home construction for SunCor's home-building subsidiary, Golden
Heritage Homes, Inc. SunCor's capital expenditures were approximately $72
million in 2002. On the basis of projects currently under development, SunCor
expects its capital needs over the next three years to be: $64 million in 2003;
$23 million in 2004; and $20 million in 2005.
At December 31, 2002, SunCor had total assets of about $534 million. See
Note 6 of Notes to Consolidated Financial Statements in Item 8 for information
regarding SunCor's long-term debt. SunCor intends to continue its focus on real
estate development of master-planned communities, mixed-use residential,
commercial, office and industrial projects. As discussed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
Item 7, we are undertaking an aggressive effort to accelerate SunCor's asset
sales activities to approximately double SunCor's annual earnings in the 2003 to
2005 period (compared with $19 million in earnings recorded in 2002) and to
permit SunCor to make annual cash distributions to Pinnacle West of $80 - $100
million during that same period.
BUSINESS OF EL DORADO INVESTMENT COMPANY
El Dorado was incorporated in 1983 under the laws of the State of Arizona.
At December 31, 2002, El Dorado owned a majority interest in NAC, a company
specializing in spent nuclear fuel technology, and also held miscellaneous small
investments, including interests in 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) as of December
31, 2002.
El Dorado reported a pretax loss of $55 million in 2002 (during 2002,
income tax benefits related to El Dorado were recorded by the parent company)
and net income of $0.2 million in 2001 and $2 million in 2000. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
Item 7 and Note 22 of Notes to Consolidated Financial Statements in Item 8 for
information regarding El Dorado's 2002 losses. At December 31, 2002, El Dorado
had total assets of $36 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:
Capacity (kW)
-------------
Coal:
Units 1, 2 and 3 at Four Corners ............................. 560,000
15% owned Units 4 and 5 at Four Corners ...................... 222,000
Units 1, 2 and 3 at Cholla Plant ............................. 615,000
14% owned Units 1, 2 and 3 at the Navajo Plant ............... 315,000
---------
Subtotal ..................................................... 1,712,000
---------
Gas or Oil:
Two steam units at Ocotillo and two steam units at Saguaro ... 430,000(a)
Eleven combustion turbine units .............................. 493,000
Three combined cycle units ................................... 255,000
---------
Subtotal ..................................................... 1,178,000
---------
Nuclear:
29.1% owned or leased Units 1, 2, and 3 at Palo Verde ........ 1,086,300
---------
Hydro and Solar ................................................ 7,600
---------
Total APS facilities ......................................... 3,983,900
=========
PINNACLE WEST ENERGY - PERMITTED CAPACITIES
Pinnacle West Energy's present generating facilities have permitted
capacities as follows:
Gas or Oil:
Two combined cycle units at Redhawk and one combined-cycle unit
at West Phoenix .............................................. 1,180,000(b)
One combustion turbine unit at Saguaro ......................... 80,000
---------
Total Pinnacle West Energy facilities .......................... 1,260,000
=========
- ----------
(a) Does not include West Phoenix steam units (108,300 kW), which were retired
in December 2002.
(b) See Note 11 of Notes to Consolidated Financial Statements in Item 8 for
information regarding Pinnacle West Energy's generation construction plans.
22
RESERVE MARGIN
APS' 2002 peak one-hour demand on its electric system was recorded on July
9, 2002 at 5,802,900 kW, compared to the 2001 peak of 5,687,200 kW recorded on
July 2, 2001. Taking into account additional capacity then available to APS
under long-term purchase power contracts as well as APS' and Pinnacle West
Energy's generating capacity, APS' capability of meeting system demand on July
9, 2002 amounted to 6,046,600 kW, for an installed reserve margin of 6.5%. The
power actually available to APS from its resources fluctuates from time to time
due in part to planned outages and technical problems. The available capacity
from sources actually operable at the time of the 2002 peak amounted to
3,877,600 kW, for a margin of negative 38.1%. Firm purchases totaling 2,612,000
kW, including short-term seasonal purchases and unit contingent purchases, were
in place at the time of the peak, ensuring the ability to meet the load
requirement, with an actual reserve margin of 7.1%.
See "Business of Arizona Public Service Company - Purchased Power
Agreements" in Item 1 for information about certain of APS' long-term power
agreements.
PLANT SITES LEASED FROM NAVAJO NATION
The Navajo Generating Station and Four Corners are located on land held
under easements from the federal government and also under leases from the
Navajo Nation. These are long-term agreements with options to extend, and we do
not believe that the risk with respect to enforcement of these easements and
leases is material. The majority of coal contracted for use in these plants and
certain associated transmission lines are also located on Indian reservations.
See "Purchased Power and Generating Fuel - Coal Supply" in Item 1.
PALO VERDE NUCLEAR GENERATING STATION
PALO VERDE LEASES
See Note 9 of Notes to Consolidated Financial Statements in Item 8 for a
discussion of three sale-leaseback transactions related to Palo Verde Unit 2.
REGULATORY
Operation of each of the three Palo Verde units requires an operating
license from the NRC. The NRC issued full power operating licenses for Unit 1 in
June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power
operating licenses, each valid for a period of approximately 40 years, authorize
APS, as operating agent for Palo Verde, to operate the three Palo Verde units at
full power.
NUCLEAR DECOMMISSIONING COSTS
The NRC rules on financial assurance requirements for the decommissioning
of nuclear power plants provide that a licensee may use a trust as the exclusive
financial assurance mechanism if the licensee recovers estimated total
decommissioning costs through cost of service rates or through a "non-bypassable
charge." The "non-bypassable systems benefits" charge is the charge that the ACC
has approved to recover certain types of ACC-approved costs, including costs for
low income programs, demand side management, consumer education, environmental,
23
renewables, etc. "Non-bypassable" means that if a customer chooses to take
energy from an "energy service provider" other than APS, the customer will still
have to pay this charge as part of the customer's APS electric bill. Other
mechanisms are prescribed, including prepayment, if the requirements for
exclusive reliance on the external sinking fund mechanism are not met. APS
currently relies on the external sinking fund mechanism to meet the NRC
financial assurance requirements for its interests in Palo Verde Units 1, 2 and
3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently
included in APS' ACC jurisdictional rates. ACC retail electric competition Rules
provide that decommissioning costs would be recovered through a non-bypassable
"system benefits" charge, which would allow APS to maintain its external sinking
fund mechanism. See Note 12 of Notes to Consolidated Financial Statements in
Item 8 for additional information about our nuclear decommissioning costs.
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 11 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the insurance
maintained by the Palo Verde participants, including APS, for Palo Verde.
PROPERTY NOT HELD IN FEE OR SUBJECT TO ENCUMBRANCES
JOINTLY-OWNED FACILITIES
APS shares ownership of some of its generating and transmission facilities
with other companies. The following table shows APS' interest in those
jointly-owned facilities recorded on the Consolidated Balance Sheets at December
31, 2002:
PERCENT
OWNED BY APS
------------
Generating facilities:
Palo Verde Nuclear Generating Station
Units 1 and 3 29.1%
Palo Verde Nuclear Generating Station
Unit 2 (see "Palo Verde Leases" below) 17.0%
Four Corners Steam Generating Station
Units 4 and 5 15.0%
Navajo Steam Generating Station
Units 1, 2, and 3 14.0%
Cholla Steam Generating Station
Common Facilities (a) 62.8%(b)
Transmission facilities:
ANPP 500KV System 35.8%(b)
Navajo Southern System 31.4%(b)
Palo Verde-Yuma 500KV System 23.9%(b)
Four Corners Switchyards 27.5%(b)
Phoenix-Mead System 17.1%(b)
Palo Verde - Estrella 500KV System 50.0%(b)
24
(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
PALO VERDE LEASES
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. APS accounts
for these leases as operating leases. The leases, which have terms of 29.5
years, contain options to renew the leases for two additional years and to
purchase the property for fair market value at the end of the lease terms. See
Notes 9 and 20 of Notes to Consolidated Financial Statements in Item 8 for
additional information regarding the Palo Verde Unit 2 sale-leaseback
transactions.
APS FIRST MORTGAGE LIEN
APS' first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). See Note 6 of Notes to Consolidated Financial Statements in
Item 8 for information regarding APS' outstanding first mortgage bonds.
OTHER INFORMATION REGARDING OUR PROPERTIES
See "Environmental Matters" and "Water Supply" in Item 1 with respect to
matters having possible impact on the operation of certain of our power plants.
See "Construction Program" in Item 1 and "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources" in Item 7 for a discussion of our construction plans.
INFORMATION REGARDING PROPERTIES OF PINNACLE WEST ENERGY AND SUNCOR
See "Business of Pinnacle West Energy Corporation" and "Business of SunCor
Development Company" for information regarding Pinnacle West Energy's and
SunCor's properties.
25
[MAP PAGE}
In accordance with Item 304 of Regulation S-T of the Securities Exchange
Act of 1934, APS' Service Territory map contained in this Form 10-K is a map of
the State of Arizona showing APS' service area, the location of its major power
plants and principal transmission lines, the location of Pinnacle West Energy's
power plants and the location of transmission lines operated by APS for others.
APS' major power plants shown on such map are the Navajo Generating Station
located in Coconino County, Arizona; the Four Corners Power Plant located near
Farmington, New Mexico; the Cholla Power Plant, located in Navajo County,
Arizona; the Yucca Power Plant, located near Yuma, Arizona; the Palo Verde
Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona; the
West Phoenix Power Plant, located near Phoenix, Arizona; and the Saguaro Power
Plant, located near Tucson, Arizona (each of which plants is reflected on such
map as being jointly owned with other utilities), as well as the Ocotillo Power
Plant located near Phoenix, Arizona. Pinnacle West Energy's power plants shown
on such map are the West Phoenix Power Plant located near Phoenix, Arizona, and
the Saguaro Power Plant, located near Tucson, Arizona (both of which plants are
reflected on such map as being jointly owned with APS), as well as the Redhawk
Power Plant, located near Phoenix, Arizona. APS' major transmission lines shown
on such map are reflected as running between the power plants named above and
certain major cities in the State of Arizona. The transmission lines operated
for others shown on such map are reflected as running from the Four Corners
Plant through a portion of northern Arizona to the California border and from
the Phoenix area.
26
ITEM 3. LEGAL PROCEEDINGS
See "Environmental Matters" and "Water Supply" in Item 1 in regard to
pending or threatened litigation and other disputes. See Note 3 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the ACC retail
electric competition Rules, the Track A Order and related litigation.
See Note 11 of Notes to Consolidated Financial Statements in Item 8 for
information relating to the FERC proceedings on California energy market issues
and a claim by Citizens that APS overcharged Citizens under a power service
agreement. See also Note 22 of Notes to Consolidated Financial Statements in
Item 8 for information relating to a breach of contract claim by Maine Yankee
against Pinnacle West and NAC.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
27
SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers are as follows:
Name Age at March 1, 2003 Position(s) at March 1, 2003
- ---- -------------------- ----------------------------
William J. Post 52 Chairman of the Board and
Chief Executive Officer (1)
Jack E. Davis 56 President, and President and Chief
Executive Officer, APS (1)
Robert S. Aiken 46 Vice President, Federal Affairs
John G. Bohon 57 Vice President, Corporate Services &
Human Resources
Donald E. Brandt 48 Senior Vice President and Chief
Financial Officer
Dennis L. Brown 52 Vice President and Chief Information
Officer
Armando B. Flores 59 Executive Vice President, Corporate
Business Services
Edward Z. Fox 49 Vice President, Communications,
Environment & Safety
Barbara M. Gomez 48 Treasurer
James M. Levine 53 Executive Vice President, APS
and President, Pinnacle
West Energy
Nancy C. Loftin 49 Vice President, General Counsel
and Secretary
Gregg R. Overbeck 56 Senior Vice President, APS, Nuclear
Martin L. Shultz 58 Vice President, Government Affairs
Steven M. Wheeler 54 Senior Vice President, APS
Transmission, Regulation and
Planning
- ----------
(1) Member of the Board of Directors.
The executive officers of Pinnacle West are elected no less often than
annually and may be removed by the Board of Directors at any time. The terms
served by the named officers in their current positions and the principal
occupations (in addition to those stated in the table) of such officers for the
past five years have been as follows:
Mr. Post was elected Chairman of the Board effective February 2001, and
Chief Executive Officer effective February 1999. He has served as an officer of
Pinnacle West since 1995 in the following capacities: from August 1999 to
February 2001 as President; from February 1997 to February 1999 as President;
and from June 1995 to February 1997 as Executive Vice President. Mr. Post is
also Chairman of the Board (since February 2001) of APS. He was President of APS
from February 1997 until October 1998 and he was Chief Executive Officer from
February 1997 until October 2002. Mr. Post is also a director of APS, Pinnacle
West Energy and Phelps Dodge Corporation.
28
Mr. Davis was elected to his present position effective February 2001.
Prior to that time he was Chief Operating Officer and Executive Vice President
of Pinnacle West (April 2000-February 2001) and Executive Vice President,
Commercial Operations of APS (September 1996-October 1998). Mr. Davis is
President of APS (since October 1998) and Chief Executive Officer of APS (since
October 2002). He is a director of APS and Pinnacle West Energy.
Mr. Aiken was elected to his present position in July 1999. Prior to that
time he was Pinnacle West's Manager, Federal Affairs (November 1986-July 1999).
Mr. Bohon was elected to his present position in July 1999. Prior to that
time he was Vice President, Corporate Services and Human Resources of APS
(October 1998-July 1999) and Vice President, Procurement of APS (April
1997-October 1998).
Mr. Brandt was elected to his present position in December 2002. Prior to
that time he was Senior Vice President and Chief Financial Officer of Ameren
Corporation (diversified energy services company). Mr. Brandt was elected Senior
Vice President and Chief Financial Officer of APS in January 2003.
Mr. Brown was elected to his present position in June 2001. Prior to that
time he was Director, Information Technology of Pinnacle West (October 1999 -
June 2001) and Global Solution Executive for IBM Utilities and Energy Services
of IBM prior to that time.
Mr. Flores was elected to his present position in July 1999. Prior to that
time, he was Executive Vice President, Corporate Business Services of APS
(October 1998-July 1999) and Senior Vice President, Corporate Business Services
of APS (September 1996-October 1998).
Mr. Fox was elected to his present position in July 1999. Prior to that
time he was Vice President, Environmental/Health/Safety and New Technology
Ventures of APS (October 1995-July 1999).
Ms. Gomez was elected to her present position in August 1999. Prior to that
time, she was Manager, Treasury Operations of APS (1997-1999). She was also
elected Treasurer of APS in October 1999.
Mr. Levine was elected Executive Vice President of APS in July 1999 and
President of Pinnacle West Energy in January 2003. Prior to that time he was
Senior Vice President, Nuclear Generation of APS (September 1996-July 1999).
Ms. Loftin was elected Vice President and General Counsel in July 1999 and
Secretary in October 2002. She was elected to the positions of Vice President
and Chief Legal Counsel of APS in September 1996. She was also elected Vice
President and General Counsel of APS in July 1999 and Secretary of APS in
October 2002.
Mr. Overbeck was elected to his present position in July 1999. Prior to
that time he was Vice President, Nuclear Production of APS (September 1996 to
July 1999) and Vice President, Nuclear Support of APS (July 1995 to September
1996).
Mr. Shultz was elected to his current position in July 1999. Prior to that
time he held the position of Director of Government Relations for APS (1988-July
1999).
Mr. Wheeler was elected to his present position in October 2002. Prior to
that time he was Senior Vice President, Transmission, Regulation and Planning of
Pinnacle West and APS (June 2001 - October 2002). Prior to that time he was a
partner with Snell & Wilmer L.L.P.
29
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
STOCK AND RELATED STOCKHOLDER MATTERS
Our common stock is publicly held and is traded on the New York and Pacific
Stock Exchanges. At the close of business on March 26, 2003, our common stock
was held of record by approximately 36,876 shareholders.
See "Quarterly Stock Prices and Dividends Per Share" in Item 6 for a
description of the common stock price ranges on the composite tape, as reported
in the Wall Street Journal for 2002 and 2001, and the dividends declared during
each of the four quarters for 2002 and 2001.
30
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
2002 2001 2000 1999 1998
------------ ------------ ------------ ------------ ------------
OPERATING RESULTS (dollars in thousands, except shares and per share amounts)
Operating revenues:
Regulated electricity segment $ 2,013,023 $ 2,562,089 $ 2,538,752 $ 1,915,108 $ 1,741,148
Marketing and trading segment 325,931 651,230 418,532 154,125 180,145
Real estate segment 236,388 168,908 158,365 130,169 124,188
Other revenues 61,937 11,771 3,873 439 --
Income from continuing operations $ 215,153 $ 327,367 $ 302,332 $ 269,772 $ 242,892
Discontinued operations (a) -- -- -- 38,000 --
Extraordinary charge - net of
income taxes (b) -- -- -- (139,885) --
Cumulative effect of change in
accounting-net of income taxes (c) (d) (65,745) (15,201) -- -- --
------------ ------------ ------------ ------------ ------------
Net income $ 149,408 $ 312,166 $ 302,332 $ 167,887 $ 242,892
============ ============ ============ ============ ============
COMMON STOCK DATA
Book value per share - year-end $ 29.40 $ 29.46 $ 28.09 $ 26.00 $ 25.50
Earnings (loss) per weighted average
common share outstanding:
Continuing operations - basic $ 2.53 $ 3.86 $ 3.57 $ 3.18 $ 2.87
Discontinued operations -- -- -- 0.45 --
Extraordinary charge -- -- -- (1.65) --
Cumulative effect of change
in accounting (0.77) (0.18) -- -- --
------------ ------------ ------------ ------------ ------------
Net income - basic $ 1.76 $ 3.68 $ 3.57 $ 1.98 $ 2.87
============ ============ ============ ============ ============
Continuing operations - diluted $ 2.53 $ 3.85 $ 3.56 $ 3.17 $ 2.85
Net income - diluted $ 1.76 $ 3.68 $ 3.56 $ 1.97 $ 2.85
Dividends declared per share $ 1.625 $ 1.525 $ 1.425 $ 1.325 $ 1.225
Indicated annual dividend rate
per share - year-end $ 1.70 $ 1.60 $ 1.50 $ 1.40 $ 1.30
Weighted-average common shares
outstanding - basic 84,902,946 84,717,649 84,732,544 84,717,135 84,774,218
Weighted-average common shares
outstanding - diluted 84,963,921 84,930,140 84,935,282 85,008,527 85,345,946
BALANCE SHEET DATA
Total assets $ 8,425,806 $ 7,939,399 $ 7,122,667 $ 6,571,023 $ 6,789,975
============ ============ ============ ============ ============
Liabilities and equity:
Long-term debt less current
maturities $ 2,881,695 $ 2,673,078 $ 1,955,083 $ 2,206,052 $ 2,048,961
Other liabilities 2,857,958 2,766,998 2,784,870 2,159,238 2,482,422
------------ ------------ ------------ ------------ ------------
Total liabilities 5,739,653 5,440,076 4,739,953 4,365,290 4,531,383
Minority interests:
Non-redeemable preferred stock of APS -- -- -- -- 85,840
Redeemable preferred stock of APS -- -- -- -- 9,401
Common stock equity 2,686,153 2,499,323 2,382,714 2,205,733 2,163,351
------------ ------------ ------------ ------------ ------------
Total liabilities and equity $ 8,425,806 $ 7,939,399 $ 7,122,667 $ 6,571,023 $ 6,789,975
============ ============ ============ ============ ============
(a) Tax benefit stemming from the resolution of income tax matters related to a
former subsidiary MeraBank, A Federal Savings Bank.
(b) Charges associated with a regulatory disallowance. See "Regulatory
Accounting" in Note 1.
(c) Change in accounting standards related to derivatives in 2001. See Note 18.
(d) Change in accounting standards related to trading activities in 2002. See
Note 18.
31
REGULATED ELECTRICITY AND MARKETING AND
TRADING SEGMENTS' REVENUES
2002 2001 2000 1999 1998
----------- ----------- ----------- ----------- -----------
Regulated electricity segment: (dollars in thousands)
Retail:
Residential $ 906,069 $ 914,711 $ 880,468 $ 805,173 $ 766,378
Business 927,773 952,627 935,214 911,449 889,244
----------- ----------- ----------- ----------- -----------
Total retail 1,833,842 1,867,338 1,815,682 1,716,622 1,655,622
Wholesale revenue on
delivered electricity:
Traditional contracts 8,616 73,305 120,618 60,486 58,184
Retail load hedge
management (a) 122,630 577,784 560,493 108,153 --
Transmission for others 29,803 25,971 14,765 11,348 11,058
Other miscellaneous services 18,132 17,691 27,194 18,499 16,284
----------- ----------- ----------- ----------- -----------
Total regulated electricity revenue 2,013,023 2,562,089 2,538,752 1,915,108 1,741,148
----------- ----------- ----------- ----------- -----------
Marketing and trading segment:
Delivered marketing and
trading:
Generation sales other than
Native Load (a) 50,364 148,316 115,476 29,551 --
Realized margin on
electricity trading 47,897 62,067 55,910 8,565 2,157
Other delivered
electricity (a) 207,810 328,972 244,183 112,551 170,796
----------- ----------- ----------- ----------- -----------
Total delivered marketing
and trading 306,071 539,355 415,569 150,667 172,953
----------- ----------- ----------- ----------- -----------
Other marketing and trading:
Realized margins on
delivered commodities
other than electricity 7,771 (13,646) (8,789) 2,483 7,192
Prior period mark-to-
market gains on
contracts delivered
during current period (40,072) (1,059) (2,079) -- --
Change in mark-to-
market for future
period deliveries 52,161 126,580 13,831 975 --
----------- ----------- ----------- ----------- -----------
Total other marketing and
trading 19,860 111,875 2,963 3,458 7,192
----------- ----------- ----------- ----------- -----------
Total marketing and trading revenue 325,931 651,230 418,532 154,125 180,145
----------- ----------- ----------- ----------- -----------
Total regulated electricity and
marketing and trading
segments' revenues $ 2,338,954 $ 3,213,319 $ 2,957,284 $ 2,069,233 $ 1,921,293
=========== =========== =========== =========== ===========
(a) The breakout of retail load hedge management and generation sales other
than Native Load is not available for 1998. These amounts are included in
other delivered electricity in the marketing and trading segment for 1998.
32
2002 2001 2000 1999 1998
---------- ---------- ---------- ---------- ----------
ELECTRIC SALES (MWH)
Regulated electricity segment:
Retail:
Residential 10,443,820 10,334,860 9,780,680 8,774,822 8,310,689
Business 12,917,935 13,064,152 12,753,844 12,299,748 12,152,394
---------- ---------- ---------- ---------- ----------
Total retail 23,361,755 23,399,012 22,534,524 21,074,570 20,463,083
Wholesale electricity
delivered:
Traditional contracts 473,699 1,213,704 1,610,032 1,421,522 1,410,392
Retail load hedge
management (a) 2,641,714 3,039,905 6,673,658 630,945 --
---------- ---------- ---------- ---------- ----------
Total regulated electricity 26,477,168 27,652,621 30,818,214 23,127,037 21,873,475
---------- ---------- ---------- ---------- ----------
Delivered marketing and trading:
Generation sales other than
Native Load (a) 1,791,319 1,387,860 1,494,299 1,267,349 --
Electricity trading 16,924,509 12,031,055 9,259,054 5,679,023 846,864
Other delivered electricity (a) 4,138,055 2,581,942 2,960,314 6,694,995 8,060,135
---------- ---------- ---------- ---------- ----------
Total delivered marketing
and trading 22,853,883 16,000,857 13,713,667 13,641,367 8,906,999
---------- ---------- ---------- ---------- ----------
Total regulated electricity
and marketing and
trading sales 49,331,051 43,653,478 44,531,881 36,768,404 30,780,474
========== ========== ========== ========== ==========
ELECTRIC CUSTOMERS -
AVERAGE
Retail:
Residential 801,801 776,339 749,285 719,774 689,871
Business 100,228 98,198 94,128 90,496 87,831
---------- ---------- ---------- ---------- ----------
Total retail 902,029 874,537 843,413 810,270 777,702
Wholesale 67 66 67 69 60
---------- ---------- ---------- ---------- ----------
Total average electric customers 902,096 874,603 843,480 810,339 777,762
========== ========== ========== ========== ==========
(a) The breakout of retail load hedge management and generation sales other
than Native Load is not available for 1998. These amounts are included in
other delivered electricity in the marketing and trading segment for 1998.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a discussion of certain information in the tables above.
33
QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE
STOCK SYMBOL: PNW
Dividends
Per
2002 High Low Close Share
- ----------- ------ ------ ------ ------
1st Quarter $45.60 $39.36 $45.35 $0.400
2nd Quarter 46.68 37.08 39.50 0.400
3rd Quarter 39.72 25.82 27.76 0.400
4th Quarter 34.36 21.70 34.09 0.425
Dividends
Per
2001 High Low Close Share
- ----------- ------ ------ ------ ------
1st Quarter $47.96 $39.06 $45.87 $0.375
2nd Quarter 50.70 45.20 47.40 0.375
3rd Quarter 49.93 37.65 39.70 0.375
4th Quarter 43.50 38.00 41.85 0.400
34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In this Item, we explain the results of operations, general financial
condition and outlook for Pinnacle West and our subsidiaries: APS, Pinnacle West
Energy, APS Energy Services, SunCor and El Dorado, including:
* the changes in our earnings from 2001 to 2002 and from 2000 to 2001;
* our capital needs, liquidity and capital resources;
* our critical accounting policies;
* our business outlook and major factors that affect our financial
outlook; and
* our management of market risks.
Throughout this Item, we refer to specific "Notes" in the Notes to
Consolidated Financial Statements in Item 8 of this report. These Notes add
further details to the discussion.
BUSINESS OVERVIEW
The Company owns all of the outstanding common stock of APS. APS is an
electric utility that provides either retail or wholesale electric service to
substantially all of the state of Arizona, with the major exceptions of the
Tucson metropolitan area and about one-half of the Phoenix metropolitan area.
Electricity is delivered through a distribution system owned by APS. APS also
generates, sells and delivers electricity to wholesale customers in the western
United States. The marketing and trading division sells, in the wholesale
market, APS and Pinnacle West Energy generation output that is not needed for
APS' Native Load, which includes loads for retail customers and traditional
cost-of-service wholesale customers. APS does not distribute any products.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our competitive
electricity generation operations;
* APS Energy Services, which provides competitive commodity-related
energy services (such as direct access commodity contracts, energy
procurement and energy supply consultation) and energy-related
products and services (such as energy master planning, energy use
consultation and facility audits, cogeneration analysis and
installation and project management) to commercial, industrial and
institutional retail customers in the western United States;
* SunCor, a developer of residential, commercial and industrial real
estate projects in Arizona, New Mexico and Utah; and
35
* El Dorado, which owns a majority interest in NAC (specializing in
spent nuclear fuel technology) and holds miscellaneous small
investments, including interests in Arizona community-based ventures.
SUMMARY OF KEY FACTORS AFFECTING OUR FINANCIAL OUTLOOK
We believe the following are among the key factors affecting our financial
outlook:
* The following ACC regulatory matters:
* APS' $500 million financing application, which the ACC approved
on March 27, 2003;
* the implementation of the ACC-mandated process by which APS must
competitively procure energy; and
* APS' general rate case to be filed in 2003.
* Wholesale power market conditions in the western United States.
We discuss each of these, and other factors in detail below in the section
entitled "Factors Affecting Our Financial Outlook."
EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT
We have three principal business segments (determined by products, services
and the regulatory environment):
* Our regulated electricity segment, which consists of regulated
traditional retail and wholesale electricity businesses and related
activities and includes electricity transmission, distribution and
generation;
* our marketing and trading segment, which consists of our competitive
energy business activities, including wholesale marketing and trading
and APS Energy Services' commodity-related energy services; and
* our real estate segment, which consists of SunCor's real estate
development and investment activities.
The following tables summarize net income and segment details for the years
ended December 31, 2002, 2001 and 2000 for Pinnacle West and each of our
subsidiaries (dollars in millions):
36
REGULATED MARKETING AND
TOTAL ELECTRICITY TRADING REAL ESTATE OTHER (a)
--------- ----------- ------------- ----------- ---------
2002
- ----
APS (b) $ 199 $ 198 $ 1 $ -- $ --
Pinnacle West Energy (b) (19) (21) 2 -- --
APS Energy Services (c) 28 -- 23 -- 5
SunCor 19 -- -- 19 --
El Dorado (principally NAC) (c) (55) -- -- -- (55)
Parent company (c) 43 (7) 32 -- 18
--------- --------- --------- --------- ---------
Income (loss) before
accounting change 215 170 58 19 (32)
Cumulative effect of change in
accounting - net of income
taxes (d) (66) -- (66) -- --
--------- --------- --------- --------- ---------
Net income (loss) $ 149 $ 170 $ (8) $ 19 $ (32)
========= ========= ========= ========= =========
REGULATED MARKETING AND
TOTAL ELECTRICITY TRADING REAL ESTATE OTHER
--------- ----------- ------------- ----------- ---------
2001
- ----
APS (b) $ 281 $ 139 $ 142 $ -- $ --
Pinnacle West Energy (b) 18 18 -- -- --
APS Energy Services (c) (10) -- (11) -- 1
SunCor 3 -- -- 3 --
El Dorado -- -- -- -- --
Parent company 35 (5) 40 -- --
--------- --------- --------- --------- ---------
Income before
accounting change 327 152 171 3 1
Cumulative effect of change in
accounting - net of income
taxes (e) (15) (15) -- -- --
--------- --------- --------- --------- ---------
Net income $ 312 $ 137 $ 171 $ 3 $ 1
========= ========= ========= ========= =========
REGULATED MARKETING AND
TOTAL ELECTRICITY TRADING REAL ESTATE OTHER
--------- ----------- ------------- ----------- ---------
2000
- ----
APS $ 307 $ 228 $ 79 $ -- $ --
Pinnacle West Energy (2) (2) -- -- --
APS Energy Services (c) (13) -- (16) -- 3
SunCor 11 -- -- 11 --
El Dorado 2 -- -- -- 2
Parent company (3) (5) 2 -- --
--------- --------- --------- --------- ---------
Net income $ 302 $ 221 $ 65 $ 11 $ 5
========= ========= ========= ========= =========
37
(a) Primarily includes activities related to El Dorado, principally NAC.
See Note 22.
(b) Consistent with APS' October 2001 ACC filing, APS entered into
agreements with its affiliates to buy power. The agreements reflected
a price based on the fully-dispatchable dedication of the Pinnacle
West Energy generating assets to APS' Native Load customers. In 2002,
Pinnacle West Energy recorded a $49 million pretax write-off related
to the cancellation of Redhawk Units 3 and 4.
(c) APS Energy Services' and El Dorado's net income is primarily reported
before income taxes. The income tax expense or benefit for these
subsidiaries is recorded at the parent company.
(d) We recorded a $66 million after-tax charge in 2002 for the cumulative
effect of a change in accounting for trading activities, for the early
adoption of EITF 02-3," Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities," as of October 1, 2002. See
Note 18.
(e) APS recorded a $15 million after-tax charge in 2001 for the cumulative
effect of a change in accounting for derivatives related to the
adoption of SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." See Note 18.
See Note 17 for additional financial information regarding our business
segments.
RESULTS OF OPERATIONS
GENERAL
Throughout the following explanations of our results of operations, we
refer to "gross margin." With respect to our regulated electricity segment and
marketing and trading segment, gross margin refers to electric operating
revenues less purchased power and fuel costs. Our real estate segment gross
margin refers to real estate revenues less real estate operations costs of
SunCor. Other gross margin refers to other operating revenues less other
operating expenses, which includes El Dorado's investment in NAC, which we began
consolidating in our financial statements in July 2002 (see Note 22). Other
gross margin also includes amounts related to APS Energy Services' energy
consulting services.
2002 COMPARED WITH 2001
Our consolidated net income for the year ended December 31, 2002 was $149
million compared with $312 million for the prior year. We recognized a $66
million after-tax charge in 2002 for the cumulative effect of a change in
accounting for trading activities for the early adoption of EITF 02-3 on October
1, 2002 (see Note 18). In 2001, we recognized a $15 million after-tax charge for
the cumulative effect of a change in accounting for derivatives, as required by
SFAS No. 133 (see Note 18).
Our income before accounting change for the year ended December 31, 2002
was $215 million compared with $327 million for the prior year. The
period-to-period comparison was lower due to:
38
* lower earnings contributions from our marketing and trading
activities, reflecting lower liquidity and lower price volatility in
the wholesale power markets in the western United States;
* pretax losses of $59 million related to our investment in NAC;
* a $49 million pretax write-off related to the cancellation of Redhawk
Units 3 and 4, of which $47 million was recorded in operations and
maintenance expense and $2 million was recorded in capitalized
interest; and
* severance costs of approximately $36 million pretax recorded in the
second half of 2002 relating to a voluntary workforce reduction.
The above decreases were partially offset by:
* increased earnings contributions from our regulated electricity
activities, reflecting lower replacement power costs for power plant
outages, retail customer growth and higher average usage per customer,
partially offset by the effects of milder weather, retail electricity
price decreases and higher costs for purchased power and gas due to
higher hedged gas and power prices; and
* increased earnings contributions from real estate operations,
primarily as a result of increased sales activities.
For additional details, see the following discussion.
39
The major factors that increased (decreased) income before accounting
change were as follows (dollars in millions):
Increase
(Decrease)
----------
Regulated electricity segment gross margin:
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages $ 127
Increased purchased power and fuel costs due to higher hedged gas
and power prices, partially offset by improved hedge management,
net of mark-to-market reversals (9)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 38
2001 charges related to purchased power contracts with Enron
and its affiliates 13
Retail price reductions effective July 1, 2001 and July 1, 2002 (28)
Effects of milder weather on retail sales (27)
Miscellaneous factors, net (2)
--------
Net increase in regulated electricity segment gross margin 112
--------
Marketing and trading segment gross margin:
Decrease in generation sales other than Native Load due to lower
market prices partially offset by higher sales volumes (66)
Lower realized wholesale margins net of related mark-to-market
reversals due to lower prices and volumes (91)
Higher competitive retail sales in California by APS Energy Services 32
2001 write-off of prior period mark-to-market value related to trading
with Enron and its affiliates 8
Lower mark-to-market reversals due to the adoption of EITF 02-3 8
Lower mark-to-market gains for future delivery due to lower market
liquidity and lower price volatility (76)
--------
Net decrease in marketing and trading segment gross margin (185)
--------
Net decrease in regulated electricity and marketing and trading segments'
gross margins (73)
Higher real estate segment gross margin primarily due to increased sales
activities 16
Lower other gross margin primarily related to NAC losses (44)
Higher operations and maintenance expense related to a $47 million
write-off of Redhawk Units 3 and 4 and 2002 severance costs of
approximately $36 million, partially offset by lower generation
reliability costs (54)
Higher taxes other than income taxes (7)
Lower other income primarily due to a 2001 insurance recovery of
environmental remediation costs (11)
Higher net interest expense primarily due to higher debt balances and lower
capitalized interest (16)
Miscellaneous factors, net 2
--------
Net decrease in income before income taxes (187)
Lower income taxes primarily due to lower income 75
--------
Net decrease in income before accounting change $ (112)
========
40
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $549 million lower in the year ended
December 31, 2002, compared with the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($64 million);
* decreased revenues related to retail load hedge management wholesale
sales, primarily as a result of lower prices and lower sales volumes
($455 million);
* decreased retail revenues related to milder weather ($60 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($69 million);
* decreased retail revenues related to reductions in retail electricity
prices ($28 million); and
* other miscellaneous factors ($11 million net decrease).
Regulated electricity segment purchased power and fuel costs were $661
million lower in the year ended December 31, 2002, compared with the prior year
as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($64 million);
* decreased costs related to retail load hedge management wholesale
sales, primarily as a result of lower prices and lower sales volumes
($460 million);
* increased costs related to higher prices for hedged natural gas and
purchased power, net of mark-to-market reversals ($14 million);
* decreased costs related to the effects of milder weather on retail
sales ($33 million);
* increased costs related to retail sales growth, excluding weather
effects ($31 million);
* charges in 2001 related to purchased power contracts with Enron and
its affiliates ($13 million net decrease);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($127 million); and
* miscellaneous factors ($9 million net decrease).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $325 million lower in the year
ended December 31, 2002, compared with the prior year as a result of:
* decreased revenues from generation sales other than Native Load
primarily due to lower market prices partially offset by higher sales
volumes ($98 million);
* lower realized wholesale revenues net of related mark-to-market
reversals primarily due to lower prices partially offset by higher
volumes ($273 million);
* increased revenues from higher competitive retail sales in California
by APS Energy Services ($105 million);
* 2001 write-off of prior period mark-to-market value related to trading
with Enron and its affiliates ($8 million increase);
* higher revenues related to the adoption of EITF 02-3 ($8 million); and
41
* lower mark-to-market gains for future delivery primarily as a result
of lower market liquidity and lower price volatility, resulting in
lower volumes ($75 million).
Marketing and trading segment purchased power and fuel costs were $140
million lower in the year ended December 31, 2002, compared to the prior year as
a result of:
* decreased fuel costs related to generation sales other than Native
Load primarily because of lower natural gas prices partially offset by
higher sales volumes ($32 million);
* decreased purchased power costs related to other realized marketing
activities in the current period primarily due to lower prices
partially offset by higher volumes ($182 million);
* increased purchased power costs related to higher competitive retail
sales in California by APS Energy Services ($73 million); and
* change in mark-to-market fuel costs for future delivery ($1 million
increase).
OTHER INCOME STATEMENT ITEMS
The increase in real estate segment gross margin of $16 million was
primarily due to increased sales activities.
The decrease in other gross margin of $44 million was primarily due to
losses on El Dorado's investment in NAC (see further discussion in Note 22).
These losses for 2002 totaled approximately $59 million on a pretax basis and
were primarily related to NAC contracts with two customers ($51 million was
recorded in other gross margin and $8 million was recorded in other expense). We
believe we have reserved our exposure with respect to these contracts in all
material respects and, as a result, we consider these charges to be
non-recurring.
The increase in operations and maintenance expense of $54 million was due
to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4,
severance costs of $36 million related to a 2002 voluntary workforce reduction
and other costs of $9 million, partially offset by lower costs related to
generation reliability, plant outages and maintenance costs of $38 million.
The increase in taxes other than income taxes of $7 million is primarily
due to increased property taxes on higher property balances.
Other income decreased $11 million primarily due to an insurance recovery
recorded in 2001 related to environmental remediation costs and other costs (see
Note 19).
Other expense was comparable with the prior year primarily due to losses
recorded related to El Dorado's investment in NAC of approximately $8 million
(see further discussion in Note 22), offset by $8 million of lower miscellaneous
non-operating costs (see Note 19).
Net interest expense increased $16 million primarily because of higher debt
balances related to our generation construction program and lower capitalized
interest on our generation construction program due to completion of Redhawk
Units 1 and 2 in mid-2002.
42
2001 COMPARED WITH 2000
Our consolidated net income for the year ended December 31, 2001 was $312
million compared with $302 million for the prior year. In 2001, we recognized a
$15 million after-tax charge for the cumulative effect of a change in accounting
for derivatives, as required by SFAS No. 133 (see Note 18).
Our income before accounting change for the year ended December 31, 2001
was $327 million compared with $302 million for the prior year. The
period-to-period comparison benefited from:
* strong marketing and trading results, including significant benefits
recognized in the third quarter of 2001 from structured trading
activities; and
* retail customer growth.
The above increases were partially offset by:
* lower earnings contributions from our regulated electricity
activities, reflecting higher purchased power and fuel costs, due in
part to increased power plant maintenance, generation reliability
measures and continuing retail electricity price decreases; and
* 2001 charges related to Enron and its affiliates.
For additional details, see the following discussion.
43
The major factors that increased (decreased) income before accounting
change were as follows (dollars in millions):
Increase
(Decrease)
----------
Regulated electricity segment gross margin:
Higher replacement power costs for plant outages related to higher
market prices $ (70)
Retail price reductions effective July 1, 2001 and July 1, 2000 (27)
Charges related to purchased power contracts with Enron and its affiliates (13)(a)
Higher retail sales primarily related to customer growth 35
Miscellaneous revenues 3
--------
Net decrease in regulated electricity segment gross margin (72)
--------
Marketing and trading segment gross margin:
Increase from generation sales other than Native Load due to higher
market prices 25
Higher realized wholesale margin net of related mark-to-market reversals 61
Change in prior period mark-to-market value related to
trading with Enron and its affiliates (8)(a)
Increase in mark-to-market value related to future periods 113
--------
Net increase in marketing and trading segment gross margin 191
--------
Net increase in regulated electricity and marketing and trading segments'
gross margins 119
Decrease in real estate segment contributions (8)
Higher operations and maintenance expense related to 2001 generation
reliability program (42)
Higher operations and maintenance expense related primarily to employee
benefits, plant outage and maintenance and other costs (38)
Lower net interest expense primarily due to higher capitalized interest 17
Higher other net expense (4)
--------
Net increase in income before income taxes 44
Higher income taxes primarily due to higher income (19)
--------
Net increase in income before accounting change $ 25
========
(a) We recorded charges totaling $21 million before income taxes for
exposure to Enron and its affiliates in the fourth quarter of 2001.
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $23 million higher in the year ended
December 31, 2001 compared to the prior year as a result of:
* decreased revenues related to other wholesale sales and miscellaneous
revenues as a result of lower sales volumes ($28 million);
44
* increased retail revenues primarily related to higher sales volumes
primarily due to customer growth ($78 million); and
* decreased retail revenues related to reductions in retail electricity
prices ($27 million).
Regulated electricity segment purchased power and fuel costs were $95
million higher in the year ended December 31, 2001 compared to the prior year as
a result of:
* decreased costs related to other wholesale sales as a result of lower
volumes ($31 million);
* higher replacement power costs primarily due to higher market prices
and increased plant outages ($70 million), including costs of $12
million related to a Palo Verde outage extension to replace fuel
control element assemblies;
* higher costs related to retail sales volumes due to customer growth
($43 million); and
* charges related to purchased power contracts with Enron and its
affiliates ($13 million).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $233 million higher in the year
ended December 31, 2001 compared with the prior year as a result of:
* increased revenues related to generation sales other than Native Load
as a result of higher average market prices ($32 million);
* increased realized wholesale revenues net of related mark-to-market
reversals primarily due to more transactions ($96 million);
* decreased prior period mark-to-market value related to trading with
Enron and its affiliates ($8 million); and
* increased mark-to-market value for future periods primarily as a
result of more forward sales volumes ($113 million).
Marketing and trading segment purchased power and fuel costs were $42
million higher in the year ended December 31, 2001 compared to the prior year as
a result of:
* increased fuel costs related to generation sales other than Native
Load as a result of higher fuel prices ($7 million); and
* increased purchased power and fuel costs net of related mark-to-market
reversals primarily due to more transactions ($35 million).
OTHER INCOME STATEMENT ITEMS
The decrease in real estate segment profits of $8 million resulted
primarily from reduced sales of land and homes by SunCor.
The increase in operations and maintenance expenses of $80 million
primarily related to the 2001 generation summer reliability program (the
addition of generating capability to enhance reliability for the summer of 2001
($42 million)) and increased employee benefit costs, plant outage and
45
maintenance and other costs ($38 million). The comparison reflects Pinnacle
West's $10 million provision for our credit exposure related to the California
energy situation, $5 million of which was recorded in the fourth quarter of 2000
and $5 million of which was recorded in the first quarter of 2001.
Net other expense increased $4 million primarily because of a change in the
market value of El Dorado's investment in a technology-related venture capital
partnership in 2000 and other nonoperating costs partially offset by an
insurance recovery of environmental remediation costs (see Note 19).
Interest expense decreased by $17 million primarily because of increased
capitalized interest resulting from our generation construction plan partially
offset with higher interest expense due to higher debt balances.
See "Regulatory Matters - 1999 Settlement Agreement" in Note 3 for a
discussion of the 1999 Settlement Agreement under which, among other things, APS
agreed to five annual retail electricity price reductions of 1.5%, with the last
decrease to take effect July 1, 2003.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS AND RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the year
ended December 31, 2002 and estimated capital expenditures for the next three
years.
CAPITAL EXPENDITURES
(dollars in millions)
Actual Estimated
------ ------------------------
2002 2003 2004 2005
---- ---- ---- ----
APS
Delivery $369 $273 $275 $329
Generation (a) 132 123 99 164
Other (e) -- 5 5 5
---- ---- ---- ----
Subtotal 501 401 379 498
Pinnacle West Energy (a) (b) 374 268 31 20
SunCor (c) 72 64 23 20
Other (d) 37 17 13 14
---- ---- ---- ----
Total $984 $750 $446 $552
==== ==== ==== ====
(a) As discussed below under "Factors Affecting Our Financial Outlook," as part
of its 2003 general rate case, APS intends to seek rate base treatment of
certain power plants in Arizona currently owned by Pinnacle West Energy
(specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and
Saguaro Unit 3).
46
(b) See Note 11 for further discussion of Pinnacle West Energy's generation
construction program and "Capital Resources and Cash Requirements -
Pinnacle West Energy" below. These amounts do not include an expected
reimbursement in 2004 by SNWA of about $100 million, assuming SNWA
exercises its option to purchase a 25% interest in the Silverhawk project
at that time.
(c) Consists primarily of capital expenditures for land development and retail
and office building construction reflected in the "Change in real estate
investments" in the Consolidated Statements of Cash Flows.
(d) Primarily related to the parent company and APS Energy Services.
(e) The other amounts relate to capital expenditures for our marketing and
trading segment. These costs were in the parent company for 2002.
Delivery capital expenditures are comprised of T&D infrastructure additions
and upgrades, capital replacements, new customer construction and related
information systems and facility costs. Examples of the types of projects
included in the forecast include T&D lines and substations, line extensions to
new residential and commercial developments and upgrades to customer information
systems. In addition, APS began several major transmission projects in 2001.
These projects are periodic in nature and are driven by strong regional customer
growth. APS expects to spend about $105 million on major transmission projects
during the 2003 to 2005 time frame, and these amounts are included in
"APS-Delivery" in the table above.
Generation capital expenditures are comprised of various improvements for
APS' existing fossil and nuclear plants and the replacement of Palo Verde steam
generators. Examples of the types of projects included in this category are
additions, upgrades and capital replacements of various power plant equipment
such as turbines, boilers and environmental equipment. Generation also contains
nuclear fuel expenditures of approximately $30 million annually for 2003 to
2005.
Replacement of the steam generators in Palo Verde Unit 2 is presently
scheduled for completion during the fall outage of 2003. The Palo Verde owners
have approved the manufacture of two additional sets of steam generators. We
expect that these generators will be installed in Units 1 and 3 in the 2005 to
2008 time frame. Our portion of steam generator expenditures for Units 1, 2 and
3 is approximately $145 million, which will be spent from 2003 through 2008. In
2003 through 2005, $94 million of the costs are included in the generation
capital expenditures table above and would be funded with internally-generated
cash or external financings.
CONTRACTUAL OBLIGATIONS
The following table summarizes actual contractual requirements for the year
ended December 31, 2002 and estimated contractual commitments for the next five
years and thereafter (dollars in millions):
47
Actual Estimated
------ ---------------------------------------------------
There-
2002 2003 2004 2005 2006 2007 after
------ ------ ------ ------ ------ ------ ------
Long-term debt payments:
APS $ 337 $ -- $ 205 $ 400 $ 84 $ -- $1,518
Pinnacle West -- 275 215 -- 300 -- --
SunCor 3 -- 126 -- 3 -- 15
El Dorado 13 1 1 1 -- -- --
------ ------ ------ ------ ------ ------ ------
Total long-term debt payments 353 276 547 401 387 -- 1,533
Capital lease payments 1 5 5 4 3 3 6
Operating lease payments 69 70 66 64 63 63 478
Purchase power and fuel commitments 338 173 82 28 31 17 162
------ ------ ------ ------ ------ ------ ------
Total contractual commitments $ 761 $ 524 $ 700 $ 497 $ 484 $ 83 $2,179
====== ====== ====== ====== ====== ====== ======
OFF-BALANCE SHEET ARRANGEMENTS
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 requires that we consolidate a VIE if we have a
majority of the risk of loss from the VIE's activities or we are entitled to
receive a majority of the VIE's residual returns or both. A VIE is a
corporation, partnership, trust or any other legal structure that either does
not have equity investors with voting rights or has equity investors that do not
provide sufficient financial resources for the entity to support its activities.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.
In 1986, APS entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. See Note 9 for
further information about the sale-leaseback transactions. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to
consolidate the Palo Verde SPEs. However, we continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.
APS is also exposed to losses under the Palo Verde sale-leaseback
agreements upon the occurrence of certain events that APS does not consider to
be reasonably likely to occur. Under certain circumstances (for example, the NRC
issuing specified violation orders with respect to Palo Verde or the occurrence
of specified nuclear events), APS would be required to assume the debt
associated with the transactions, make specified payments to the equity
participants and take title to the leased Unit 2 interests, which, if
appropriate, may be required to be written down in value. If such an event had
occurred as of December 31, 2002, APS would have been required to assume
approximately $285 million of debt and pay the equity participants approximately
$200 million.
GUARANTEES
We and certain of our subsidiaries have issued guarantees in support of our
unregulated businesses. We have also obtained surety bonds on behalf of APS
48
Energy Services. We have not recorded any liability on our Consolidated Balance
Sheets with respect to these obligations. See Note 23 for additional information
regarding guarantees.
CREDIT RATINGS
The ratings of securities of Pinnacle West and APS as of March 28, 2003 are
shown below and are considered to be "investment-grade" ratings. The ratings
reflect the respective views of the rating agencies, from which an explanation
of the significance of their ratings may be obtained. There is no assurance that
these ratings will continue for any given period of time. The ratings may be
revised or withdrawn entirely by the rating agencies, if, in their respective
judgments, circumstances so warrant. Any downward revision or withdrawal may
adversely affect the market price of Pinnacle West's or APS' securities and
serve to increase those companies' cost of and access to capital.
Moody's Standard & Poor's Fitch
------- ----------------- -----
PINNACLE WEST
Senior unsecured Baa2 BBB- BBB
Commercial paper P-2 A-2 F-2
APS
Senior secured A3 A- A-
Senior unsecured Baa1 BBB BBB+
Secured lease
obligation bonds Baa2 BBB BBB
Commercial paper P-2 A-2 F-2
On November 4, 2002, Standard & Poor's affirmed the APS debt ratings in the
above chart, but lowered Pinnacle West's senior unsecured debt rating from BBB
to BBB- "because of the structural subordination of this debt as compared to the
unsecured debt at APS." On that same date, Standard & Poor's lowered APS'
corporate credit rating from BBB+ to BBB and affirmed the BBB corporate credit
rating of Pinnacle West. Standard & Poor's assigned a stable outlook to the
ratings. All of Pinnacle West's and APS' credit ratings remain investment grade.
In December 2002, Fitch placed certain of our debt and that of APS on Ratings
Watch Negative. The ratings watch affects our senior unsecured debt and
commercial paper ratings. It also affects all of APS' debt ratings, with the
exception of its commercial paper rating.
On December 31, 2002, Moody's affirmed the ratings set forth above.
DEBT PROVISIONS
Pinnacle West's and APS' significant debt covenants related to their
respective financing arrangements include a debt-to-total-capitalization ratio
and an interest coverage test. Pinnacle West and APS are in compliance with such
covenants and each anticipates it will continue to meet all the significant
covenant requirement levels. The ratio of debt to total capitalization cannot
exceed 65% for both the Company and APS. At December 31, 2002, the ratios are
approximately 54% and 48% for the parent company and APS, respectively. The
provisions regarding interest coverage require a minimum cash coverage of two
times the interest requirements for both the Company and APS. The coverages are
approximately 4 times for the parent company, 5 times for the APS bank
agreements and 15 times for the APS mortgage indenture. Failure to comply with
49
such covenant levels would result in an event of default which, generally
speaking, would require the immediate repayment of the debt subject to the
covenants.
Neither Pinnacle West's nor APS' financing agreements contain "ratings
triggers" that would result in an acceleration of the required interest and
principal payments in the event of a ratings downgrade. However, in the event of
a ratings downgrade, Pinnacle West and/or APS may be subject to increased
interest costs under certain financing agreements.
All of Pinnacle West's bank agreements contain "cross-default" provisions
that would result in defaults and the potential acceleration of payment under
these loan agreements if Pinnacle West or APS were to default under other
agreements. All of APS' bank agreements contain cross-default provisions that
would result in defaults and the potential acceleration of payment under these
bank agreements if APS were to default under other agreements. Pinnacle West's
and APS' credit agreements generally contain provisions under which the lenders
could refuse to advance loans in the event of a material adverse change in our
financial condition or financial prospects.
PINNACLE WEST (PARENT COMPANY)
Our primary cash needs are for dividends to our shareholders; equity
infusions into our subsidiaries, primarily Pinnacle West Energy; and interest
payments and optional and mandatory repayments of principal on our long-term
debt (see the table above for our contractual requirements, including our debt
repayment obligations, but excluding optional repayments). On October 23, 2002,
our board of directors increased the common stock dividend to an indicated
annual rate of $1.70 per share from $1.60 per share, effective with the December
1, 2002 dividend payment. The level of our common dividends and future dividend
growth will be dependent on a number of factors including, but not limited to,
payout ratio trends, free cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external financings and
cash distributions from our other subsidiaries, primarily SunCor. For the years
2000 through 2002, total dividends from APS were $510 million and total
distributions from SunCor were $33 million. For the year ended December 31,
2002, dividends from APS were approximately $170 million and distributions from
SunCor were approximately $13 million. We expect SunCor to make cash
distributions to the parent company of $80 million to $100 million annually in
2003 through 2005 due to anticipated accelerated asset sales activity.
On December 23, 2002, we issued 6,555,000 shares of common stock, no par
value, which resulted in net proceeds of $199 million. See Note 7.
We have financed Pinnacle West Energy's generation construction program
premised upon Pinnacle West Energy's receipt of APS' generation assets by the
end of 2002. On November 22, 2002, the ACC approved APS' request (Interim
Financing Application) to permit APS to (a) make short-term advances to Pinnacle
West in the form of an inter-affiliate line of credit in the amount of $125
million, or (b) guarantee $125 million of Pinnacle West's short-term debt,
subject to certain conditions. As of December 31, 2002, there were no borrowings
outstanding under this financing arrangement. On March 27, 2003, the ACC
authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up
to $500 million of Pinnacle West Energy debt, or a combination of both, not to
50
exceed $500 million in the aggregate. See "Factors Affecting our Financial
Outlook - Regulatory Matters" and "ACC Applications" in Note 3 for additional
information.
In 2002, the parent company issued $215 million in long-term debt and had
no repayments of long-term debt (see Note 6).
The parent company's outstanding long and short-term debt was approximately
$887 million at December 31, 2002. At December 31, 2002, our commitments totaled
$475 million, which were available to support the issuance of commercial paper
or to be used as bank borrowings. At December 31, 2002, we had about $24 million
of commercial paper outstanding and $72 million of short-term borrowings. Our
long-term debt including current maturities totaled $791 million at December 31,
2002.
In mid-2003, we will need to refinance approximately $475 million of parent
company indebtedness, including a total of $225 million we expect to borrow
under an existing credit facility. We expect that this indebtedness will be
repaid through funds borrowed by Pinnacle West Energy from APS under the $500
million financing arrangement recently approved by the ACC.
As part of a multi-employer pension plan sponsored by Pinnacle West, we
contribute at least the minimum amount required under IRS regulations, but no
more than the maximum tax-deductible amount. The minimum required funding takes
into consideration the value of the fund assets and our pension obligation. We
elected to contribute cash to our pension plan in each of the last five years;
our minimum required contributions during each of those years was zero.
Specifically, we contributed $27 million for 2002, $24 million for 2001, $44
million for 2000, $25 million for 1999 and $14 million for 1998. APS and other
subsidiaries fund their share of the pension contribution, of which APS
represents approximately 90% of the total funding amounts described above. The
assets in the plan are mostly domestic common stocks, bonds and real estate. We
currently forecast a pension contribution in 2003 of approximately $50 million,
all or part of which may be required. If the fund performance continues to
decline as a result of a continued decline in equity markets, larger
contributions may be required in future years.
As a result of a change in IRS guidance, we claimed a tax deduction related
to an APS tax accounting method change on the 2001 federal consolidated income
tax return. The accelerated deduction has resulted in a $200 million reduction
in the current income tax liability. In 2002, we received an income tax refund
of approximately $115 million related to our 2001 federal consolidated income
tax return.
APS
APS' capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. See "Factors Affecting Our
Financial Outlook - Regulatory Matters" below and Note 3 for discussion of the
$500 million financing arrangement between APS and Pinnacle West Energy recently
approved by the ACC. See "Pinnacle West (Parent Company)" above and Note 3 for
discussion of a $125 million financing arrangement between APS and Pinnacle
West.
51
APS pays for its capital requirements with cash from operations and, to the
extent necessary, external financings. APS has historically paid for its
dividends to Pinnacle West with cash from operations.
In 2002, APS issued $375 million in long-term debt, refinanced $90 million
in long-term debt and redeemed approximately $247 million in long-term debt (see
Note 6). On April 7, 2003, APS will redeem $33 million of its first mortgage
bonds.
APS' outstanding debt was approximately $2.2 billion at December 31, 2002.
At December 31, 2002, APS had credit commitments from various banks totaling
about $250 million, which were available either to support the issuance of
commercial paper or to be used as bank borrowings. At December 31, 2002, APS had
no outstanding commercial paper or bank borrowings.
Although provisions in APS' first mortgage bond indenture, articles of
incorporation and ACC financing orders establish maximum amounts of additional
first mortgage bonds, debt and preferred stock that APS may issue, APS does not
expect any of these provisions to limit its ability to meet its capital
requirements.
PINNACLE WEST ENERGY
The costs of Pinnacle West Energy's construction of generating capacity
from 2000 through 2004 are expected to be about $1.4 billion. This does not
reflect an expected reimbursement in 2004 by SNWA of about $100 million of
Pinnacle West Energy's cumulative capital expenditures in the Silverhawk
project, assuming SNWA exercises its option to purchase a 25% interest in the
project. Pinnacle West Energy is currently funding its capital requirements
through capital infusions from Pinnacle West, which finances those infusions
through debt and equity financings and internally-generated cash. See the
capital expenditures table above for actual capital expenditures in 2002 and
projected capital expenditures for the next three years.
See "Factors Affecting Our Financial Outlook - Regulatory Matters" below
and Note 3 for discussion of the $500 million.
OTHER SUBSIDIARIES
During the past three years, SunCor funded its cash requirements with cash
from operations and its own external financings. SunCor's capital needs consist
primarily of capital expenditures for land development and retail and office
building construction. See the capital expenditures table above for actual
capital expenditures in 2002 and projected capital expenditures for the next
three years. SunCor expects to fund its capital requirements with cash from
operations and external financings.
In 2002, SunCor issued $50 million in long-term debt, and redeemed,
refinanced or repaid $53 million in long-term debt (see Note 6).
SunCor's outstanding long and short-term debt was approximately $153
million as of December 31, 2002. As of December 31, 2002, SunCor had a $140
million line of credit, under which $126 million of borrowings were outstanding.
SunCor's short-term debt was $6 million and other long-term debt, including
current maturities, totaled $21 million at December 31, 2002.
52
We expect SunCor to make cash distributions to the parent company of $80 to
$100 million annually in 2003 through 2005 due to anticipated accelerated asset
sales activity.
El Dorado funded its cash requirements during the past three years,
primarily for NAC in 2002, with cash infused by the parent company and with cash
from operations. El Dorado expects minimal capital requirements over the next
three years and intends to focus on prudently realizing the value of its
existing investments. El Dorado's long-term debt was approximately $3 million at
December 31, 2002 and it had no long-term debt outstanding at December 31, 2001.
El Dorado's long-term debt increased primarily due to its consolidation of NAC
for financial reporting purposes (see Notes 6 and 22).
APS Energy Services' cash requirements during the past three years were
funded with cash infusions from the parent company. APS Energy Services' capital
expenditures and other cash requirements are increasingly funded by operations,
with some funding from cash infused by Pinnacle West. See the capital
expenditures table above regarding APS Energy Services' actual capital
expenditures for 2002 and projected capital expenditures for the next three
years.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from
those estimates. We consider the following accounting policies to be our most
critical because of the uncertainties, judgments and complexities of the
underlying accounting standards and operations involved.
* Regulatory Accounting - Regulatory accounting allows for the actions
of regulators, such as the ACC and the FERC, to be reflected in the
financial statements. Their actions may cause us to capitalize costs
that would otherwise be included as an expense in the current period
by unregulated companies.
* Pensions and Other Postretirement Benefit Accounting - Changes in our
actuarial assumptions used in calculating our pension and other
postretirement benefit liability and expense can have a significant
impact on our earnings and financial position. The most relevant
actuarial assumptions are the discount rate used to measure our
liability and the expected long-term rate of return on plan assets
used to estimate earnings on invested funds over the long-term.
* Derivative Accounting - Derivative accounting requires evaluation of
rules that are complex and subject to varying interpretations. Our
evaluation of these rules, as they apply to our contracts, will
determine whether we use accrual accounting or fair value
(mark-to-market) accounting. Mark-to-market accounting requires that
changes in fair value be recorded in earnings or, if certain hedge
accounting criteria are met, in other comprehensive income.
53
* Mark-to-Market Accounting - The market value of our derivative
contracts is not always readily determinable. In some cases, we use
models and other valuation techniques to determine fair value. The use
of these models and valuation techniques sometimes requires subjective
and complex judgment. Actual results could differ from the results
estimated through application of these methods. Our marketing and
trading portfolio consists of structured activities hedged with a
portfolio of forward purchases that protects the economic value of the
sales transactions.
See the discussion below for further details on our critical accounting
policies.
REGULATORY ACCOUNTING
For our regulated operations, we prepare our financial statements in
accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to
reflect the impact of regulatory decisions in its financial statements. As a
result, we capitalize certain costs that would be included as expense in the
current period by unregulated companies. Regulatory assets represent incurred
costs that have been deferred because they are probable of future recovery in
customer rates. Regulatory liabilities generally represent obligations to make
refunds to customers for previous collections of costs not likely to be
incurred.
We are required to discontinue applying SFAS No. 71 when deregulatory
legislation is passed or a rate order is issued that contains sufficient detail
to determine its effect on the portion of the business being deregulated. In
1999, we discontinued the application of SFAS No. 71 for APS' generation
operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a
discussion of the 1999 Settlement Agreement.
In 2002, the ACC directed APS not to transfer its generation assets, as
previously required by the 1999 Settlement Agreement (see "Track A Order" in
Note 3). Accordingly, we now consider APS generation to be cost-based,
rate-regulated and subject to the requirements of SFAS No. 71. The impact of
this change was immaterial to our consolidated financial statements.
Management continually assesses whether our regulatory assets are probable
of future recovery by considering factors such as applicable regulatory
environment changes and recent rate orders to other regulated entities in the
same jurisdiction. This determination reflects the current political and
regulatory climate in the state and is subject to change in the future. If
future recovery of costs ceases to be probable, the assets would be written off
as a charge to current period earnings. We had $241 million of regulatory assets
included on the Consolidated Balance Sheets at December 31, 2002. See Notes 1
and 3 for more information.
PENSIONS AND OTHER POSTRETIREMENT BENEFIT ACCOUNTING
We sponsor a qualified defined benefit pension plan and a non-qualified
supplemental excess benefit retirement plan for our employees and employees of
our subsidiaries. Our reported costs of providing defined pension and other
postretirement benefits are dependent upon numerous factors resulting from
actual plan experience and assumptions of future experience. Pension and other
postretirement benefit costs, for example, are impacted by actual employee
demographics (including age, compensation levels and employment periods), the
level of contributions we make to the plans and earnings on plan assets. Changes
made to the provisions of the plans may also impact current and future pension
and other postretirement benefit costs. Pension and other postretirement benefit
54
costs may also be significantly affected by changes in key actuarial
assumptions, including the expected long-term rate of return on plan assets and
the discount rates used in determining the projected benefit obligation and
pension and other postretirement benefit costs.
Pinnacle West's pension and other postretirement plan assets are primarily
made up of equity and fixed income investments. Fluctuations in actual equity
market returns as well as changes in general interest rates may result in
increased or decreased pension and other postretirement benefit costs in future
periods. Likewise, changes in assumptions regarding current discount rates and
the expected long-term rate of return on plan assets could also increase or
decrease recorded pension and other postretirement benefit costs.
We account for our defined benefit pension plans in accordance with SFAS
No. 87, "Employers' Accounting for Pensions," which requires amounts recognized
in our financial statements to be determined on an actuarial basis. Changes in
pension obligations associated with these factors may not be immediately
recognized as pension costs on the income statement, but generally are
recognized in future years over the remaining average service period of plan
participants. As such, significant portions of pension costs recorded in any
period may not reflect the actual level of cash benefits provided to plan
participants.
The following chart reflects the sensitivities associated with a one
percent increase or decrease in certain actuarial assumptions related to our
defined benefit pension plans. Each sensitivity below reflects the impact of
changing only that assumption. The chart shows the increase (decrease) each
change in assumption would have on the 2002 projected benefit obligation, our
2002 reported pension liability on the Consolidated Balance Sheets and our 2002
reported annual pension expense, after consideration of amounts capitalized or
billed to electric plant participants, on the Consolidated Statements of Income
(dollars in millions).
Increase/(Decrease)
-------------------------------------------------------------------
Impact on
Projected Impact on Impact on
Benefit Pension Pension
Actuarial Assumption Obligation Liability Expense
-------------------------------------------------------------------
Discount rate:
Increase 1% $ (143) $ (107) $ (4)
Decrease 1% 177 130 9
Expected long-term rate
of return on plan assets:
Increase 1% -- -- (4)
Decrease 1% -- -- 4
At the end of each year, we determine the discount rate to be used to
calculate the present value of plan liabilities. The discount rate is an
estimate of the current interest rate at which the pension liabilities could be
effectively settled at the end of the year. The discount rate is selected by
comparison to current yields on high-quality, long-term bonds. We changed our
discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31,
2002.
55
In 2002, we assumed that the expected long-term rate of return on plan
assets would be 10%. However, the plan assets have earned a rate of return
substantially less than 10% in the last three years due to sharp declines in the
equity markets. For 2003, we decreased our expected long-term rate of return on
plan assets to 9%, as a result of continued declines in general equity and bond
market returns.
The following chart reflects the sensitivities associated with a one
percent increase or decrease in certain actuarial assumptions related to our
other postretirement benefit plans. Each sensitivity below reflects the impact
of changing only that assumption. The chart shows the increase (decrease) each
change in assumption would have on the 2002 accumulated other postretirement
benefit obligation and our 2002 reported other postretirement benefit expense,
after consideration of amounts capitalized or billed to electric plant
participants, on the Consolidated Statements of Income (dollars in millions).
Increase/(Decrease)
----------------------------------------------------------------------
Impact on Accumulated Impact on Other
Postretirement Benefit Postretirement Benefit
Actuarial Assumption Obligation Expense
----------------------------------------------------------------------
Discount rate:
Increase 1% $(38) $ (2)
Decrease 1% 43 2
Health care cost trend
rate (a):
Increase 1% 54 5
Decrease 1% (43) (4)
Expected long-term rate
of return on plan
assets - pretax:
Increase 1% -- (1)
Decrease 1% -- 1
(a) This assumes a 1% change in the initial and ultimate health care cost trend
rate.
The discount rate is selected by comparison to current yields on
high-quality, long-term bonds. We changed our discount rate assumption from 7.5%
at December 31, 2001 to 6.75% at December 31, 2002.
In selecting our health care cost trend rate, we consider past performance
and forecasts of health care costs. In 2002, we increased our initial health
care cost trend rate to 8% from 7% based on an analysis of our actual plan
experience. We also assume an ultimate health care cost trend rate of 5% is
reached in 2007.
In selecting the pretax expected long-term rate of return on plan assets,
we consider past performance and economic forecasts for the types of investments
held by the plan. The market value of the plan assets has been affected by sharp
declines in the equity markets. For 2003, we decreased our pretax expected
long-term rate of return on plan assets from 10% to 9%, as a result of continued
declines in general equity and bond market returns.
56
Pension and other postretirement benefit costs and cash funding
requirements may increase in future years without a substantial recovery in the
equity markets. Due to the actual investment performance of our pension and
other postretirement benefit funds and the changes in the actuarial assumptions
discussed above, we expect an increase of approximately $29 million before
income taxes in 2003 expense over 2002. See Note 8 for further details about our
pension and other postretirement benefit plans.
DERIVATIVE ACCOUNTING
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We manage risks associated with these market fluctuations by utilizing various
commodity derivatives, including exchange-traded futures and options and
over-the-counter forwards, options and swaps. As part of our risk management
program, we enter into derivative transactions to hedge purchases and sales of
electricity, fuels and emissions allowances and credits. The changes in market
value of such contracts have a high correlation to price changes in the hedged
commodities. In addition, subject to specified risk parameters monitored by the
ERMC, we engage in marketing and trading activities intended to profit from
market price movements.
We examine contracts at inception to determine the appropriate accounting
treatment. If a contract does not meet the derivative criteria or if it
qualifies for a SFAS No. 133 scope exception, we account for the contract on an
accrual basis with associated revenues and costs recorded at the time the
contracted commodities are delivered or received. SFAS No. 133 provides a scope
exception for contracts that meet the normal purchases and sales criteria
specified in the standard. Most of our non-trading electricity purchase and
sales agreements qualify as normal purchases and sales and are exempted from
recognition in the financial statements until the electricity is delivered.
For contracts that qualify as a derivative and do not meet a SFAS No. 133
scope exception, we further examine the contract to determine if it will qualify
for hedge accounting. Changes in the fair value of the effective portion of
derivative instruments that qualify for cash flow hedge accounting treatment are
recognized as either an asset or liability and in common stock equity (as a
component of accumulated other comprehensive income (loss)). Gains and losses
related to derivatives that qualify as cash flow hedges of expected transactions
are recognized in revenue or purchased power and fuel expense as an offset to
the related item being hedged when the underlying hedged physical transaction
impacts earnings. If a contract does not meet the hedging criteria in SFAS No.
133, we recognize the changes in the fair value of the derivative instrument in
income each period through mark-to-market accounting.
On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a
result, our energy trading contracts that are derivatives continue to be
accounted for at fair value under SFAS No. 133. Contracts that were previously
marked-to-market as trading activities under EITF 98-10 that do not meet the
accounting definition of a derivative are now accounted for on an accrual basis
with the associated revenues and costs recorded at the time the contracted
commodities are delivered or received. Additionally, all gains and losses
(realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.
See "Other Accounting Matters - Accounting for Derivative and Trading
57
Activities" below for details on the change in accounting for energy trading
contracts. See Note 18 for further discussion on derivative accounting.
MARK-TO-MARKET ACCOUNTING
Under mark-to-market accounting, the purchase or sale of energy commodities
is reflected at fair market value, net of valuation adjustments, with resulting
unrealized gains and losses recorded as assets and liabilities from risk
management and trading activities in the Consolidated Balance Sheets.
We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. We shape quarterly and calendar year quotes into monthly
prices based on historical relationships.
For options, long-term contracts and other contracts for which price quotes
are not available, we use models and other valuation methods. The valuation
models we employ utilize spot prices, forward prices, historical market data and
other factors to forecast future prices. The primary valuation technique we use
to calculate the fair value of contracts where price quotes are not available is
based on the extrapolation of forward pricing curves using observable market
data for more liquid delivery points in the same region and actual transactions
at the more illiquid delivery points. We also value option contracts using a
variation of the Black-Scholes option-pricing model.
For non-exchange traded contracts, we calculate fair market value based on
the average of the bid and offer price, and we discount to reflect net present
value. We maintain certain valuation adjustments for a number of risks
associated with the valuation of future commitments. These include valuation
adjustments for liquidity and credit risks based on the financial condition of
counterparties. The liquidity valuation adjustment represents the cost that
would be incurred if all unmatched positions were closed-out or hedged.
A credit valuation adjustment is also recorded to represent estimated
credit losses on our overall exposure to counterparties, taking into account
netting arrangements; expected default experience for the credit rating of the
counterparties; and the overall diversification of the portfolio. Counterparties
in the portfolio consist principally of major energy companies, municipalities
and local distribution companies. We maintain credit policies that management
believes minimize overall credit risk. Determination of the credit quality of
counterparties is based upon a number of factors, including credit ratings,
financial condition, project economics and collateral requirements. When
applicable, we employ standardized agreements that allow for the netting of
positive and negative exposures associated with a single counterparty. See
"Factors Affecting our Financial Outlook - Market Risks - Commodity Price Risk"
below and Note 18 for further discussion on credit risk.
The use of models and other valuation methods to determine fair market
value often requires subjective and complex judgment. Actual results could
differ from the results estimated through application of these methods. Our
marketing and trading portfolio includes structured activities hedged with a
portfolio of forward purchases that protects the economic value of the sales
58
transactions. To illustrate, as presented in the "Factors Affecting our
Financial Outlook - Market Risks - Commodity Price Risk" section below, a 10%
increase in the price of trading commodities would result in only a $2 million
decrease in pretax income. Our practice is to hedge within timeframes
established by the ERMC.
OTHER ACCOUNTING MATTERS
ACCOUNTING FOR DERIVATIVE AND TRADING ACTIVITIES
During 2002, the EITF discussed EITF 02-3 and reached a consensus on
certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25,
2002 for any new contracts, and on January 1, 2003 for existing contracts, with
early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in
the fourth quarter of 2002. We recorded a $66 million after-tax charge in net
income as a cumulative effect adjustment for the previously recorded accumulated
unrealized mark-to-market on energy trading contracts that did not meet the
accounting definition of a derivative. As a result, our energy trading contracts
that are derivatives continue to be accounted for at fair value under SFAS No.
133. Contracts that were previously marked-to-market as trading activities under
EITF 98-10 that do not meet the definition of a derivative are now accounted for
on an accrual basis with the associated revenues and costs recorded at the time
the contracted commodities are delivered or received. Additionally, all gains
and losses (realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.
EITF 02-3 requires that derivatives held for trading purposes, whether
settled financially or physically, be reported in the income statement on a net
basis. Previous guidance under EITF 98-10 permitted physically settled energy
trading contracts to be reported either gross or net in the income statement.
Beginning in the third quarter of 2002, we netted all of our energy trading
activities on the Consolidated Statements of Income and restated prior year
amounts for all periods presented. Reclassification of such trading activity to
a net basis of reporting resulted in reductions in both revenues and purchased
power and fuel costs, but did not have any impact on our financial condition,
results of operations or cash flows.
In 2001, we adopted SFAS No. 133 and recorded a $15 million after-tax
charge in net income and a $72 million after-tax credit in common stock equity
(as a component of other comprehensive income), both as a cumulative effect of a
change in accounting for derivatives. See Notes 1 and 18 for further information
on accounting for derivatives under SFAS No. 133.
ASSET RETIREMENT OBLIGATIONS
On January 1, 2003 we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." The standard requires the fair value of asset
retirement obligations to be recorded as a liability, along with an offsetting
plant asset, when the obligation is incurred. Accretion of the liability due to
the passage of time will be an operating expense and the capitalized cost is
depreciated over the useful life of the long-lived asset. (See Note 1 for more
information regarding our previous accounting for removal costs.)
59
We determined that we have asset retirement obligations for our nuclear
facilities (nuclear decommissioning) and certain other generation, transmission
and distribution assets. On January 1, 2003 we recorded a liability of $219
million for our asset retirement obligations including the accretion impacts; a
$67 million increase in the carrying amount of the associated assets; and a net
reduction of $192 million in accumulated depreciation related primarily to the
reversal of previously recorded accumulated decommissioning and other removal
costs related to these obligations. Additionally, we recorded a regulatory
liability of $40 million for our asset retirement obligations related to our
regulated utility. This regulatory liability represents the difference between
the amount currently being recovered in regulated rates and the amount
calculated under SFAS No. 143. We believe we can recover in regulated rates the
transition costs and ongoing current period costs calculated in accordance with
SFAS No. 143.
STOCK-BASED COMPENSATION
In the third quarter of 2002, we began applying the fair value method of
accounting for stock-based compensation, as provided for in SFAS No. 123,
"Accounting for Stock-Based Compensation." We recorded approximately $500,000 in
stock option expense before income taxes in our Consolidated Statements of
Income for 2002. See Notes 1 and 16 for further information on the impacts of
adopting the fair value method provided in SFAS No. 123.
VARIABLE INTEREST ENTITIES
See "Liquidity and Capital Resources - Off-Balance Sheet Arrangements" and
Note 20 for discussion of VIEs.
OTHER
See Note 2 for discussion of other new accounting standards that are not
expected to have a material impact on the Company.
FACTORS AFFECTING OUR FINANCIAL OUTLOOK
REGULATORY MATTERS
GENERAL
On September 21, 1999, the ACC approved Rules that provide a framework for
the introduction of retail electric competition in Arizona. On September 23,
1999, the ACC approved a comprehensive settlement agreement among APS and
various parties related to the implementation of retail electric competition in
Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was
required to transfer all of its competitive electric assets and services to an
unaffiliated party or parties or to a separate corporate affiliate or affiliates
no later than December 31, 2002. Consistent with that requirement, APS had been
addressing the legal and regulatory requirements necessary to complete the
transfer of its generation assets to Pinnacle West Energy on or before that
date. On September 10, 2002, the ACC issued the Track A Order, which, among
other things, directed APS not to transfer its generation assets to Pinnacle
West Energy.
60
1999 SETTLEMENT AGREEMENT
The 1999 Settlement Agreement has affected, and will affect, our results of
operations. As part of the 1999 Settlement Agreement, APS agreed to reduce
retail electricity prices for standard-offer, full-service customers with loads
less than three megawatts in a series of annual decreases of 1.5% on July 1,
1999 through July 1, 2003, for a total of 7.5%. For customers with loads three
megawatts or greater, standard-offer rates were reduced in annual increments
totaling 5% in the years 1999 through 2002.
The 1999 Settlement Agreement also removed, as a regulatory disallowance,
$234 million before income taxes ($183 million net present value) from ongoing
regulatory cash flows. APS recorded this regulatory disallowance as a net
reduction of regulatory assets and reported it as a $140 million after-tax
extraordinary charge on the 1999 Consolidated Statement of Income. As discussed
under "APS General Rate Case" below, APS intends to seek recovery of this $234
million write-off in its next general rate case.
Prior to the 1999 Settlement Agreement, the ACC accelerated the
amortization of substantially all of APS' regulatory assets to an eight-year
period that would have ended June 30, 2004. The regulatory assets to be
recovered under the 1999 Settlement Agreement are currently being amortized as
follows (dollars in millions):
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $686
See Note 3 for additional information regarding the 1999 Settlement
Agreement.
APS FINANCING APPLICATION
On September 16, 2002, APS filed an application with the ACC requesting the
ACC to allow APS to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to the Company; to guarantee up to $500 million of
Pinnacle West Energy's or the Company's debt; or a combination of both, not to
exceed $500 million in the aggregate. In its application, APS stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between APS and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing that we
provided to fund the construction of Pinnacle West Energy generation assets or
from effectively competing in the wholesale markets. On March 27, 2003, the ACC
authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up
to $500 million of Pinnacle West Energy debt, or a combination of both, not to
exceed $500 million in the aggregate. See "ACC Applications" in Note 3 for
further discussion of the approval and related conditions.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order. See "Track A
Order" in Note 3.
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COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that APS competitively procure certain power
requirements. On March 14, 2003, the ACC issued the Track B Order, which
documented the decision made by the ACC at its open meeting on February 27, 2003
addressing this requirement. Under the ACC's Track B Order, APS will be required
to solicit bids for certain estimated capacity and energy requirements for
periods beginning July 1, 2003. For 2003, APS will be required to solicit
competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours
of energy, or approximately 20% of APS' total retail energy requirements. The
bid amounts are expected to increase in 2004 and 2005 based largely on growth in
APS' retail load and APS' retail energy sales. The Track B Order also confirmed
that it was "not intended to change the current rate base status of [APS']
existing assets." The order recognizes APS' right to reject any bids that are
unreasonable, uneconomical or unreliable.
APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements. See "Track B Order" in Note 3 for
additional information.
APS GENERAL RATE CASE
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
APS will file a general rate case with the ACC. In this rate case, APS will
update its cost of service and rate design. In addition, APS expects to seek:
* rate base treatment of certain power plants currently owned by
Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
Phoenix Units 4 and 5 and Saguaro Unit 3);
* recovery of the $234 million pretax asset write-off recorded by APS
as part of the 1999 Settlement Agreement ($140 million extraordinary
charge recorded on the 1999 Consolidated Statement of Income); and
* recovery of costs incurred by APS in preparation for the previously
required transfer of generation assets to Pinnacle West Energy.
We assume that the ACC will make a decision in this general rate case by the end
of 2004.
WHOLESALE POWER MARKET CONDITIONS
The marketing and trading division, which we moved to APS in early 2003 for
future marketing and trading activities (existing wholesale contracts will
remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting APS'
transfer of generating assets to Pinnacle West Energy, focuses primarily on
managing APS' purchased power and fuel risks in connection with its costs of
serving retail customer demand. Additionally, the marketing and trading
division, subject to specified parameters, markets, hedges and trades in
electricity, fuels and emission allowances and credits. Earnings contributions
from our marketing and trading division were lower in 2002 compared to 2001 due
to weak wholesale power market conditions in the western United States, which
62
included a lack of market liquidity, fewer creditworthy counterparties, lower
wholesale market prices and resulting decreases in sales volumes. Our 2003
earnings will be affected by the strength (or weakness) of the wholesale power
market.
GENERATION CONSTRUCTION
See "Capital Needs and Resources - Pinnacle West Energy" above and Note 11
for information regarding Pinnacle West Energy's generation construction
program. The planned additional generation is expected to increase revenues,
fuel expenses, operating expenses and financing costs.
FACTORS AFFECTING OPERATING REVENUES
GENERAL Electric operating revenues are derived from sales of electricity
in regulated retail markets in Arizona and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer as well as electricity prices and
variations in weather from period to period. Competitive sales of energy and
energy-related products and services are made by APS Energy Services in western
states that have opened to competitive supply.
CUSTOMER GROWTH Customer growth in APS' service territory averaged about
3.6% a year for the three years 2000 through 2002; we currently expect customer
growth to average about 3.5% per year from 2003 to 2005. We currently estimate
that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in
2003 through 2005, before the retail effects of weather variations. The customer
growth and sales growth referred to in this paragraph applies to energy delivery
customers. As previously noted, under the 1999 Settlement Agreement, we agreed
to retail electricity price reductions of 1.5% annually through July 1, 2003
(see Note 3).
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
PURCHASED POWER AND FUEL COSTS Purchased power and fuel costs are impacted
by our electricity sales volumes, existing contracts for purchased power and
generation fuel, our power plant performance, prevailing market prices, new
generating plants being placed in service and our hedging program for managing
such costs.
OPERATIONS AND MAINTENANCE EXPENSES Operations and maintenance expenses are
expected to be affected by sales mix and volumes, power plant additions and
operations, inflation, outages, higher trending pension and other postretirement
benefit costs and other factors. In July 2002, we implemented a voluntary
workforce reduction as part of our cost reduction program. We recorded $36
million before taxes in voluntary severance costs in the second half of 2002. In
addition, we are expecting to produce annual operating expense savings of
approximately $30 million beginning in 2003 as a result of this workforce
reduction.
DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization
expenses are expected to be affected by net additions to existing utility plant
and other property, changes in regulatory asset amortization and our generation
construction program. West Phoenix Unit 4 was placed in service in June 2001.
Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in
63
July 2002. West Phoenix Unit 5 is expected to be on line in mid-2003 and
Silverhawk is expected to be in service in mid-2004 (see Note 11 for further
details about our generation construction program). The regulatory assets to be
recovered under the 1999 Settlement Agreement are currently being amortized as
follows (dollars in millions):
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $ 686
PROPERTY TAXES Taxes other than income taxes consist primarily of property
taxes, which are affected by tax rates and the value of property in-service and
under construction. The average property tax rate for APS, which currently owns
the majority of our property, was 9.7% of assessed value for 2002 and 9.3% for
2001. We expect property taxes to increase primarily due to our generation
construction program and our additions to existing facilities.
INTEREST EXPENSE Interest expense is affected by the amount of debt
outstanding and the interest rates on that debt. The primary factors affecting
borrowing levels in the next several years are expected to be our capital
requirements and our internally-generated cash flow. Capitalized interest
offsets a portion of interest expense while capital projects are under
construction. We stop recording capitalized interest on a project when it is
placed in commercial operation. As noted above, we have placed new power plants
in commercial operation in 2001 and 2002 and we expect to bring additional
plants on-line in 2003 and 2004. We are continuing to evaluate our generation
construction program. Interest expense is affected by interest rates on
variable-rate debt and interest rates on the refinancing of the Company's future
liquidity needs.
RETAIL COMPETITION The regulatory developments and legal challenges to the
Rules discussed in Note 3 have raised considerable uncertainty about the status
and pace of retail electric competition in Arizona. Although some very limited
retail competition existed in APS' service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to APS' customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter APS' service territory.
SUBSIDIARIES In the case of SunCor, we are undertaking an aggressive effort
to accelerate asset sales activities to approximately double SunCor's annual
earnings in 2003 to 2005 compared to the $19 million in earnings recorded in
2002. A portion of these sales could be reported as discontinued operations on
the Consolidated Statements of Income.
The annual earnings contribution from APS Energy Services is expected to be
positive over the next several years due primarily to a number of retail
electricity contracts in California. APS Energy Services' had pretax earnings of
$28 million in 2002.
El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. El Dorado's strategies focus on prudently realizing
the value of its existing investments.
GENERAL Our financial results may be affected by a number of broad factors.
See "Forward-Looking Statements" below for further information on such factors,
which may cause our actual future results to differ from those we currently seek
or anticipate.
64
MARKET RISKS
Our operations include managing market risks related to changes in interest
rates, commodity prices and investments held by the nuclear decommissioning
trust fund and our pension plans.
INTEREST RATE AND EQUITY RISK
Our major financial market risk exposure is changing interest rates.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our pension plan (see Note 8) and nuclear decommissioning
trust fund (see Note 12). Our policy is to manage interest rates through the use
of a combination of fixed-rate and floating-rate debt. The pension plan and
nuclear decommissioning fund also have risks associated with changing market
values of equity investments. Pension (APS only) and nuclear decommissioning
costs are recovered in regulated electricity prices. See "Critical Accounting
Policies - Pension and Other Postretirement Benefit Accounting" for a
sensitivity analysis on the long-term rate of return on plan assets.
The tables below present contractual balances of our consolidated long-term
debt and commercial paper at the expected maturity dates as well as the fair
value of those instruments on December 31, 2002 and 2001. The interest rates
presented in the tables below represent the weighted-average interest rates for
the years ended December 31, 2002 and 2001.
Expected Maturity/Principal Repayment
December 31, 2002
(dollars in thousands)
Variable-Rate Fixed-Rate
Short-Term Debt Long-Term Debt Long-Term Debt
------------------- -------------------- ---------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
----- ------ ----- ------ ----- ------
2003 2.59% $ 102,183 2.68% $ 250,800 6.73% $ 30,223
2004 -- -- 3.76% 126,813 5.32% 424,697
2005 -- -- 3.39% 1,294 7.27% 403,931
2006 -- -- 10.10% 2,954 6.47% 387,018
2007 -- -- 8.00% 209 6.04% 2,738
Years thereafter -- -- 2.00% 390,537 6.08% 1,148,371
--------- --------- -----------
Total $ 102,183 $ 772,607 $ 2,396,978
========= ========= ===========
Fair value $ 102,183 $ 772,607 $ 2,501,073
========= ========= ===========
65
Expected Maturity/Principal Repayment
December 31, 2001
(dollars in thousands)
Variable-Rate Fixed-Rate
Short-Term Debt Long-Term Debt Long-Term Debt
------------------- -------------------- ---------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
----- ------ ----- ------ ----- ------
2002 4.01% $ 405,762 7.76% $ 207 8.10% $ 125,933
2003 -- -- 4.75% 292,912 6.87% 25,829
2004 -- -- 5.32% 85,601 6.08% 205,677
2005 -- -- 7.70% 294 7.59% 400,380
2006 -- -- 7.30% 3,018 6.48% 384,085
Years thereafter -- -- 2.63% 480,740 6.73% 799,808
--------- --------- -----------
Total $ 405,762 $ 862,772 $ 1,941,712
========= ========= ===========
Fair value $ 405,762 $ 862,772 $ 1,963,389
========= ========= ===========
COMMODITY PRICE RISK
We are exposed to the impact of market fluctuations in the commodity price
and transportation costs of electricity, natural gas, coal and emissions
allowances. We manage risks associated with these market fluctuations by
utilizing various commodity derivatives, including exchange-traded futures and
options and over-the-counter forwards, options and swaps. The ERMC, consisting
of senior officers, oversees company-wide energy risk management activities and
monitors the results of marketing and trading activities to ensure compliance
with our stated energy risk management and trading policies. As part of our risk
management program, we enter into derivative transactions to hedge purchases and
sales of electricity, fuels and emissions allowances and credits. The changes in
market value of such contracts have a high correlation to price changes in the
hedged commodities. In addition, subject to specified risk parameters monitored
by the ERMC, we engage in marketing and trading activities intended to profit
from market price movements.
Prior to October 1, 2002, we accounted for our energy trading contracts at
fair value in accordance with EITF 98-10. On October 1, 2002, we adopted EITF
02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that
are derivatives continue to be accounted for at fair value under SFAS No. 133.
Contracts that were previously marked-to-market as trading activities under EITF
98-10 that do not meet the definition of a derivative are now accounted for on
an accrual basis with the associated revenues and costs recorded at the time the
contracted commodities are delivered or received. Additionally, all gains and
losses (realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.
See Note 18 for details on the change in accounting for energy trading contracts
and further discussion regarding derivative accounting.
66
Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the Consolidated
Balance Sheets. For non-trading derivative instruments that qualify for hedge
accounting treatment, changes in the fair value of the effective portion are
recognized in common stock equity (as a component of accumulated other
comprehensive income (loss)). Non-trading derivatives, or any portion thereof,
that are not effective hedges are adjusted to fair value through income. Gains
and losses related to non-trading derivatives that qualify as cash flow hedges
of expected transactions are recognized in revenue or purchased power and fuel
expense as an offset to the related item being hedged when the underlying hedged
physical transaction impacts earnings. If it becomes probable that a forecasted
transaction will not occur, we discontinue the use of hedge accounting and
recognize in income the unrealized gains and losses that were previously
recorded in other comprehensive income (loss). In the event a non-trading
derivative is terminated or settled, the unrealized gains and losses remain in
other comprehensive income (loss), and are recognized in income when the
underlying transaction impacts earnings.
Derivatives associated with trading activities are adjusted to fair value
through income. Derivative commodity contracts for the physical delivery of
purchase and sale quantities transacted in the normal course of business are
exempt from the requirements of SFAS No. 133 under the normal purchase and sales
exception and are not reflected on the balance sheet at fair value. Most of our
non-trading electricity purchase and sales agreements qualify as normal
purchases and sales and are exempted from recognition in the financial
statements until the electricity is delivered.
Our assets and liabilities from risk management and trading activities are
presented in two categories consistent with our business segments:
* System - our regulated electricity business segment, which consists of
non-trading derivative instruments that hedge our purchases and sales
of electricity and fuel for our Native Load requirements; and
* Marketing and Trading - our non-regulated, competitive business
segment, which includes both non-trading and trading derivative
instruments.
The following tables show the changes in mark-to-market of our system and
marketing and trading derivative positions in 2002 and 2001 (dollars in
millions):
67
Marketing
and
System Trading
------ -------
Mark-to-market of net positions
at December 31, 2001 $(107) $ 138
Cumulative effect adjustment due to
adoption of EITF 02-3 -- (109)
Change in mark-to-market gains
for future period deliveries (13) 47
Changes in cash flow hedges
recorded in OCI 57 16
Ineffective portion of changes in fair value
recorded in earnings 11 --
Mark-to-market losses/(gains) realized
during the year 3 (38)
Change in valuation techniques -- 3
----- -----
Mark-to-market of net positions
at December 31, 2002 $ (49) $ 57
===== =====
Marketing
and
System Trading
------ -------
Mark-to-market of net positions
at December 31, 2000 $ -- $ 12
Cumulative effect adjustment due to
adoption of SFAS No. 133 95 --
Change in mark-to-market (losses)/gains
for future period deliveries (12) 203
Changes in cash flow hedges
recorded in OCI (166) --
Ineffective portion of changes in fair
value recorded in earnings (6) --
Mark-to-market gains realized
during the year (18) (77)
Change in valuation techniques -- --
----- -----
Mark-to-market of net positions
at December 31, 2001 $(107) $ 138
===== =====
The Company no longer reports non-derivative energy contracts or physical
inventories at fair value. Since July 1, 2002, the Company has not recognized a
dealer profit or unrealized gain or loss at the inception of a derivative unless
the fair value of that instrument (in its entirety) is evidenced by quoted
market prices or current market transactions. Prior to the change in our policy,
we recorded net gains at inception of $10 million in 2002 and $3 million in
2001. These amounts included a reasonable marketing margin.
The tables below show the maturities of our system and marketing and
trading derivative positions at December 31, 2002 by the type of valuation that
is performed to calculate the fair value of the contract (dollars in millions).
See "Critical Accounting Policies - Mark-to-Market Accounting" above for more
discussion on our valuation methods.
68
SYSTEM
Years Total
Source of Fair Value 2003 2004 2005 2006 2007 thereafter fair value
- -------------------- ---- ---- ---- ---- ---- ---------- ----------
Prices actively quoted $(23) $(10) $ -- $ -- $ -- $ -- $(33)
Prices provided by
other external sources (1) (12) -- -- -- -- (13)
Prices based on models
and other valuation
methods (1) (2) -- -- -- -- (3)
---- ---- ---- ---- ---- ---- ----
Total by maturity $(25) $(24) $ -- $ -- $ -- $ -- $(49)
==== ==== ==== ==== ==== ==== ====
MARKETING AND TRADING
Years Total
Source of Fair Value 2003 2004 2005 2006 2007 thereafter fair value
- -------------------- ---- ---- ---- ---- ---- ---------- ----------
Prices actively quoted $ (1) $ 5 $ 6 $ 3 $ 3 $ 7 $ 23
Prices provided by
other external sources 2 8 9 12 -- -- 31
Prices based on models
and other valuation
methods 6 3 (3) (4) 5 (4) 3
---- ---- ---- ---- ---- ---- ----
Total by maturity $ 7 $ 16 $ 12 $ 11 $ 8 $ 3 $ 57
==== ==== ==== ==== ==== ==== ====
The table below shows the impact hypothetical price movements of 10% would
have on the market value of our risk management and trading assets and
liabilities included on the Consolidated Balance Sheets at December 31, 2002 and
2001 (dollars in millions).
69
December 31, 2002 December 31, 2001
Gain (Loss) Gain (Loss)
----------------------------- ----------------------------
Commodity Price Up 10% Price Down 10% Price Up 10% Price Down 10%
--------- ------------ -------------- ------------ --------------
Mark-to-market changes
reported in earnings (a):
Electricity $ (2) $ 3 $ (3) $ 3
Natural gas (4) 4 (1) 1
Other 1 -- -- 2
Mark-to-market changes
reported in OCI (b):
Electricity 32 (32) -- --
Natural gas 18 (16) 23 (23)
---- ---- ---- ----
Total $ 45 $(41) $ 19 $(17)
==== ==== ==== ====
(a) These contracts are structured sales activities hedged with a
portfolio of forward purchases that protects the economic value of the
sales transactions.
(b) These contracts are hedges of our forecasted purchases of natural gas
and electricity. The impact of these hypothetical price movements
would substantially offset the impact that these same price movements
would have on the physical exposures being hedged.
CREDIT RISK
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including two counterparties for which a worst case exposure
represents approximately 33% of our $181 million of risk management and trading
assets as of December 31, 2002. Our risk management process assesses and
monitors the financial exposure of these and all other counterparties. Despite
the fact that the great majority of trading counterparties are rated as
investment grade by the credit rating agencies, including the counterparties
noted above, there is still a possibility that one or more of these companies
could default, resulting in a material impact on consolidated earnings for a
given period. Counterparties in the portfolio consist principally of major
energy companies, municipalities and local distribution companies. We maintain
credit policies that we believe minimize overall credit risk to within
acceptable limits. Determination of the credit quality of our counterparties is
based upon a number of factors, including credit ratings and our evaluation of
their financial condition. In many contracts, we employ collateral requirements
and standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Valuation adjustments are
established representing our estimated credit losses on our overall exposure to
counterparties. See "Critical Accounting Policies - Mark-to-Market Accounting"
above for a discussion of our credit valuation adjustment policy.
70
RISK FACTORS
Exhibit 99.3, which is hereby incorporated by reference, contains a
discussion of risk factors affecting the Company.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements or make any
further statements on any of these issues, except as required by applicable
laws. Because actual results may differ materially from expectations, we caution
readers not to place undue reliance on these statements. A number of factors
could cause future results to differ materially from historical results or from
results or outcomes currently expected or sought by us. These factors include
the ongoing restructuring of the electric industry, including the introduction
of retail electric competition in Arizona and decisions impacting wholesale
competition; the outcome of regulatory and legislative proceedings relating to
the restructuring; state and federal regulatory and legislative decisions and
actions, including price caps and other market constraints imposed by the FERC;
regional economic and market conditions, including the California energy
situation and completion of generation and transmission construction in the
region, which could affect customer growth and the cost of power supplies; the
cost of debt and equity capital and access to capital markets; weather
variations affecting local and regional customer energy usage; the effect of
conservation programs on energy usage; power plant performance; the successful
completion of our generation construction program; regulatory issues associated
with generation construction, such as permitting and licensing; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); our ability to manage our marketing and trading activities
and the use of derivative contracts in our business; technological developments
in the electric industry; the performance of the stock market, which affects the
amount of our required contributions to our pension plan and nuclear
decommissioning trust funds; the strength of the real estate market in SunCor's
market areas, which include Arizona, New Mexico and Utah; and other
uncertainties, all of which are difficult to predict and many of which are
beyond our control.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See "Factors Affecting Our Financial Outlook - Market Risks" in Item 7 for
a discussion of quantitative and qualitative disclosures about market risk.
71
[THIS PAGE INTENTIONALLY LEFT BLANK.]
72
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
Independent Auditors' Report................................................. 74
Consolidated Statements of Income for 2002, 2001 and 2000.................... 75
Consolidated Balance Sheets as of December 31, 2002 and 2001................. 76
Consolidated Statements of Cash Flows for 2002, 2001 and 2000................ 78
Consolidated Statements of Changes in Common Stock Equity
for 2002, 2001 and 2000.................................................... 79
Notes to Consolidated Financial Statements................................... 80
Financial Statement Schedule for 2002, 2001 and 2000
Schedule II - Valuation and Qualifying Accounts for 2002, 2001
and 2000...................................................................138
See Note 13 for the selected quarterly financial data required to be presented
in this Item.
73
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle
West Capital Corporation and subsidiaries ("the Corporation") as of December 31,
2002 and 2001 and the related consolidated statements of income, changes in
common stock equity, and cash flows for each of the three years in the period
ended December 31, 2002. Our audits also included the financial statement
schedule listed in the Index. These financial statements and financial statement
schedule are the responsibility of the Corporation's management. Our
responsibility is to express an opinion on the financial statements and the
financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Pinnacle West Capital
Corporation and subsidiaries at December 31, 2002 and 2001 and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2002 in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.
As discussed in Note 18 to the consolidated financial statements, in 2002
Pinnacle West Capital Corporation changed its method of accounting for trading
activities in order to comply with the provisions of Emerging Issues Task Force
Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities."
As discussed in Note 18 to the consolidated financial statements, in 2001
Pinnacle West Capital Corporation changed its method of accounting for
derivatives and hedging activities in order to comply with the provisions of
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities."
DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 3, 2003 (March 4, 14, 26 and 27, 2003 as to Note 24)
74
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)
Year Ended December 31,
---------------------------------------------
2002 2001 2000
----------- ----------- -----------
OPERATING REVENUES
Regulated electricity segment $ 2,013,023 $ 2,562,089 $ 2,538,752
Marketing and trading segment 325,931 651,230 418,532
Real estate segment 236,388 168,908 158,365
Other revenues 61,937 11,771 3,873
----------- ----------- -----------
Total 2,637,279 3,393,998 3,119,522
----------- ----------- -----------
OPERATING EXPENSES
Regulated electricity segment purchased
power and fuel 499,543 1,160,863 1,065,597
Marketing and trading segment purchased
power and fuel 194,039 334,209 292,669
Operations and maintenance 584,538 530,095 450,205
Real estate operations segment 205,315 153,462 134,422
Depreciation and amortization 424,886 427,903 431,229
Taxes other than income taxes 107,952 101,068 99,780
Other expenses 104,959 10,375 782
----------- ----------- -----------
Total 2,121,232 2,717,975 2,474,684
----------- ----------- -----------
OPERATING INCOME 516,047 676,023 644,838
----------- ----------- -----------
OTHER
Other income 15,104 26,416 21,832
Other expenses (33,655) (33,577) (25,329)
----------- ----------- -----------
Total (18,551) (7,161) (3,497)
----------- ----------- -----------
INTEREST EXPENSE
Interest charges 188,353 175,822 166,447
Capitalized interest (44,110) (47,862) (21,638)
----------- ----------- -----------
Total 144,243 127,960 144,809
----------- ----------- -----------
INCOME BEFORE INCOME TAXES 353,253 540,902 496,532
INCOME TAXES 138,100 213,535 194,200
----------- ----------- -----------
INCOME BEFORE ACCOUNTING CHANGE 215,153 327,367 302,332
Cumulative effect of a change in
accounting for derivatives -
net of income taxes of $9,892 -- (15,201) --
Cumulative effect of a change in
accounting for trading activities -
net of income taxes of $43,123 (65,745) -- --
----------- ----------- -----------
NET INCOME $ 149,408 $ 312,166 $ 302,332
=========== =========== ===========
WEIGHTED-AVERAGE COMMON
SHARES OUTSTANDING - BASIC 84,903 84,718 84,733
WEIGHTED-AVERAGE COMMON
SHARES OUTSTANDING - DILUTED 84,964 84,930 84,935
EARNINGS PER WEIGHTED - AVERAGE
COMMON SHARE OUTSTANDING
Income before accounting change - basic $ 2.53 $ 3.86 $ 3.57
Net income - basic 1.76 3.68 3.57
Income before accounting change - diluted 2.53 3.85 3.56
Net income - diluted 1.76 3.68 3.56
DIVIDENDS DECLARED PER SHARE $ 1.625 $ 1.525 $ 1.425
See Notes to Consolidated Financial Statements.
75
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
-------------------------
2002 2001
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 77,707 $ 28,619
Customer and other receivables - net 374,995 367,241
Accrued utility revenues 72,915 76,131
Materials and supplies (at average cost) 91,652 81,215
Fossil fuel (at average cost) 28,185 27,023
Deferred income taxes (Note 4) 4,094 --
Assets from risk management and trading activities
(Note 18) 59,162 66,973
Other current assets 103,978 80,203
---------- ----------
Total current assets 812,688 727,405
---------- ----------
INVESTMENTS AND OTHER ASSETS
Real estate investments - net (Notes 1 and 6) 425,331 418,673
Assets from risk management and trading activities -
long term (Note 18) 122,336 200,351
Other assets 229,891 304,453
---------- ----------
Total investments and other assets 777,558 923,477
---------- ----------
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
Plant in service and held for future use 9,058,900 8,030,847
Less accumulated depreciation and amortization 3,474,325 3,290,097
---------- ----------
Total 5,584,575 4,740,750
Construction work in progress 777,542 1,047,072
Intangible assets, net of accumulated amortization (Note 21) 109,815 86,782
Nuclear fuel, net of accumulated amortization of
$102,821 and $99,185 7,466 6,933
---------- ----------
Net property, plant and equipment 6,479,398 5,881,537
---------- ----------
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4) 241,045 342,383
Other deferred debits 115,117 64,597
---------- ----------
Total deferred debits 356,162 406,980
---------- ----------
TOTAL ASSETS $8,425,806 $7,939,399
========== ==========
See Notes to Consolidated Financial Statements.
76
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
----------------------------
2002 2001
----------- -----------
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable $ 356,305 $ 269,124
Accrued taxes 71,109 96,729
Accrued interest 53,018 48,806
Short-term borrowings (Note 5) 102,183 405,762
Current maturities of long-term debt (Note 6) 281,023 126,140
Customer deposits 55,838 30,232
Deferred income taxes (Note 4) -- 3,244
Liabilities from risk management and trading
activities (Note 18) 70,667 35,994
Other current liabilities 64,972 69,475
----------- -----------
Total current liabilities 1,055,115 1,085,506
----------- -----------
LONG-TERM DEBT LESS CURRENT
MATURITIES (Note 6) 2,881,695 2,673,078
----------- -----------
DEFERRED CREDITS AND OTHER
Liabilities from risk management and trading
activities-long term (Note 18) 75,642 207,576
Deferred income taxes (Note 4) 1,209,074 1,064,993
Unamortized gain - sale of utility plant (Note 9) 59,484 64,060
Pension liability (Note 8) 183,880 49,032
Other 274,763 295,831
----------- -----------
Total deferred credits and other 1,802,843 1,681,492
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES
3, 11 AND 12)
COMMON STOCK EQUITY (Note 7)
Common stock, no par value; authorized
150,000,000 shares; issued 91,379,947 at end
of 2002 and 84,824,947 at end of 2001 1,737,258 1,536,924
Treasury stock; 124,830 shares at end of 2002 and
101,307 shares at end of 2001 (4,358) (5,886)
----------- -----------
Total common stock 1,732,900 1,531,038
----------- -----------
Accumulated other comprehensive loss:
Minimum pension liability adjustment (71,264) (966)
Derivative instruments (20,020) (63,599)
----------- -----------
Total accumulated other comprehensive loss (91,284) (64,565)
----------- -----------
Retained earnings 1,044,537 1,032,850
----------- -----------
Total common stock equity 2,686,153 2,499,323
----------- -----------
TOTAL LIABILITIES AND EQUITY $ 8,425,806 $ 7,939,399
=========== ===========
See Notes to Consolidated Financial Statements.
77
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
Year Ended December 31,
---------------------------------------------
2002 2001 2000
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Income before accounting change $ 215,153 $ 327,367 $ 302,332
Items not requiring cash:
Depreciation and amortization 424,886 427,903 431,229
Nuclear fuel amortization 31,185 28,362 30,083
Deferred income taxes 196,324 (17,203) (37,885)
Change in mark-to-market (18,146) (133,573) (11,752)
Redhawk Units 3 and 4 cancellation 49,192 -- --
Changes in current assets and liabilities:
Customer and other receivables 18,615 146,581 (269,223)
Materials, supplies and fossil fuel (11,599) (16,867) 475
Other current assets (9,784) (1,276) (39,083)
Accounts payable 74,833 (127,782) 193,502
Accrued taxes (36,039) 7,483 18,736
Accrued interest 4,212 5,852 9,701
Other current liabilities 17,489 5,260 98,493
Change in real estate investments (6,112) (44,173) (25,937)
Increase in regulatory assets (11,029) (17,516) (14,138)
Change in risk management and trading - assets (11,700) (51,894) --
Change in risk management and trading - liabilities (22,783) 45,330 13,834
Change in customer advances (23,780) 28,599 2,544
Change in pension liability (1,571) (28,347) (16,575)
Change in long-term assets (16,918) 13,874 54,829
Change in long-term liabilities 8,346 (26,937) (27,771)
----------- ----------- -----------
Net cash flow provided by operating activities 870,774 571,043 713,394
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (895,522) (1,055,574) (658,608)
Capitalized interest (44,110) (47,862) (21,638)
Other 36,635 (16,481) (55,595)
----------- ----------- -----------
Net cash flow used for investing activities (902,997) (1,119,917) (735,841)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 725,419 995,447 651,000
Short-term borrowings and payments - net (303,579) 322,987 44,475
Dividends paid on common stock (137,721) (129,199) (120,733)
Repayment of long-term debt (404,670) (621,057) (558,019)
Common stock equity issuance 199,238 -- --
Other 2,624 (1,048) (4,618)
----------- ----------- -----------
Net cash flow provided by financing activities 81,311 567,130 12,105
----------- ----------- -----------
NET CASH FLOW 49,088 18,256 (10,342)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 28,619 10,363 20,705
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 77,707 $ 28,619 $ 10,363
=========== =========== ===========
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid/(refunded) (Note 4) $ (17,918) $ 223,037 $ 219,411
Interest paid, net of amounts capitalized $ 126,322 $ 115,276 $ 132,434
See Notes to Consolidated Financial Statements.
78
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
For the Years Ended December 31, 2002, 2001 and 2000
(dollars in thousands)
2002 2001 2000
----------- ----------- -----------
COMMON STOCK (Note 7)
Balance at beginning of year $ 1,536,924 $ 1,537,920 $ 1,540,197
Issuance of common stock 199,238 -- --
Other 1,096 (996) (2,277)
----------- ----------- -----------
Balance at end of year 1,737,258 1,536,924 1,537,920
----------- ----------- -----------
TREASURY STOCK (Note 7)
Balance at beginning of year (5,886) (5,089) (2,748)
Purchase of treasury stock (5,971) (16,393) (12,968)
Reissuance of treasury stock used for stock
compensation, net 7,499 15,596 10,627
----------- ----------- -----------
Balance at end of year (4,358) (5,886) (5,089)
----------- ----------- -----------
RETAINED EARNINGS
Balance at beginning of year 1,032,850 849,883 668,284
Net income 149,408 312,166 302,332
Common stock dividends (137,721) (129,199) (120,733)
----------- ----------- -----------
Balance at end of year 1,044,537 1,032,850 849,883
----------- ----------- -----------
ACCUMULATED OTHER
COMPREHENSIVE LOSS
Balance at beginning of year (64,565) -- --
Minimum pension liability adjustment, net of
tax of $46,109 and $634 (70,298) (966) --
Cumulative effect of a change in accounting
for derivatives, net of tax of $47,404 -- 72,274 --
Unrealized gain/(loss) on derivative
instruments, net of tax of $28,820 and
$71,720 43,939 (109,346) --
Reclassification of realized gain to
income, net of tax of $237 and $17,399 (360) (26,527) --
----------- ----------- -----------
Balance at end of year (91,284) (64,565) --
----------- ----------- -----------
TOTAL COMMON STOCK EQUITY $ 2,686,153 $ 2,499,323 $ 2,382,714
=========== =========== ===========
COMPREHENSIVE INCOME
Net income $ 149,408 $ 312,166 $ 302,332
Other comprehensive loss (26,719) (64,565) --
----------- ----------- -----------
Comprehensive income $ 122,689 $ 247,601 $ 302,332
=========== =========== ===========
See Notes to Consolidated Financial Statements.
79
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION AND NATURE OF OPERATIONS
The consolidated financial statements include the accounts of Pinnacle West
and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and
El Dorado (principally NAC). Significant intercompany accounts and transactions
between the consolidated companies have been eliminated.
APS is an electric utility that provides either retail or wholesale
electric service to substantially all of the state of Arizona, with the major
exceptions of the Tucson metropolitan area and about half of the Phoenix
metropolitan area. Electricity is delivered through a distribution system owned
by APS. APS also generates, sells and delivers electricity to wholesale
customers in the western United States. In early 2003, the marketing and trading
division of Pinnacle West was moved to APS for future marketing and trading
activities (existing wholesale contracts will remain at Pinnacle West) as a
result of the ACC's Track A Order prohibiting the previously required transfer
of APS' generating assets to Pinnacle West Energy. See Note 3 for a discussion
of the Track A Order. Pinnacle West Energy, which was formed in 1999, is the
subsidiary through which we conduct our competitive generation operations. APS
Energy Services was formed in 1998 and provides competitive commodity energy and
energy-related products to key customers in competitive markets in the western
United States. SunCor is a developer of residential, commercial and industrial
real estate projects in Arizona, New Mexico and Utah. El Dorado is an investment
firm, and its principal investment is in NAC, which is a company specializing in
spent nuclear fuel technology.
ACCOUNTING RECORDS AND USE OF ESTIMATES
Our accounting records are maintained in accordance with accounting
principles generally accepted in the United States of America (GAAP). The
preparation of financial statements in accordance with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements and reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. We have
reclassified certain prior year amounts to conform to the current year
presentation.
DERIVATIVE ACCOUNTING
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We manage risks associated with these market fluctuations by utilizing various
commodity derivatives, including exchange-traded futures and options and
over-the-counter forwards, options and swaps. As part of our overall risk
management program, we enter into derivative transactions to hedge purchases and
sales of electricity, fuels and emissions allowances and credits. The changes in
market value of such contracts have a high correlation to price changes in the
hedged commodities. In addition, subject to specified risk parameters monitored
by the ERMC, we engage in marketing and trading activities intended to profit
from market price movements.
80
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We examine contracts at inception to determine the appropriate accounting
treatment. If a contract does not meet the derivative criteria or if it
qualifies for a SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," scope exception, we account for the contract on an accrual basis
with associated revenues and costs recorded at the time the contracted
commodities are delivered or received. SFAS No. 133 provides a scope exception
for contracts that meet the normal purchases and sales criteria specified in the
standard. Most of our non-trading electricity purchase and sales agreements
qualify as normal purchases and sales and are exempted from recognition in the
financial statements until the electricity is delivered.
For contracts that qualify as a derivative and do not meet a SFAS No. 133
scope exception, we further examine the contract to determine if it will qualify
for hedge accounting. Changes in the fair value of the effective portion of
derivative instruments that qualify for cash flow hedge accounting treatment are
recognized as either an asset or liability and in common stock equity (as a
component of accumulated other comprehensive income (loss)). Gains and losses
related to derivatives that qualify as cash flow hedges of expected transactions
are recognized in revenue or purchased power and fuel expense as an offset to
the related item being hedged when the underlying hedged physical transaction
impacts earnings. If a contract does not meet the hedging criteria in SFAS No.
133, we recognize the changes in the fair value of the derivative instrument in
income each period through mark-to-market accounting.
On October 1, 2002, we adopted EITF 02-3, "Issues Involved in Accounting
for Derivative Contracts Held for Trading Purposes and Contracts Involved in
Energy Trading and Risk Management Activities," which rescinded EITF 98-10. As a
result, our energy trading contracts that are derivatives continue to be
accounted for at fair value under SFAS No. 133. Contracts that were previously
marked-to-market as trading activities under EITF 98-10 that do not meet the
definition of a derivative are now accounted for on an accrual basis with the
associated revenues and costs recorded at the time the contracted commodities
are delivered or received. Additionally, all gains and losses (realized and
unrealized) on energy trading contracts that qualify as derivatives are included
in marketing and trading segment revenues on the Consolidated Statements of
Income on a net basis. The rescission of EITF 98-10 has no effect on the
accounting for derivative instruments used for non-trading activities, which
continue to be accounted for in accordance with SFAS No. 133. See Note 18 for
more details on the change in accounting for energy trading contracts and for
further discussion on derivative accounting.
MARK-TO-MARKET ACCOUNTING
Under mark-to-market accounting, the purchase or sale of energy commodities
is reflected at fair market value, net of valuation adjustments, with resulting
unrealized gains and losses recorded as assets and liabilities from risk
management and trading activities in the Consolidated Balance Sheets.
We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. We convert quarterly and calendar year quotes into monthly
prices based on historical relationships.
81
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For options, long-term contracts and other contracts for which price quotes
are not available, we use models and other valuation methods. The valuation
models we employ utilize spot prices, forward prices, historical market data and
other factors to forecast future prices. The primary valuation technique we use
to calculate the fair value of contracts where price quotes are not available is
based on the extrapolation of forward pricing curves using observable market
data for more liquid delivery points in the same region and actual transactions
at the more illiquid delivery points. We also value option contracts using a
variation of the Black-Scholes option-pricing model.
For non-exchange traded contracts, we calculate fair market value based on
the average of the bid and offer price, and we discount to reflect net present
value. We maintain certain valuation adjustments for a number of risks
associated with the valuation of future commitments. These include valuation
adjustments for liquidity and credit risks based on the financial condition of
counterparties. The liquidity valuation adjustment represents the cost that
would be incurred if all unmatched positions were closed-out or hedged.
A credit valuation adjustment is also recorded to represent estimated
credit losses on our overall exposure to counterparties, taking into account
netting arrangements, expected default experience for the credit rating of the
counterparties and the overall diversification of the portfolio. Counterparties
in the portfolio consist principally of major energy companies, municipalities
and local distribution companies. We maintain credit policies that management
believes minimize overall credit risk. Determination of the credit quality of
counterparties is based upon a number of factors, including credit ratings,
financial condition, project economics and collateral requirements. When
applicable, we employ standardized agreements that allow for the netting of
positive and negative exposures associated with a single counterparty. See Note
18 for further discussion on credit risk.
The use of models and other valuation methods to determine fair market
value often requires subjective and complex judgment. Actual results could
differ from the results estimated through application of these methods. Our
marketing and trading portfolio includes structured activities hedged with a
portfolio of forward purchases that protects the economic value of the sales
transactions. Our practice is to hedge within timeframes established by the
ERMC.
REGULATORY ACCOUNTING
APS is regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. As a result, we capitalize
certain costs that would be included as expense in the current period by
unregulated companies. Regulatory assets represent incurred costs that have been
deferred because they are probable of future recovery in customer rates.
Regulatory liabilities generally represent obligations to make refunds to
customers for previous collections of costs not likely to be incurred.
We are required to discontinue applying SFAS No. 71 when deregulatory
legislation is passed or a rate order is issued that contains sufficient detail
to determine its effect on the portion of the business being deregulated. In
1999, we discontinued the application of SFAS No. 71 for APS' generation
operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a
discussion of the 1999 Settlement Agreement.
82
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As a result, we tested the generation assets for impairment and determined
the generation assets were not impaired. Pursuant to the 1999 Settlement
Agreement, a regulatory disallowance removed $234 million pretax ($183 million
net present value) from ongoing regulatory cash flows and was recorded as a net
reduction of regulatory assets. This reduction ($140 million after income taxes)
was reported as an extraordinary charge on the 1999 Consolidated Statement of
Income.
In 2002, the ACC directed APS not to transfer its generation assets, as
previously required by the 1999 Settlement Agreement (see "Track A Order" in
Note 3). Accordingly, we now consider APS generation to be cost-based,
rate-regulated and subject to the requirements of SFAS No. 71. The impact of
this change was immaterial to our consolidated financial statements.
Management continually assesses whether our regulatory assets are probable
of future recovery by considering factors such as applicable regulatory
environment changes and recent rate orders to other regulated entities in the
same jurisdiction. This determination reflects the current political and
regulatory climate in the state and is subject to change in the future. If
future recovery of costs ceases to be probable, the assets would be written off
as a charge in current period earnings.
Prior to the 1999 Settlement Agreement, the ACC accelerated the
amortization of substantially all of APS' regulatory assets to an eight-year
period that would have ended June 30, 2004. The regulatory assets to be
recovered under the 1999 Settlement Agreement are currently being amortized as
follows (dollars in millions):
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $ 686
Regulatory assets are reported as deferred debits on the Consolidated
Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the
following (dollars in millions):
December 31,
--------------
2002 2001
---- ----
Remaining balance recoverable under the 1999
Settlement Agreement (a) $104 $219
Spent nuclear fuel storage (Note 11) 46 43
Electric industry restructuring transition costs (Note 3) 40 34
Other 51 46
---- ----
Total regulatory assets $241 $342
==== ====
(a) The majority of our unamortized regulatory assets above relates to deferred
income taxes (see Note 4) and rate synchronization cost deferrals (see
"Rate Synchronization Cost Deferrals" below).
83
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory liabilities are included in deferred credits and other on the
Consolidated Balance Sheets. As of December 31, 2002 and 2001, they are
comprised of the following (dollars in millions):
December 31,
--------------
2002 2001
---- ----
Deferred gains on utility property $ 20 $ 20
Other 6 7
---- ----
Total regulatory liabilities $ 26 $ 27
==== ====
RATE SYNCHRONIZATION COST DEFERRALS
As authorized by the ACC, operating costs (excluding fuel) and financing
costs of Palo Verde Units 2 and 3 were deferred from the commercial operation
dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the
units were included in a rate order (April 1988 for Unit 2 and December 1991 for
Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate the amortization of the deferrals over an eight-year period that will
end June 30, 2004. Amortization of the deferrals is included in depreciation and
amortization expense in the Consolidated Statements of Income.
UTILITY PLANT AND DEPRECIATION
Utility plant is the term we use to describe the business property and
equipment that supports electric service, consisting primarily of generation,
transmission and distribution facilities. We report utility plant at its
original cost, which includes:
* material and labor;
* contractor costs;
* construction overhead costs (where applicable); and
* capitalized interest or an allowance for funds used during
construction.
We expense the costs of plant outages, major maintenance and routine
maintenance as incurred. We charge retired utility plant, plus removal costs
less salvage realized, to accumulated depreciation. See Note 2 for information
on a new accounting standard that impacts accounting for removal costs.
We record depreciation on utility property on a straight-line basis over
the remaining useful life of the related assets. The approximate remaining
average useful lives of our utility property at December 31, 2002 were as
follows:
* Fossil plant - 22 years;
* Nuclear plant - 22 years;
* Transmission - 34 years;
* Distribution - 28 years; and
* Other utility property - 9 years.
84
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years 2000 through 2002 the depreciation rates, as prescribed by
our regulators, ranged from a low of 1.51% to a high of 20%. The
weighted-average rate was 3.35% for 2002 and 3.40% for 2001 and 2000. We
depreciate non-utility property and equipment over the estimated useful lives of
the related assets, ranging from 3 to 30 years.
EL DORADO INVESTMENTS
El Dorado accounts for its investments using the consolidated (if
controlled), equity (if significant influence) and cost (less than 20%
ownership) methods. Beginning in the third quarter of 2002, El Dorado began
consolidating the operations of NAC. See Note 22 for further details on El
Dorado's investment in NAC.
CAPITALIZED INTEREST
Capitalized interest represents the cost of debt funds used to finance
construction projects. Plant construction costs, including capitalized interest,
are expensed through depreciation when completed projects are placed into
commercial operation. Capitalized interest does not represent current cash
earnings. The rate used to calculate capitalized interest was a composite rate
of 4.80% for 2002, 6.13% for 2001 and 6.62% for 2000.
ELECTRIC REVENUES
Revenues related to the sale of energy are generally recorded when service
is rendered or energy is delivered to customers. However, the determination of
energy sales to individual Native Load customers is based on the reading of
their meters, which occurs on a systematic basis throughout the month. At the
end of each month, amounts of energy delivered to customers since the date of
the last meter reading and the corresponding unbilled revenue are estimated. We
exclude sales taxes on electric revenues from both revenue and taxes other than
income taxes. Other than revenues and purchased power costs related to energy
trading activities, revenues are reported on a gross basis in our Consolidated
Statements of Income.
All gains and losses (realized and unrealized) on energy trading contracts
that qualify as derivatives are included in marketing and trading segment
revenues on the Consolidated Statements of Income on a net basis.
SUNCOR
SunCor recognizes revenue from land, home and qualifying commercial
operating assets sales in full, provided (a) the income is determinable, that
is, the collectibility of the sales price is reasonably assured or the amount
that will not be collectible can be estimated, and (b) the earnings process is
virtually complete, that is, SunCor is not obligated to perform significant
activities after the sale to earn the income. Unless both conditions exist,
recognition of all or part of the income is postponed. A single method of
recognizing income is applied to all sales transactions within an entire home,
land or commercial development project. Commercial property and management
revenues are recorded over the term of the lease or period in which services are
provided.
85
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERCENTAGE OF COMPLETION - NAC
Certain NAC contract revenues are accounted for under the
percentage-of-completion method. Revenues are recognized based upon total costs
incurred to date compared to total costs expected to be incurred for each
contract. Revisions in contract revenue and cost estimates are reflected in the
accounting period when known. Provisions are made for the full amounts of
anticipated losses in the periods in which they are first determined. Changes in
job performance, job conditions and estimated profitability, including those
arising from contract penalty provisions and final contract settlements, may
result in revisions to costs and income, and are recognized in the period in
which revisions are determined. Profit incentives are included in revenues when
their realization is reasonably assured.
Contract costs include all direct material and labor costs and those
indirect costs related to contract performance, such as indirect labor,
supplies, tools, repairs and depreciation costs. General and administrative
costs are charged to expense as incurred.
CASH AND CASH EQUIVALENTS
For purposes of the Consolidated Statements of Cash Flows, we consider all
highly liquid debt instruments purchased with an initial maturity of three
months or less to be cash equivalents.
NUCLEAR FUEL
APS charges nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method based on actual
physical usage. APS divides the cost of the fuel by the estimated number of
thermal units it expects to produce with that fuel. APS then multiplies that
rate by the number of thermal units produced within the current period. This
calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear
fuel, and it charges APS $0.001 per kWh of nuclear generation. See Note 11 for
information about spent nuclear fuel disposal and Note 12 for information on
nuclear decommissioning costs.
INCOME TAXES
Income taxes are provided using the asset and liability approach prescribed
by SFAS No. 109, "Accounting for Income Taxes." We file our federal income tax
return on a consolidated basis and we file our state income tax returns on a
consolidated or unitary basis. In accordance with our intercompany tax sharing
agreement, federal and state income taxes are allocated to each subsidiary as
though each first-tier subsidiary filed a separate income tax return. Any
difference between the aforementioned allocations and the consolidated (and
unitary) income tax liability is attributed to the parent company.
86
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
REACQUIRED DEBT COSTS
For debt related to the regulated portion of APS' business, APS amortizes
those gains and losses incurred upon early retirement over the original
remaining life of the debt. In accordance with the 1999 Settlement Agreement,
APS is continuing to accelerate reacquired debt costs over an eight-year period
that will end June 30, 2004. All regulatory asset amortization is included in
depreciation and amortization expense in the Consolidated Statements of Income.
REAL ESTATE INVESTMENTS
Real estate investments primarily include SunCor's land, home inventory and
investments in joint ventures. Land includes acquisition costs, infrastructure
costs, property taxes and capitalized interest directly associated with the
acquisition and development of each project. Land under development and land
held for future development are stated at accumulated cost, except to the extent
that such land is believed to be impaired, it is written down to fair value.
Land held for sale is stated at the lower of accumulated cost or estimated fair
value less costs to sell. Home inventory consists of construction costs,
improved lot costs, capitalized interest and property taxes on homes under
construction. Home inventory is stated at the lower of accumulated cost or
estimated fair value less costs to sell. Investments in joint ventures for which
SunCor does not have a controlling financial interest are not consolidated but
are accounted for using the equity method of accounting.
STOCK-BASED COMPENSATION
In 2002, we began applying the fair value method of accounting for
stock-based compensation, as provided for in SFAS No. 123, "Accounting for
Stock-Based Compensation." The fair value method of accounting is the preferred
method. In accordance with the transition requirements of SFAS No. 123, we
applied the fair value method prospectively, beginning with 2002 stock grants.
In prior years, we recognized stock compensation expense based on the intrinsic
value method allowed in Accounting Principles Board Opinion (APB) No. 25,
"Accounting for Stock Issued to Employees."
The following chart compares our net income, stock compensation expense and
earnings per share to what those items would have been if we had recorded stock
compensation expense based on the fair value method for all stock grants through
2002 (dollars in thousands, except per share amounts):
87
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2002 2001 2000
--------- --------- ---------
Net Income:
As reported $ 149,408 $ 312,166 $ 302,332
Pro forma (fair value method) 148,013 309,874 301,102
Stock compensation expense (net of tax):
As reported 300 -- --
Pro forma (fair value method) 1,395 2,292 1,230
Earnings per share - basic:
As reported $ 1.76 $ 3.68 $ 3.57
Pro forma (fair value method) $ 1.74 $ 3.66 $ 3.55
Earnings per share - diluted:
As reported $ 1.76 $ 3.68 $ 3.56
Pro forma (fair value method) $ 1.74 $ 3.65 $ 3.55
In order to calculate the fair value of the 2002 stock option grants and
the pro forma information above, we calculated the fair value of each fixed
stock option in the incentive plans using the Black-Scholes option-pricing
model. The fair value was calculated based on the date the option was granted.
The following weighted-average assumptions were also used in order to calculate
the fair value of the stock options:
2002 2001 2000
------ ------ ------
Risk-free interest rate 4.17% 4.08% 5.81%
Dividend yield 4.17% 3.70% 3.48%
Volatility 22.59% 27.66% 32.00%
Expected life (months) 60 60 60
See Note 16 for further discussion about our stock compensation plans.
2. ACCOUNTING MATTERS
On January 1, 2003 we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." The standard requires the fair value of asset
retirement obligations to be recorded as a liability, along with an offsetting
plant asset, when the obligation is incurred. Accretion of the liability due to
the passage of time will be an operating expense and the capitalized cost is
depreciated over the useful life of the long-lived asset. (See Note 1 for more
information regarding our previous accounting for removal costs.)
We determined that we have asset retirement obligations for our nuclear
facilities (nuclear decommissioning) and certain other fossil generation,
transmission and distribution assets. On January 1, 2003 we recorded a liability
of $219 million for our asset retirement obligations including the accretion
impacts; a $67 million increase in the carrying amount of the associated assets;
and a net reduction of $192 million in accumulated depreciation related
primarily to the reversal of previously recorded accumulated decommissioning and
other removal costs related to these obligations. Additionally, we recorded a
net regulatory liability of $40 million for our asset retirement obligations
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
related to our regulated utility. This regulatory liability represents the
difference between the amount currently being recovered in regulated rates and
the amount calculated under SFAS No. 143. We believe we can recover in regulated
rates the transition costs and ongoing current period costs calculated in
accordance with SFAS No. 143.
In November 2002, the EITF reached a consensus on EITF 00-21, "Revenue
Arrangements with Multiple Deliverables." EITF 00-21 addresses certain aspects
of the accounting by a vendor for arrangements under which it will perform
multiple revenue-generating activities. EITF 00-21 specifically addresses how to
determine whether an arrangement has identifiable, separable revenue-generating
activities. EITF 00-21 does not address when the criteria for revenue
recognition are met or provide guidance on the appropriate revenue recognition
convention. EITF 00-21 is effective for revenue arrangements entered into after
July 1, 2003. We are currently evaluating the impacts of this new guidance, but
we do not believe it will have a material impact on our financial statements.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions for the disposal of
a segment of a business. This standard did not impact our financial statements
at adoption. For each of the years 2002, 2001 and 2000, items requiring
discontinued operations reporting were immaterial.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
Nos. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections," which, among other things, supersedes previous guidance for
reporting gains and losses from extinguishment of debt. This standard did not
impact our financial statements at adoption.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." The standard requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The guidance will be applied to exit or disposal activities initiated after
December 31, 2002. This standard did not impact our financial statements at
adoption.
In 2001, the American Institute of Certified Public Accountants (AICPA)
issued an exposure draft of a proposed Statement of Position (SOP), "Accounting
for Certain Costs Related to Property, Plant, and Equipment." This proposed SOP
would create a project timeline framework for capitalizing costs related to
property, plant and equipment construction. It would require that property,
plant and equipment assets be accounted for at the component level and require
administrative and general costs incurred in support of capital projects to be
expensed in the current period. In November 2002, the AICPA announced they would
no longer issue general purpose SOPs. The work they have performed on the
proposed SOP will be transitioned to the FASB staff. In February 2003, the FASB
determined that the AICPA should continue their deliberations on certain aspects
of the proposed SOP. We are waiting for further guidance from the FASB staff and
the AICPA on the timing of the final guidance.
See the following Notes for other new accounting standards:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* Notes 1 and 16 for a new accounting standard (SFAS No. 148) related to
stock-based compensation;
* Note 18 for a new EITF issue (EITF 02-3) related to accounting for
energy trading contracts;
* Note 20 for a new interpretation (FIN No. 46) related to VIEs;
* Note 21 for a new standard (SFAS No. 142) related to goodwill and
intangible assets; and
* Note 23 for a new interpretation (FIN No. 45) on guarantees.
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW On September 21, 1999, the ACC approved Rules that provide a
framework for the introduction of retail electric competition in Arizona. On
September 23, 1999, the ACC approved a comprehensive settlement agreement among
APS and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, APS was required to transfer all of its competitive electric assets
and services to an unaffiliated party or parties or to a separate corporate
affiliate or affiliates no later than December 31, 2002. Consistent with that
requirement, APS had been addressing the legal and regulatory requirements
necessary to complete the transfer of its generation assets to Pinnacle West
Energy on or before that date. On September 10, 2002, the ACC issued the Track A
Order, which, among other things, directed APS not to transfer its generation
assets to Pinnacle West Energy. See "Track A Order" below.
On September 16, 2002, APS filed an application with the ACC requesting the
ACC to allow APS to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to the Company; to guarantee up to $500 million of
Pinnacle West Energy's or the Company's debt; or a combination of both, not to
exceed $500 million in the aggregate. In its application, APS stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between APS and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing provided
by the Company to fund the construction of Pinnacle West Energy generation
assets or from effectively competing in the wholesale markets. On March 27,
2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy,
guarantee up to $500 million of Pinnacle West Energy debt, or a combination of
both, not to exceed $500 million in the aggregate. See "ACC Applications" below.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that APS competitively procure certain power
requirements. On March 14, 2003, the ACC issued the Track B Order which
documented the decision made by the ACC at its open meeting on February 27,
2003, addressing this requirement. Under the order, APS will be required to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, APS will be required to solicit competitive
bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of
energy, or approximately 20% of APS' total retail energy requirements. The bid
amounts are expected to increase in 2004 and 2005 based largely on growth in
APS' retail load and APS' retail energy sales. The Track B Order also confirmed
that it was "not intended to change the current rate base status of [APS']
existing assets." The order recognizes APS' right to reject any bids that are
unreasonable, uneconomical or unreliable.
APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements. See "Track B Order" below.
These regulatory developments and legal challenges to the Rules have raised
considerable uncertainty about the status and pace of retail electric
competition in Arizona. These matters are discussed in more detail below.
1999 SETTLEMENT AGREEMENT
The following are the major provisions of the 1999 Settlement Agreement, as
approved by the ACC:
* APS has reduced, and will reduce, rates for standard-offer service for
customers with loads less than three MW in a series of annual retail
electricity price reductions of 1.5% on July 1 for each of the years
1999 to 2003 for a total of 7.5%. Based on the price reductions
authorized in the 1999 Settlement Agreement, there were retail price
decreases of approximately $24 million ($14 million after taxes),
effective July 1, 1999; approximately $28 million ($17 million after
taxes), effective July 1, 2000; approximately $27 million ($16 million
after taxes), effective July 1, 2001; and approximately $28 million
($17 million after taxes), effective July 1, 2002. The final price
reduction is to be implemented July 1, 2003. For customers having
loads of three MW or greater, standard-offer rates have been reduced
in varying annual increments that total 5% in the years 1999 through
2002.
* Unbundled rates being charged by APS for competitive direct access
service (for example, distribution services) became effective upon
approval of the 1999 Settlement Agreement, retroactive to July 1,
1999, and also became subject to annual reductions beginning January
1, 2000, that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard-offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
limited circumstances. Neither the ACC nor APS will be prevented from
seeking or authorizing rate changes prior to July 1, 2004 in the event
of conditions or circumstances that constitute an emergency, such as
an inability to finance on reasonable terms; material changes in APS'
cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or judicial
decisions, actions or orders.
* APS will be permitted to defer for later recovery prudent and
reasonable costs of complying with the Rules, system benefits costs in
excess of the levels included in then-current (1999) rates, and costs
associated with the "provider of last resort" and standard-offer
obligations for service after July 1, 2004. These costs are to be
recovered through an adjustment clause or clauses commencing on July
1, 2004.
* APS' distribution system opened for retail access effective September
24, 1999. Customers were eligible for retail access in accordance with
the phase-in adopted by the ACC under the Rules (see "Retail Electric
Competition Rules" below), including an additional 140 MW being made
available to eligible non-residential customers. APS opened its
distribution system to retail access for all customers on January 1,
2001. The regulatory developments and legal challenges to the Rules
discussed in this note have raised considerable uncertainty about the
status and pace of electric competition in Arizona. Although some very
limited retail competition existed in APS' service area in 1999 and
2000, there are currently no active retail competitors providing
unbundled energy or other utility services to APS' customers. As a
result, we cannot predict when, and the extent to which, additional
competitors will re-enter APS' service territory.
* Prior to the 1999 Settlement Agreement, APS was recovering
substantially all of its regulatory assets through July 1, 2004,
pursuant to a 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that APS has demonstrated that its
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value (in 1999 dollars).
APS will not be allowed to recover $183 million net present value (in
1999 dollars) of the above amounts. The 1999 Settlement Agreement
provides that APS will have the opportunity to recover $350 million
net present value (in 1999 dollars) through a competitive transition
charge that will remain in effect through December 31, 2004, at which
time it will terminate. The costs subject to recovery under the
adjustment clause described above will be decreased or increased by
any over/under-recovery due to sales volume variances.
* APS will form, or cause to be formed, a separate corporate affiliate
or affiliates and transfer to such affiliate(s) its competitive
electric assets and services at book value as of the date of transfer,
and will complete the transfers no later than December 31, 2002. APS
will be allowed to defer and later collect, beginning July 1, 2004,
67% of its costs to accomplish the required transfer of generation
assets to an affiliate. However, as noted above and discussed in
greater detail below, in 2002 the ACC unilaterally modified this
aspect of the 1999 Settlement Agreement by issuing an order preventing
APS from transferring its generation assets.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RETAIL ELECTRIC COMPETITION RULES
The Rules approved by the ACC included the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by
the ACC, including APS.
* Effective January 1, 2001, retail access became available to all APS
retail electricity customers.
* Electric service providers that get CC&N's from the ACC can supply
only competitive services, including electric generation, but not
electric transmission and distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
noncompetitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
electric assets and services to an unaffiliated party or parties or to
a separate corporate affiliate or affiliates. Under the 1999
Settlement Agreement, APS received a waiver to allow transfer of its
competitive electric assets and services to affiliates no later than
December 31, 2002. However, as noted above and discussed in greater
detail below, in 2002 the ACC reversed its decision, as reflected in
the Rules, to require APS to transfer its generation assets.
Under the 1999 Settlement Agreement, the Rules are to be interpreted and
applied, to the greatest extent possible, in a manner consistent with the 1999
Settlement Agreement. If the two cannot be reconciled, APS must seek, and the
other parties to the 1999 Settlement Agreement must support, a waiver of the
Rules in favor of the 1999 Settlement Agreement.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, to operate in Arizona. We do not believe the
ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was
not at issue in the consolidated cases before the judge. Further, the ACC made
findings related to the fair value of APS' property in the order approving the
1999 Settlement Agreement. The ACC and other parties aligned with the ACC have
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
appealed the ruling to the Arizona Court of Appeals, as a result of which the
Superior Court's ruling is automatically stayed pending further judicial review.
That appeal is still pending. In a similar appeal concerning the issuance of
competitive telecommunications CC&N's, the Arizona Court of Appeals invalidated
rates for competitive carriers due to the ACC's failure to establish a fair
value rate base for such carriers. That decision was upheld by the Arizona
Supreme Court.
PROVIDER OF LAST RESORT OBLIGATION
Although the Rules allow retail customers to have access to competitive
providers of energy and energy services, APS is the "provider of last resort"
for standard-offer, full-service customers under rates that have been approved
by the ACC. These rates are established until at least July 1, 2004. The 1999
Settlement Agreement allows APS to seek adjustment of these rates in the event
of emergency conditions or circumstances, such as the inability to secure
financing on reasonable terms; material changes in APS' cost of service for
ACC-regulated services resulting from federal, tribal, state or local laws;
regulatory requirements; or judicial decisions, actions or orders. Energy prices
in the western wholesale market vary and, during the course of the last two
years, have been volatile. At various times, prices in the spot wholesale market
have significantly exceeded the amount included in APS' current retail rates. In
the event of shortfalls due to unforeseen increases in load demand or generation
or transmission outages, APS may need to purchase additional supplemental power
in the wholesale spot market. Unless APS is able to obtain an adjustment of its
rates under the emergency provisions of the 1999 Settlement Agreement, there can
be no assurance that APS would be able to fully recover the costs of this power.
GENERIC DOCKET
In January 2002, the ACC opened a "generic" docket to "determine if changed
circumstances require the [ACC] to take another look at electric restructuring
in Arizona." In February 2002, the ACC docket relating to APS' October 2001
filing was consolidated with several other pending ACC dockets, including the
generic docket. On May 2, 2002, the ACC issued a procedural order stating that
hearings would begin on June 17, 2002 on various issues, including APS' planned
divestiture of generation assets to Pinnacle West Energy and associated market
and affiliate issues. The procedural order also stated that consideration of the
competitive bidding process required by the Rules would proceed concurrently
with the Track A issues.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order, which documents
decisions made by the ACC at an open meeting on August 27, 2002. The major
provisions of the Track A Order include, among other things:
Provisions related to the reversal of the generation asset transfer
requirement:
* The ACC reversed its decision, as reflected in the Rules, to require
APS to transfer its generation assets either to an unrelated third
party or to a separate corporate affiliate; and
* the ACC unilaterally modified the 1999 Settlement Agreement, which
authorized APS' transfer of its generating assets, and directed APS to
cancel its activities to transfer its generation assets to Pinnacle
West Energy.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Provisions related to the wholesale competitive energy procurement process
(Track B issues):
* The ACC stayed indefinitely the requirement of the Rules that APS
acquire 100% of its energy needs for its standard offer customers from
the competitive market, with at least 50% obtained through a
competitive bid process;
* the ACC established a requirement that APS competitively procure, at a
minimum, any required power that it cannot produce from its existing
assets in accordance with the ultimate outcome of the Track B
proceedings;
* the ACC directed the parties to develop a competitive procurement
("bidding") process that can begin by March 1, 2003; and
* the ACC stated that "the [Pinnacle West Energy] generating assets that
APS may acquire from [Pinnacle West Energy] shall not be counted as
APS assets in determining the amount, timing and manner of the
competitive solicitation" for Track B purposes, thereby bifurcating
the regulatory treatment of the existing APS assets and the Pinnacle
West Energy assets.
On November 15, 2002, APS filed appeals of the Track A Order in the
Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals.
ARIZONA PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, CV 2002-0222
32. ARIZONA PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, 1CA CC
02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for
resolving certain issues raised by APS in its appeals of the Track A Order. APS
and the ACC are the only parties to the Track A Order appeals. The major
provisions of this document include, among other things, the following:
* The parties agreed that it would be appropriate for the ACC to
consider the following matters in APS' upcoming general rate case,
anticipated to be filed before June 30, 2003:
* the generating assets to be included in APS' rate base, including
the question of whether certain power plants currently owned by
Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
Phoenix Units 4 and 5, and Saguaro Unit 3) should be included in
APS' rate base;
* the appropriate treatment of the $234 million pretax asset
write-off agreed to by APS as part of a 1999 settlement agreement
approved by the ACC among APS and various parties related to the
implementation of retail competition in Arizona; and
* the appropriate treatment of costs incurred by APS in preparation
for the previously anticipated transfer of generation assets to
Pinnacle West Energy.
* Upon the ACC's issuance of a final decision that is no longer subject
to appeal approving the Financing Application, with appropriate
conditions, APS' appeals of the Track A Order would be limited to the
issues described in the preceding bullet points, each of which would
be presented to the ACC for consideration prior to any final judicial
resolution.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On February 21, 2003, a Notice of Claim was filed with the ACC and the
Arizona Attorney General on behalf of APS, Pinnacle West and Pinnacle West
Energy to preserve their and our rights relating to the Track A Order.
TRACK B ORDER
The ACC Staff has conducted workshops on the Track B issues with various
parties to determine and define the appropriate process to be used for
competitive power procurement. On September 10, 2002, the ACC issued an order
that, among other things, established a requirement that APS competitively
procure certain power requirements. On March 14, 2003, the ACC issued the Track
B Order which documented the decision made by the ACC at its open meeting on
February 27, 2003 addressing this requirement. The order adopted most of the
provisions of an ACC ALJ's recommendation that was issued on January 30, 2003.
Under the ACC's Track B Order, APS will be required to solicit bids for certain
estimated capacity and energy requirements for periods beginning July 1, 2003.
For 2003, APS will be required to solicit competitive bids for about 2,500
megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately
20% of APS' total retail energy requirements. The bid amounts are expected to
increase in 2004 and 2005 based largely on growth in APS' retail load and APS'
retail energy sales. The Track B Order also confirmed that it was "not intended
to change the current rate base status of [APS'] existing assets."
The order recognizes APS' right to reject any bids that are unreasonable,
uneconomical or unreliable. The Track B procurement process will involve the ACC
Staff and an independent monitor. The Track B Order also contains requirements
relating to standards of conduct between APS and any affiliate of APS that may
participate in the competitive solicitation, requires that APS treat bidders in
a non-discriminatory manner and requires APS to file a protocol regarding
short-term and emergency procurements. The order permits the provision of
corporate oversight, support and governance as long as such activities do not
favor Pinnacle West Energy in the procurement process or provide Pinnacle West
Energy with confidential APS bidding information that is not available to other
bidders. The order directs APS to evaluate bids on cost, reliability and
reasonableness. The decision requires bidders to allow the ACC to inspect their
plants and requires assurances of appropriate competitive market conduct from
senior officers of such bidders. Following the solicitation, APS will prepare a
report evaluating environmental issues relating to the procurement and a series
of workshops on environmental risk management will be commenced thereafter.
APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ACC APPLICATIONS
On September 16, 2002, APS filed a Financing Application requesting the ACC
to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle
West Energy or the Company; to guarantee up to $500 million of Pinnacle West
Energy's or the Company's debt; or a combination of both, not to exceed $500
million in the aggregate. The loan and/or the guarantee would be used to
refinance debt incurred to fund the construction of Pinnacle West Energy
generation assets.
The Financing Application addressed, among other things, the following
matters:
* APS noted that its April 19, 2002 filing with the ACC had sought
unification of "[Pinnacle West Energy] Assets" (West Phoenix Units 4
and 5, Redhawk Units 1 and 2, and Saguaro Unit 3) and APS generation
assets under a common financial and regulatory regime. APS further
noted that the Track A Order's language regarding the treatment of the
Pinnacle West Energy Assets for Track B purposes appears to postpone a
decision regarding the inclusion of the Pinnacle West Energy Assets in
APS' rate base, thereby effectively precluding the consolidation of
the Pinnacle West Energy Assets at APS under a common financial and
regulatory regime at the present time.
* APS stated that it did not intend or desire to foreclose the
possibility that it would acquire all or part of the Pinnacle West
Energy Assets or that it may propose that the Pinnacle West Energy
Assets be included in APS' rate base or afforded cost-of-service
regulatory treatment to the extent the Pinnacle West Energy Assets are
used by APS customers. APS stated that these issues would be
appropriate topics in APS' 2003 general rate case and noted that the
Track A Order specifically stated that the ACC would not pre-judge the
eventual rate treatment of the Pinnacle West Energy Assets.
* APS stated that the Track A Order's reversal of the generation asset
transfer requirement and the resulting bifurcation of generation
assets between APS and Pinnacle West Energy under different regulatory
regimes result in Pinnacle West Energy being unable to attain
investment-grade credit ratings. This, in turn, precludes Pinnacle
West Energy from accessing capital markets to refinance the bridge
financing provided by the Company to fund the construction of the
Pinnacle West Energy Assets or from effectively competing in the
wholesale markets. APS noted that Pinnacle West Energy had previously
received investment-grade credit ratings contingent upon its receipt
of APS generation assets and that the Company's credit ratings could
be adversely affected if Pinnacle West Energy is unable to finance its
capital requirements. On November 4, 2002, Standard & Poor's lowered
the Company's senior unsecured debt rating from "BBB" to "BBB-."
* APS stated that the amount of the requested loan and/or guarantee is
APS' present estimate of the amount of credit support necessary
through APS to restore Pinnacle West Energy and the Company to their
credit status prior to the ACC's issuance of the Track A Order. APS
further stated that if the requested amount proves to be inadequate,
APS reserves the right to submit a second financing application
seeking additional credit support.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 27, 2003, the ACC approved the Financing Application, subject to
the following principal conditions:
* any debt issued by APS pursuant to the order must be unsecured;
* APS will be permitted to loan up to $500 million to Pinnacle West
Energy (the "APS Loan"), guarantee up to $500 million of Pinnacle West
Energy debt, or a combination of both, not to exceed $500 million in
the aggregate;
* the APS Loan must be callable and secured by certain Pinnacle West
Energy assets;
* the APS Loan must bear interest at a rate equal to 264 basis points
above the interest rate on APS debt that could be issued and sold on
equivalent terms (including, but not limited to, maturity and
security);
* the 264 basis points referred to in the previous bullet point will be
capitalized as a deferred credit and used to offset retail rates in
the future, with the deferred credit balance bearing an interest rate
of six percent per annum;
* the APS Loan must have a maturity date of not more than four years,
unless otherwise ordered by the ACC;
* any demonstrable increase in APS' cost of capital as a result of the
transaction (such as from a decline in bond rating) will be excluded
from future rate cases;
* APS must maintain a common equity ratio of at least forty percent and
may not pay common dividends if such payment would reduce its common
equity ratio below that threshold, unless otherwise waived by the ACC.
The ACC will process any waiver request within sixty days, and for
this sixty-day period this condition will be suspended. However, this
condition, which will continue indefinitely, will not be permanently
waived without an order of the ACC; and
* certain waivers of the ACC's affiliated interest rules previously
granted to APS and its affiliates will be withdrawn and, during the
term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy
may reorganize or restructure, acquire or divest assets, or form, buy
or sell affiliates (each a "Covered Transaction"), or pledge or
otherwise encumber the Pinnacle West
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Energy assets without prior ACC approval, except that the foregoing
restrictions will not apply to the following categories of Covered
Transactions:
* Covered Transactions less than $100 million, measured on a
cumulative basis over the calendar year in which the Covered
Transactions are made;
* Covered Transactions by SunCor of less than $300 million through
2005, consistent with SunCor's anticipated accelerated asset
sales activity during those years;
* Covered Transactions related to the payment of ongoing
construction costs for Pinnacle West Energy's (a) West Phoenix
Unit 5, located in Phoenix, with an expected commercial operation
date in mid-2003, and (b) Silverhawk plant, located near Las
Vegas, with an expected commercial operation date in mid-2004;
and
* Covered Transactions related to the sale of 25% of the Silverhawk
plant to SNWA if SNWA exercises its existing purchase option to
do so.
The ACC also ordered the ACC staff to conduct an inquiry into our and our
affiliates' compliance with the retail electric competition and related rules
and decisions.
In mid-2003, the Company will need to refinance approximately $475 million
of parent company indebtedness. We expect that this indebtedness will be repaid
through funds borrowed by Pinnacle West Energy from APS under the APS Loan.
On November 22, 2002, the ACC approved APS' request to permit APS to (a)
make short-term advances to Pinnacle West in the form of an inter-affiliate line
of credit in the amount of $125 million, or (b) guarantee $125 million of
Pinnacle West's short-term debt, subject to certain conditions. See Note 5.
FEDERAL
In July 2002, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The FERC has adopted a price cap of $250 per MWh for the period
subsequent to October 31, 2002. Sales at prices above the cap must be justified
and are subject to potential refund.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for
Standard Market Design for wholesale electric markets. Voluminous comments and
reply comments were filed on virtually every aspect of the proposed rule, and
the FERC has announced that it will issue an additional white paper on the
proposed Standard Market Design in April 2003. We are reviewing the proposed
rulemaking and cannot currently predict what, if any, impact there may be to the
Company if the FERC adopts the proposed rule or any modifications proposed in
the comments.
GENERAL
The regulatory developments and legal challenges to the Rules discussed in
this Note have raised considerable uncertainty about the status and pace of
retail electric competition in Arizona. Although some very limited retail
competition existed in APS' service area in 1999 and 2000, there are currently
no active retail competitors providing unbundled energy or other utility
services to APS' customers. As a result, we cannot predict when, and the extent
to which, additional competitors will re-enter APS' service territory. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. INCOME TAXES
Certain assets and liabilities are reported differently for income tax
purposes than they are for financial statements. The tax effect of these
differences is recorded as deferred taxes. We calculate deferred taxes using the
current income tax rates.
APS has recorded a regulatory asset related to income taxes on its Balance
Sheets in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. APS amortizes this amount as the differences reverse. In
accordance with ACC settlement agreements, APS is continuing to accelerate
amortization of a regulatory asset related to income taxes over an eight-year
period that will end June 30, 2004 (see Note 1). Accordingly, we are including
this accelerated amortization in depreciation and amortization expense on our
Consolidated Statements of Income.
As a result of a change in IRS guidance, we claimed a tax deduction related
to an APS tax accounting method change on the 2001 federal consolidated income
tax return. The accelerated deduction has resulted in a $200 million reduction
in the current income tax liability and a corresponding increase in the
plant-related deferred tax liability. In 2002, we received an income tax refund
of approximately $115 million related to our 2001 federal consolidated income
tax return.
The components of income tax expense for income before accounting change
are (dollars in thousands):
Year Ended December 31,
-----------------------------------------
2002 2001 2000
--------- --------- ---------
Current:
Federal $ (43,492) $ 184,893 $ 189,779
State (14,732) 45,845 42,306
--------- --------- ---------
Total current (58,224) 230,738 232,085
Deferred 196,324 (17,203) (37,885)
--------- --------- ---------
Total income tax expense $ 138,100 $ 213,535 $ 194,200
========= ========= =========
The following chart compares pretax income at the 35% federal income tax
rate to income tax expense (dollars in thousands):
100
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31,
----------------------------------
2002 2001 2000
--------- --------- ---------
Federal income tax expense at 35%
statutory rate $ 123,639 $ 189,316 $ 173,786
Increases (reductions) in tax expense
resulting from:
State income tax net of federal income
tax benefit 16,478 23,353 19,848
Other (2,017) 866 566
--------- --------- ---------
Income tax expense $ 138,100 $ 213,535 $ 194,200
========= ========= =========
The following table sets forth the net deferred income tax liability
recognized on the Consolidated Balance Sheets at December 31, 2002 and 2001
(dollars in thousands):
December 31,
-------------------------
2002 2001
----------- -----------
Current asset/(liability) $ 4,094 $ (3,244)
Long term liability (1,209,074) (1,064,993)
----------- -----------
Accumulated deferred income taxes - net $(1,204,980) $(1,068,237)
=========== ===========
The components of the net deferred income tax liability were as follows
(dollars in thousands):
December 31,
-------------------------
2002 2001
----------- -----------
DEFERRED TAX ASSETS
Pension liability $ 72,835 $ 19,422
Risk management and trading activities 43,542 73,043
Deferred gain on Palo Verde Unit 2 sale-leaseback 23,562 25,374
Other 99,054 90,580
----------- -----------
Total deferred tax assets 238,993 208,419
----------- -----------
DEFERRED TAX LIABILITIES
Plant-related (1,316,636) (1,069,207)
Regulatory asset for income taxes (80,635) (121,757)
Risk management and trading activities (46,702) (85,692)
----------- -----------
Total deferred tax liabilities (1,443,973) (1,276,656)
----------- -----------
Accumulated deferred income taxes - net $(1,204,980) $(1,068,237)
=========== ===========
5. LINES OF CREDIT AND SHORT-TERM BORROWINGS
APS had committed lines of credit with various banks of $250 million at
December 31, 2002 and 2001, which were available either to support the issuance
of commercial paper or to be used for bank borrowings. These lines of credit
101
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
mature in June 2003. The commitment fees at December 31, 2002 and 2001 for these
lines of credit were 0.09% per annum. APS had no bank borrowings outstanding
under these lines of credit at December 31, 2002 and 2001.
APS had no commercial paper borrowings outstanding at December 31, 2002 and
$171 million at December 31, 2001. The weighted average interest rate on
commercial paper borrowings was 2.47% for the year ended December 31, 2002 and
4.72% for the year ended December 31, 2001. By Arizona statute, APS' short-term
borrowings cannot exceed 7% of its total capitalization unless approved by the
ACC.
Pinnacle West had committed lines of credit of $475 million at December 31,
2002 and $250 million at December 31, 2001, which were available either to
support the issuance of commercial paper or to be used for bank borrowings.
Outstanding amounts at December 31, 2002 were $72 million, and there were no
short-term bank borrowings outstanding at December 31, 2001. The commitment fees
ranged from 0.10% to 0.15% in 2002 and 2001. Pinnacle West commercial paper
borrowings outstanding were $24 million at December 31, 2002 and $235 million at
December 31, 2001. The weighted average interest rate on commercial paper
borrowings was 2.06% for the year ended December 31, 2002 and 3.50% for the year
ended December 31, 2001.
On July 31, 2002, Pinnacle West completed a $300 million bank credit
facility, which was subsequently reduced to $225 million by applying $75 million
of the proceeds from the equity offering in December 2002 (see Note 7). The
borrowings are LIBOR-based, can be drawn upon as needed and are expected to be
used primarily to fund Pinnacle West Energy capital requirements. The facility
matures in July 2003. The majority of these borrowings were used to fund
Pinnacle West Energy capital expenditures. At December 31, 2002, Pinnacle West
had borrowed $67 million under the credit facility.
On November 22, 2002, the ACC approved APS' request to permit APS to (a)
make short-term advances to Pinnacle West in the form of an inter-affiliate line
of credit in the amount of $125 million, or (b) guarantee $125 million of
Pinnacle West's short-term debt, subject to certain conditions. This interim
loan matures in December 2003. There have been no borrowings on this line.
SunCor had revolving lines of credit totaling $140 million at December 31,
2002 and 2001. The commitment fees were 0.125% in 2002 and 2001. SunCor had $126
million outstanding at December 31, 2002 and $128 million outstanding at
December 31, 2001. The balance is included in long-term debt on the Consolidated
Balance Sheets (see Note 6). SunCor had short-term loans in the amount of $6
million at December 31, 2002 and no short-term loans outstanding at December 31,
2001.
102
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. LONG-TERM DEBT
Borrowings under the APS mortgage bond indenture are secured by
substantially all utility plant. APS also has unsecured debt. SunCor's debt is
collateralized by interests in certain real property and Pinnacle West's debt is
unsecured. The following table presents the components of long-term debt on the
Consolidated Balance Sheets outstanding at December 31, 2002 and 2001 (dollars
in thousands):
103
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31,
Maturity Interest ----------------------------
Dates (a) Rates 2002 2001
--------- ----- ----------- -----------
APS
First mortgage bonds 2002 8.125%(b) $ -- $ 125,000
2004 6.625% 80,000 80,000
2023 7.25% 54,150 54,150
2024 8.75%(c) -- 121,668
2025 8.0% 33,075 33,075
2028 5.5% 25,000 25,000
2028 5.875% 154,000 154,000
Unamortized discount and premium (6,337) (5,266)
Pollution control bonds 2024-2034 (d) 386,860 386,860
Pollution control bonds 2029 3.30%(e) -- 90,000
Pollution control bonds with senior
notes (f) 2029 5.05% 90,000 --
Unsecured notes 2004 5.875% 125,000 125,000
Unsecured notes 2005 6.25% 100,000 100,000
Unsecured notes 2005 7.625% 300,000 300,000
Unsecured notes 2011 6.375% 400,000 400,000
Unsecured notes 2012 6.50% 375,000 --
Senior notes (g) 2006 6.75% 83,695 83,695
Capitalized lease obligations 2003-2012 5.78% 20,400 1,343
----------- -----------
Subtotal 2,220,843 2,074,525
----------- -----------
SUNCOR
Revolving credit 2003-2004 (h) 125,500 128,000
Notes payable 2003-2008 (i) 7,646 7,912
Bonds payable 2024 5.95% 5,090 5,215
Bonds payable 2026 6.75% 7,500 7,500
Capitalized lease obligations 2003-2007 8.91% 1,299 --
----------- -----------
Subtotal 147,035 148,627
----------- -----------
PINNACLE WEST
Senior notes 2003-2006 (j) 540,000 325,000
Unamortized discount and premium (530) --
Floating rate notes 2003 (k) 250,000 250,000
Capitalized lease obligations 2004-2007 5.48% 1,999 1,066
----------- -----------
Subtotal 791,469 576,066
----------- -----------
EL DORADO
Construction loan 2005 1.77% 2,600 --
Capitalized lease obligations 2004-2005 7.04% 771 --
----------- -----------
Subtotal 3,371 --
----------- -----------
Total long-term debt 3,162,718 2,799,218
Less current maturities 281,023 126,140
----------- -----------
TOTAL LONG-TERM DEBT
LESS CURRENT
MATURITIES $ 2,881,695 $ 2,673,078
=========== ===========
104
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) This schedule does not reflect the timing of redemptions that may occur
prior to maturity.
(b) On March 15, 2002, APS redeemed at maturity $125 million of its First
Mortgage Bonds, 8.125% Series due 2002.
(c) On April 15, 2002, APS redeemed $122 million of its First Mortgage Bonds,
8.75% Series due 2024.
(d) The weighted-average rate was 1.94% at December 31, 2002 and 2.55% at
December 31, 2001. Changes in short-term interest rates would affect the
costs associated with this debt.
(e) In November 2001, these bonds were converted to a one-year fixed rate of
3.30%. These bonds were previously adjustable rate and, from January 1,
2001 until October 31, 2001, the weighted average rate was 2.72%.
(f) On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation
issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds
(Arizona Public Service Company Palo Verde Project) 2002 Series A, due
2029, and loaned the proceeds to APS pursuant to a loan agreement. The
bonds were issued to refinance $90 million of outstanding pollution control
bonds. The bondholders were issued $90 million of first mortgage bonds
(senior note mortgage bonds) as collateral.
(g) APS currently has outstanding $84 million of first mortgage bonds (senior
note mortgage bonds) issued to the senior note trustee as collateral for
the senior notes, as well as the $90 million issue discussed in footnote
(f) above. The senior note mortgage bonds have the same interest rate,
interest payment dates, maturity and redemption provisions as the senior
notes. APS' payments of principal, premium and/or interest on the senior
notes satisfy its corresponding payment obligations on the senior note
mortgage bonds. As long as the senior note mortgage bonds secure the senior
notes, the senior notes will effectively rank equally with the first
mortgage bonds. When APS repays all of its first mortgage bonds, other than
those that secure senior notes, the senior note mortgage bonds will no
longer secure the senior notes and will cease to be outstanding.
(h) The weighted-average rate was 3.75% at December 31, 2002 and was 5.31% at
December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 2% or
prime plus 0.5%.
(i) Multiple notes primarily with variable interest rates based mostly on the
lenders' prime plus 1.75% and lenders' prime plus .25%.
(j) Includes three series of notes: $25 million at 6.87% due in 2003, $300
million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of
December 31, 2002.
(k) The weighted average rate was 2.85% at December 31, 2002 and was 4.65% at
December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus
0.98%.
Pinnacle West's and APS' significant debt covenants related to their
respective financing arrangements include a debt-to-total-capitalization ratio
and an interest coverage test. Pinnacle West and APS are in compliance with such
covenants and each anticipates it will continue to meet all the significant
covenant requirement levels. Failure to comply with such covenant levels would
result in an event of default which, generally speaking, would require the
immediate repayment of the debt subject to the covenants.
Neither Pinnacle West's nor APS' financing agreements contain "ratings
triggers" that would result in an acceleration of the required interest and
principal payments in the event of a ratings downgrade. However, in the event of
a ratings downgrade, Pinnacle West and/or APS may be subject to increased
interest costs under certain financing agreements.
105
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All of Pinnacle West's bank agreements contain "cross-default" provisions
under which a default by it or APS in a specified amount under another agreement
would result in a default and the potential acceleration of payment under the
agreements. All of APS' bank agreements contain cross-default provisions under
which a default by APS in a specified amount under another agreement would
result in a default and the potential acceleration of payment under the
agreements. Pinnacle West's and APS' credit agreements generally contain
provisions under which the lenders could refuse to advance loans in the event of
a material adverse change in the borrower's financial condition or financial
prospects.
The following is a list of payments due on total long-term debt and
capitalized lease requirements through 2007:
* $281 million in 2003;
* $552 million in 2004;
* $405 million in 2005;
* $390 million in 2006;
* $3 million in 2007; and
* $1,539 million, thereafter.
APS' first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. APS may pay dividends on its common
stock if there is a sufficient amount "available" from retained earnings and the
excess of cumulative book depreciation (since the mortgage's inception) over
mortgage depreciation, which is the cumulative amount of additional property
pledged each year to address collateral depreciation. As of December 31, 2002,
the amount "available" under the mortgage would have allowed APS to pay
approximately $3 billion of dividends compared to APS' current annual common
stock dividends of $170 million.
7. COMMON STOCK AND TREASURY STOCK
Our common stock and treasury stock activity during each of the three years
2002, 2001 and 2000 is as follows (dollars in thousands, except shares):
106
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMMON STOCK TREASURY STOCK
------------------------- -------------------------
SHARES AMOUNT SHARES AMOUNT
---------- ----------- ---------- -----------
Balance at December 31, 1999 84,824,947 $ 1,540,197 (74,844) $ (2,748)
Purchase of treasury stock (300,800) (12,968)
Reissuance of treasury stock
for stock compensation (net) 266,006 10,627
Other (2,277)
---------- ----------- ---------- -----------
Balance at December 31, 2000 84,824,947 1,537,920 (109,638) (5,089)
Purchase of treasury stock (334,600) (16,393)
Reissuance of treasury stock
for stock compensation (net) 342,931 15,596
Other (996)
---------- ----------- ---------- -----------
Balance at December 31, 2001 84,824,947 1,536,924 (101,307) (5,886)
Common stock issuance -
December 23, 2002 6,555,000 199,238
Purchase of treasury stock (150,500) (5,971)
Reissuance of treasury stock
for stock compensation (net) 126,977 7,499
Other 1,096
---------- ----------- ---------- -----------
Balance at December 31, 2002 91,379,947 $ 1,737,258 (124,830) $ (4,358)
========== =========== ========== ===========
8. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLANS
Pinnacle West sponsors a qualified defined benefit pension plan and a
non-qualified supplemental excess benefit retirement plan for the employees of
Pinnacle West and our subsidiaries. Effective January 1, 2003, Pinnacle West
sponsored a new account balance pension plan for all new employees in place of
the defined benefit plan and, effective April 1, 2003, the new plan will be
offered as an alternative to the defined benefit plan for all existing
employees. A defined benefit plan specifies the amount of benefits a plan
participant is to receive using information about the participant. The pension
plan covers nearly all of our employees. The supplemental excess benefit plan
covers officers of the company and highly compensated employees designated for
participation by the Board of Directors. Our employees do not contribute to the
plans. Generally, we calculate the benefits based on age, years of service and
pay. We fund the qualified plan by contributing at least the minimum amount
required under IRS regulations but no more than the maximum tax-deductible
amount. The assets in the qualified plan at December 31, 2002 were mostly
domestic common stocks and bonds and real estate.
Total pension expense, including administrative costs and after
consideration of amounts capitalized or billed to electric plant participants,
was:
* $14 million in 2002;
* $11 million in 2001; and
107
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* $6 million in 2000.
The following table shows the components of net periodic pension cost
before consideration of amounts capitalized or billed to electric plant
participants for the years ended December 31, 2002, 2001 and 2000 (dollars in
thousands):
2002 2001 2000
-------- -------- --------
Service cost - benefits earned during the period $ 30,333 $ 27,640 $ 26,040
Interest cost on projected benefit obligation 71,242 66,549 61,625
Expected return on plan assets (75,652) (77,340) (77,231)
Amortization of:
Transition asset (3,227) (3,227) (3,227)
Prior service cost 2,912 3,008 2,370
Net actuarial loss/(gain) 1,846 907 (1,190)
-------- -------- --------
Net periodic pension cost $ 27,454 $ 17,537 $ 8,387
======== ======== ========
The following table shows a reconciliation of the funded status of the
plans to the amounts recognized in the Consolidated Balance Sheets as of
December 31, 2002 and 2001 (dollars in thousands):
2002 2001
---------- ---------
Funded status - pension plan assets less than
projected benefit obligation $ (348,770) $(166,773)
Unrecognized net transition asset (10,327) (13,554)
Unrecognized prior service cost 23,148 26,170
Unrecognized net actuarial losses 293,223 108,422
---------- ---------
Accrued pension benefit liability recognized in the
Consolidated Balance Sheets $ (42,726) $ (45,735)
========== =========
The following table sets forth the defined benefit pension plans' change in
projected benefit obligation for the plan years 2002 and 2001 (dollars in
thousands):
2002 2001
---------- ---------
Projected pension benefit obligation at
beginning of year $ 931,646 $ 840,485
Service cost 30,333 27,640
Interest cost 71,242 66,549
Benefit payments (35,230) (33,282)
Actuarial losses 71,696 21,632
Plan amendments (110) 8,622
---------- ---------
Projected pension benefit obligation at end of year $1,069,577 $ 931,646
========== =========
The following table sets forth the qualified defined benefit pension plans'
change in the fair value of plan assets for the plan years 2002 and 2001
(dollars in thousands):
108
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2002 2001
--------- ---------
Fair value of pension plan assets at beginning of year $ 764,873 $ 775,196
Actual loss on plan assets (36,966) (22,876)
Employer contributions 26,600 44,200
Benefit payments (33,700) (31,647)
--------- ---------
Fair value of pension plan assets at end of year $ 720,807 $ 764,873
========= =========
The following table sets forth the defined benefit pension plans' amounts
recognized in the Consolidated Balance Sheets at December 31, 2002 and 2001
(dollars in thousands):
2002 2001
--------- ---------
Accrued pension benefit liability $ (42,726) $ (45,735)
Additional minimum liability (141,155) (3,297)
Intangible asset 23,148 1,697
Accumulated other comprehensive loss - pretax 118,007 1,600
The following table shows the accumulated benefit obligation in relation to
the fair value of plan assets for the plan years 2002 and 2001 (dollars in
thousands):
2002 2001
---------- ---------
Projected benefit obligation $1,069,577 $ 931,646
Accumulated benefit obligation 904,687 752,230
Fair value of plan assets 720,807 764,873
The following are weighted-average assumptions as of December 31, 2002 and
2001:
2002 2001
---------- ---------
Discount rate 6.75% 7.50%
Rate of increase in compensation levels 4.00% 4.00%
Expected long-term rate of return on assets 9.00% 10.00%
EMPLOYEE SAVINGS PLAN BENEFITS
Pinnacle West sponsors a defined contribution savings plan for the
employees of Pinnacle West and our subsidiaries. In a defined contribution
savings plan, the benefits a participant will receive result from regular
contributions they make to a participant account. Under this plan, we make
matching contributions in Pinnacle West stock to participant accounts. After a
five-year vesting period, participants have a choice to change the employer
109
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
contribution match to other investments. At December 31, 2002, approximately 25%
of total plan assets were in Pinnacle West stock. We recorded expenses for this
plan of approximately $5 million for 2002 and 2001 and $4 million for 2000.
OTHER POSTRETIREMENT BENEFITS
Pinnacle West sponsors other postretirement benefits for the employees of
Pinnacle West and our subsidiaries. We provide medical and life insurance
benefits to retired employees. Employees must retire to become eligible for
these retirement benefits, which are based on years of service and age. For the
medical insurance plans, retirees make contributions to cover a portion of the
plan costs. For the life insurance plan, retirees do not make contributions. We
retain the right to change or eliminate these benefits.
Funding is based upon actuarially determined contributions that take tax
consequences into account. Plan assets consist primarily of domestic stocks and
bonds. The other postretirement benefit expense, after consideration of amounts
capitalized or billed to electric plant participants, was:
* $12 million for 2002;
* $6 million for 2001; and
* $3 million for 2000.
The following table shows the components of net periodic other
postretirement benefit costs before consideration of amounts capitalized or
billed to electric plant participants for the years ended December 31, 2002,
2001 and 2000 (dollars in thousands):
2002 2001 2000
-------- -------- --------
Service cost - benefits earned during the period $ 12,036 $ 9,438 $ 8,613
Interest cost on accumulated benefit obligation 25,235 21,585 19,315
Expected return on plan assets (21,116) (21,985) (22,381)
Amortization of:
Transition obligation 4,001 7,698 7,698
Prior service credit (75) -- --
Net actuarial loss/(gain) 3,072 (4,066) (7,983)
-------- -------- --------
Net periodic other postretirement benefit cost $ 23,153 $ 12,670 $ 5,262
======== ======== ========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the Consolidated Balance Sheets at December 31,
2002 and 2001 (dollars in thousands):
110
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2002 2001
--------- ---------
Funded status - other postretirement plan assets less
than accumulated other postretirement benefit obligation $(186,400) $ (80,544)
Unrecognized net obligation at transition 36,489 84,748
Unrecognized prior service credit (1,673) --
Unrecognized net actuarial loss/(gain) 148,268 (8,606)
--------- ---------
Net other postretirement benefit liability recognized in the
Consolidated Balance Sheets $ (3,316) $ (4,402)
========= =========
The following table sets forth the other postretirement benefit plan's
change in accumulated postretirement benefit obligation for the plan years 2002
and 2001 (dollars in thousands):
2002 2001
--------- ---------
Accumulated other postretirement benefit obligation at
beginning of year $ 318,355 $ 264,006
Service cost 12,036 9,438
Interest cost 25,235 21,585
Benefit payments (10,473) (10,194)
Actuarial losses 108,979 33,520
Plan amendments (44,258)(a) --
--------- ---------
Accumulated other postretirement benefit obligation at
end of year $ 409,874 $ 318,355
========= =========
(a) The plan was amended January 1, 2002 to increase the deductibles,
out-of-pocket maximums and prescription drug co-pays. The plan was amended
in June 2002 to increase the participants' portion of premiums.
The following table sets forth the other postretirement benefit plan's
change in the fair value of plan assets for the plan years 2002 and 2001
(dollars in thousands):
2002 2001
--------- ---------
Fair value of other postretirement benefit plan
assets at beginning of year $ 237,810 $ 249,154
Actual loss on plan assets (27,802) (12,550)
Employer contributions 23,600 11,400
Benefit payments (10,134) (10,194)
--------- ---------
Fair value of other postretirement benefit plan
assets at end of year $ 223,474 $ 237,810
========= =========
111
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following are weighted-average assumptions as of December 31, 2002 and
2001:
2002 2001
------- -------
Discount rate 6.75% 7.50%
Expected long-term rate of return on assets - pretax 9.00% 10.00%
Expected long-term rate of return on assets - after tax 7.84% 8.71%
Initial health care cost trend rate - under age 65 8.00% 7.00%
Initial health care cost trend rate - age 65 and over 8.00% 7.00%
Ultimate health care cost trend rate 5.00% 5.00%
Year ultimate health care trend rate is reached 2007 2006
The following table shows the effect of a 1% increase or decrease in the
initial and ultimate health care expense and cost trend rate (dollars in
millions):
1% increase 1% decrease
----------- -----------
Effect on the 2002 other postretirement benefit expense,
after consideration of amounts capitalized or billed
to electric plant participants $ 5 $ (4)
Effect on the 2002 service and interest cost components of
net periodic other postretirement benefit costs 7 (6)
Effect on the accumulated other postretirement benefit
obligation at December 31, 2002 54 (43)
SEVERANCE CHARGES
In July 2002, we implemented a voluntary workforce reduction as part of our
cost reduction program. We recorded $36 million before taxes in voluntary
severance costs in 2002. No further charges are expected.
9. LEASES
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. APS accounts
for these leases as operating leases. The gain resulting from the transaction of
approximately $140 million was deferred and is being amortized to operations and
maintenance expense over 29.5 years, the original term of the leases. There are
options to renew the leases for two additional years and to purchase the
property for fair market value at the end of the lease terms. Consistent with
the ratemaking treatment, a regulatory asset is recognized for the difference
between lease payments and rent expense calculated on a straight-line basis. See
Note 20 for a discussion of VIEs, including the SPEs involved in the Palo Verde
sale-leaseback transactions.
112
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition, we lease certain land, buildings, equipment, vehicles and
miscellaneous other items through operating rental agreements with varying
terms, provisions and expiration dates.
Total lease expense recognized in the Consolidated Statements of Income was
$62 million in 2002, $56 million in 2001 and $58 million in 2000.
The amounts to be paid for the Palo Verde Unit 2 leases are approximately
$49 million per year for the years 2003 to 2015.
In accordance with the 1999 Settlement Agreement and previous settlement
agreements, APS is continuing to accelerate amortization of the regulatory asset
for leases over an eight-year period that will end June 30, 2004 (see Note 1).
All regulatory asset amortization is included in depreciation and amortization
expense in the Consolidated Statements of Income. The balance of this regulatory
asset at December 31, 2002 was $14 million.
Estimated future minimum lease payments for our operating leases are
approximately as follows (dollars in millions):
Year
------------------
2003 $ 70
2004 66
2005 64
2006 63
2007 63
Thereafter 478
-----
Total future lease
commitments $ 804
=====
10. JOINTLY-OWNED FACILITIES
APS shares ownership of some of its generating and transmission facilities
with other companies. The following table shows APS' interest in those
jointly-owned facilities recorded on the Consolidated Balance Sheets at December
31, 2002. APS' share of operating and maintaining these facilities is included
in the Consolidated Statements of Income in operations and maintenance expense.
113
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERCENT CONSTRUCTION
OWNED BY PLANT IN ACCUMULATED WORK IN
APS SERVICE DEPRECIATION PROGRESS
--- ------- ------------ --------
(dollars in thousands)
Generating facilities:
Palo Verde Nuclear Generating Station
Units 1 and 3 29.1% $1,829,225 $(905,278) $17,428
Palo Verde Nuclear Generating Station
Unit 2 (see Note 9) 17.0% 574,745 (289,049) 68,475
Four Corners Steam Generating Station
Units 4 and 5 15.0% 153,559 (82,434) 500
Navajo Steam Generating Station
Units 1, 2 and 3 14.0% 235,743 (110,923) 3,010
Cholla Steam Generating Station
Common Facilities (a) 62.8%(b) 76,322 (42,608) 1,733
Transmission facilities:
ANPP 500KV System 35.8%(b) 68,314 (25,655) 31
Navajo Southern System 31.4%(b) 27,129 (17,405) 664
Palo Verde-Yuma 500KV System 23.9%(b) 9,591 (4,168) 383
Four Corners Switchyards 27.5%(b) 3,071 (1,979) --
Phoenix-Mead System 17.1%(b) 36,418 (2,906) --
Palo Verde - Estrella 500KV System 50.0%(b) -- -- 50,450
(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
11. COMMITMENTS AND CONTINGENCIES
ENRON
We recorded charges totaling $21 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. This amount is
comprised of a $15 million reserve for the Company's net exposure to Enron and
its affiliates and additional expenses of $6 million primarily related to 2002
power contracts with Enron that were canceled. These charges take into
consideration our rights of set-off with respect to the Enron related
contractual obligations. The APS portion of the write-off was $13 million. The
basis of the set-offs included, but was not limited to, provisions in the
various contractual arrangements with Enron and its affiliates, including an
International Swaps and Derivative Agreement (ISDA) between APS and Enron North
America. The write-off is also net of the expected recovery based on secondary
market quotes from the bond market. The amounts were written-off from the
balances of the related assets and liabilities from risk management and trading
activities on the Consolidated Balance Sheets.
PALO VERDE NUCLEAR GENERATING STATION
Nuclear power plant operators are required to enter into spent fuel
disposal contracts with the DOE, and the DOE is required to accept and dispose
of all spent nuclear fuel and other high-level radioactive wastes generated by
domestic power reactors. Although the Nuclear Waste Act required the DOE to
develop a permanent repository for the storage and disposal of spent nuclear
fuel by 1998, the DOE has announced that the repository cannot be completed
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
before 2010 and it does not intend to begin accepting spent nuclear fuel prior
to that date. In November 1997, the United States Court of Appeals for the
District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE
from excusing its own delay, but refused to order the DOE to begin accepting
spent nuclear fuel. Based on this decision and the DOE's delay, a number of
utilities filed damages actions against the DOE in the Court of Federal Claims.
In February 2002, the Secretary of Energy recommended to President Bush
that the Yucca Mountain, Nevada site be developed as a permanent repository for
spent nuclear fuel. The President transmitted this recommendation to Congress
and the State of Nevada vetoed the President's recommendation. Congress approved
the Yucca Mountain site, overriding the Nevada veto. It is now expected that the
DOE will submit a license application to the NRC in late 2004.
APS has existing fuel storage pools at Palo Verde and is in the process of
completing construction of a new facility for on-site dry storage of spent
nuclear fuel. With the existing storage pools and the addition of the new
facility, APS believes spent nuclear fuel storage or disposal methods will be
available for use by Palo Verde to allow its continued operation through the
term of the operating license for each Palo Verde unit.
Although some low-level waste has been stored on-site in a low-level waste
facility, APS is currently shipping low-level waste to off-site facilities. APS
currently believes interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
APS currently estimates it will incur $115 million (in 2002 dollars) over
the life of Palo Verde for its share of the costs related to the on-site interim
storage of spent nuclear fuel. As of December 31, 2002, APS had spent $2 million
and recorded accumulated spent nuclear fuel amortization of $44 million and a
regulatory asset of $46 million for on-site interim spent nuclear fuel storage
costs related to nuclear fuel burned to date.
The Palo Verde participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $200 million ($300 million
effective January 1, 2003) and the balance by an industry-wide retrospective
assessment program. If losses at any nuclear power plant covered by the programs
exceed the accumulated funds, APS could be assessed retrospective premium
adjustments. The maximum assessment per reactor under the program for each
nuclear incident is approximately $88 million, subject to an annual limit of $10
million per incident. Based on APS' interest in the three Palo Verde units, APS'
maximum potential assessment per incident for all three units is approximately
$77 million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. APS has also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
PURCHASED POWER AND FUEL COMMITMENTS
APS and Pinnacle West are parties to various purchased power and fuel
contracts with terms expiring from 2003 through 2025 that include required
purchase provisions. We estimate the contract requirements to be approximately
$173 million in 2003; $82 million in 2004; $28 million in 2005; $31 million in
2006; $17 million in 2007 and $162 million thereafter. However, these amounts
may vary significantly pursuant to certain provisions in such contracts that
permit us to decrease required purchases under certain circumstances.
Of the various purchased power and fuel contracts mentioned above some of
those contracts have take-or-pay provisions. The contracts APS has for the
supply of its coal and nuclear fuel supply have take-or-pay provisions. The
current take-or-pay nuclear fuel contracts expire in 2003 and had not been
renewed as of December 31, 2002. The current take-or-pay coal contracts have
terms that expire in 2007.
The following table summarizes the estimated take-or-pay commitments for
the existing terms (dollars in millions):
Estimated
Years Ending December 31,
--------------------------------------------
2003 2004 2005 2006 2007
---- ---- ---- ---- ----
Coal $ 43 $ 44 $ 9 $ 9 $ 9
Nuclear Fuel 22 -- -- -- --
---- ---- ---- ---- ----
Total take-or-pay
commitments (a) $ 65 $ 44 $ 9 $ 9 $ 9
==== ==== ==== ==== ====
(a) Total take-or-pay commitments are approximately $136 million. The total net
present value of these commitments is approximately $119 million.
COAL MINE RECLAMATION OBLIGATIONS
APS must reimburse certain coal providers for amounts incurred for coal
mine reclamation. Our coal mine reclamation obligation is about $59 million at
December 31, 2002 and is included in deferred credits-other in the Consolidated
Balance Sheets.
A regulatory asset has been established for amounts not yet recovered from
ratepayers related to the coal obligations. In accordance with the 1999
Settlement Agreement with the ACC, APS is continuing to accelerate the
amortization of the regulatory asset for coal mine reclamation over an
eight-year period that will end June 30, 2004. Amortization is included in
depreciation and amortization expense on the Consolidated Statements of Income.
CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST
In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC directed
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
an ALJ to make findings of fact with respect to: (1) the mitigated price in each
hour of the refund period; (2) the amount of refunds owed by each supplier
according to the methodology established in the order; and (3) the amount
currently owed to each supplier (with separate quantities due from each entity)
by the CAISO, the California Power Exchange, the investor-owned utilities and
the State of California.
APS was a seller and a purchaser in the California markets at issue, and to
the extent that refunds are ordered, APS should be a recipient as well as a
payor of such amounts. On December 12, 2002, the ALJ issued Proposed Findings of
Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great
majority of the proposed findings, revising only the calculation of natural gas
prices for the final determination of mitigated prices in the California
markets. Sellers who may actually have paid more for natural gas than the proxy
prices adopted by the FERC have 40 days in which to submit necessary data to the
FERC, after which a technical conference will be held. Finalization of refund
amounts is expected in mid-2003. APS does not anticipate material changes in its
exposure and still believes, subject to the finalization of the revised proxy
prices, that it will be entitled to a net refund.
On November 20, 2002, the FERC reopened discovery in these proceedings
pursuant to instructions of the United States Court of Appeals for the Ninth
Circuit, that the FERC permit parties to offer additional evidence of potential
market manipulation for the period January 1, 2000 through June 20, 2001.
Parties have submitted additional evidence and proposed findings, which the FERC
continues to consider.
The FERC also ordered an evidentiary proceeding to discuss and evaluate
possible refunds for the Pacific Northwest. The FERC required that the record
establish the volume of the transactions, the identification of the net sellers
and net buyers, the price and terms and conditions of the sales contracts and
the extent of potential refunds. On September 24, 2001, an ALJ concluded that
prices in the Pacific Northwest during the period December 25, 2000 through June
20, 2001 were the result of a number of factors in addition to price signals
from the California markets, including the shortage of supply, excess demand,
drought and increased natural gas prices. Under these circumstances, the ALJ
ultimately concluded that the prices in the Pacific Northwest were not
unreasonable or unjust and refunds should not be ordered in this proceeding. The
FERC is currently reviewing the ALJ's report and recommendations.
On December 19, 2002, the FERC opened a new discovery period to permit the
parties to offer additional evidence for the period January 1, 2000 through June
20, 2001. Additional evidence has been submitted and a FERC decision on the
newly submitted evidence is expected soon. Based on public comments from the
FERC, it is anticipated that this case will be sent back to the ALJ for further
proceedings on spot market and balance of month transactions.
Although the FERC has not yet made a final ruling in the Pacific Northwest
matter nor calculated the specific refund amounts due in California, we do not
expect that the resolution of these issues, as to the amounts alleged in the
proceedings, will have a material adverse impact on our financial position,
results of operations or liquidity.
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PINNACLE WEST CAPITAL CORPORATION
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On March 26, 2003, FERC made public a Final Report on Price Manipulation in
Western Markets, prepared by its Staff and covering spot markets in the West in
2000 and 2001. The report stated that a significant number of entities who
participated in the California markets during 2000-2001 time period, including
APS, may potentially have been involved in arbitrage transactions that allegedly
violated certain provisions of the ISO tariff. The report also recommended that
the FERC issue an order to show cause why these transactions did not violate the
ISO tariff, with potential disgorgement of any unjust profits. Although APS has
not yet had an opportunity to review the transactions at issue, it believes that
it was not engaged in any such improper transactions. Based on the information
available, it also appears that such transactions would not have a material
adverse impact on our financial position, results of operations or liquidity.
SCE and PG&E have publicly disclosed that their liquidity has been
materially and adversely affected because of, among other things, their
inability to pass on to ratepayers the prices each has paid for energy and
ancillary services procured through the PX and the ISO. PG&E filed for
bankruptcy protection in 2001.
We are closely monitoring developments in the California energy market and
the potential impact of these developments on us and our subsidiaries. Based on
our evaluations, we previously reserved $10 million before income taxes for our
credit exposure related to the California energy situation, $5 million of which
was recorded in the fourth quarter of 2000 and $5 million of which was recorded
in the first quarter of 2001. Our evaluations took into consideration our range
of exposure of approximately zero to $38 million before income taxes and review
of likely recovery rates in bankruptcy situations.
In the second quarter of 2002, PG&E filed its Modified Second Amended
Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization.
Both plans generally indicated that PG&E would, at the close of bankruptcy
proceedings, be able to pay in full all outstanding, undisputed debts. As a
result of these developments, the probable range of our total exposure now is
approximately zero to $27 million before income taxes, and our best estimate of
the probable loss is now approximately $6 million before income taxes.
Consequently, we reversed $4 million of the $10 million reserve in the second
quarter of 2002. We cannot predict with certainty, however, the impact that any
future resolution or attempted resolution, of the California energy market
situation may have on us, our subsidiaries or the regional energy market in
general.
CALIFORNIA ENERGY MARKET LITIGATION On March 19, 2002, the State of
California filed a complaint with the FERC alleging that wholesale sellers of
power and energy, including the Company, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the
present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET AL., Docket
No. EL02-71-000. The complaint requests the FERC to require the wholesale
sellers to refund any rates that are "found to exceed just and reasonable
levels." This complaint has been dismissed by the FERC and the State of
California is now appealing the matter to the Ninth Circuit Court of Appeals. In
addition, the State of California and others have filed various claims, which
have now been consolidated, against several power suppliers to California
alleging antitrust violations. WHOLESALE ELECTRICITY ANTITRUST CASES I AND II,
Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005
and 4204-00006. Two of the suppliers who were named as defendants in those
matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke
Energy and Trading, LLP (and other Duke entities), filed cross-claims against
various other participants in the PX and ISO markets, including APS, attempting
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
to expand those matters to such other participants. APS has not yet filed a
responsive pleading in the matter, but APS believes the claims by Reliant and
Duke as they relate to APS are without merit.
APS was also named in a lawsuit regarding wholesale contracts in
California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United
States District Court in and for the District of Northern California, Case No.
C02-2855 EMC. The complaint alleges basically that the contracts entered into
were the result of an unfair and unreasonable market. The PX has filed a lawsuit
against the State of California regarding the seizure of forward contracts and
the State has filed a cross complaint against APS and numerous other PX
participants. CAL PX V. THE STATE OF CALIFORNIA Superior Court in and for the
County of Sacramento, JCCP No. 4203. Various preliminary motions are being filed
and we cannot currently predict the outcome of this matter. The "United States
Justice Foundation" is suing numerous wholesale energy contract suppliers to
California, including us, as well as the California Department of Water
Resources, based upon an alleged conflict of interest arising from the
activities of a consultant for Edison International who also negotiated
long-term contracts for the California Department of Water Resources.
MCCLINTOCK, ET AL. V. YUDHRAJA, Superior Court in and for the County of Los
Angeles, Case No. GC 029447. The California Attorney General has indicated that
an investigation by his office did not find evidence of improper conduct by the
consultant. We believe the claims against APS and us in the lawsuits mentioned
in this paragraph are without merit and will have no material adverse impact on
our financial position, results of operations or liquidity.
POWER SERVICE AGREEMENT
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised APS that it believes APS overcharged Citizens by over $50 million under
a power service agreement. APS believes its charges under the agreement were
fully in accordance with the terms of the agreement. In addition, in testimony
filed with the ACC on March 13, 2002, Citizens acknowledged, based on its
review, "if Citizens filed a complaint with FERC, it probably would lose the
central issue in the contract interpretation dispute." APS and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, the Company and Citizens entered into a power
sale agreement under which the Company will supply Citizens with future
specified amounts of electricity and ancillary services through May 31, 2008.
This new agreement does not address issues previously raised by Citizens with
respect to charges under the original power service agreement through June 1,
2001.
CONSTRUCTION PROGRAM
Consolidated capital expenditures in 2003 are estimated to be (dollars in
millions):
APS $ 401
Pinnacle West Energy 268
SunCor 64
Other (primarily APS Energy
Services and Pinnacle West) 17
-----
Total $ 750
=====
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PINNACLE WEST ENERGY'S GENERATION CONSTRUCTION
Pinnacle West Energy's generation construction plan is as follows:
* A 650 MW combined cycle expansion of the West Phoenix Power Plant in
Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation in
June 2001. Construction has begun on the 530 MW West Phoenix Unit 5,
with commercial operation expected to begin in mid-2003.
* The Redhawk Power Plant, two 530 MW combined cycle units, near Palo
Verde. Commercial operation began in July 2002. Based on an analysis
of the financial situation of the Company and the market as a whole,
among other things, Pinnacle West has cancelled plans to construct the
additional two 530 MW combined cycle units, Redhawk Units 3 and 4. As
a result we recorded a pretax charge of approximately $49 million in
December 2002.
* The construction of an 80 MW simple-cycle power plant at Saguaro in
Southern Arizona. Commercial operation began in July 2002.
* Development of the 570 MW Silverhawk combined-cycle plant 20 miles
north of Las Vegas, Nevada. Construction of the plant began in August
2002, with an expected commercial operation date of mid-2004. Pinnacle
West Energy has signed an agreement with Las Vegas-based SNWA under
which SNWA has an option to purchase a 25% interest in the project for
approximately $100 million.
* A Pinnacle West Energy affiliate is exploring the possibility of
creating an underground natural gas storage facility on Company-owned
land west of Phoenix. An analysis to determine the feasibility of the
project is in progress.
LITIGATION
We are party to various claims, legal actions and complaints arising in the
ordinary course of business, including but not limited to environmental matters
related to the Clean Air Act, Navajo Nation issues and ADEQ issues. In our
opinion, the ultimate resolution of these matters will not have a material
adverse effect on our consolidated financial statements, results of operations
or liquidity.
12. NUCLEAR DECOMMISSIONING COSTS
APS recorded $11 million for nuclear decommissioning expense in each of the
years 2002, 2001 and 2000. APS estimates it will cost approximately $1.8 billion
($528 million in 2002 dollars) to decommission its share of the three Palo Verde
units. The majority of decommissioning costs are expected to be incurred over a
14-year period beginning in 2024. APS charges decommissioning costs to expense
over each unit's operating license term and APS includes them in the accumulated
depreciation balance until each unit is retired. Nuclear decommissioning costs
are recovered in rates.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS' current estimates are based on a 2001 site-specific study for Palo
Verde that assumes the prompt removal/dismantlement method of decommissioning.
An independent consultant prepared this study. APS is required by the ACC to
update the study every three years.
To fund the costs APS expects to incur to decommission the plant, APS
established external decommissioning trusts in accordance with NRC regulations
and ACC orders. APS invests the trust funds primarily in fixed income securities
and domestic stock and classifies them as available for sale. Realized and
unrealized gains and losses are reflected in accumulated depreciation in
accordance with industry practice. The following table shows the cost and fair
value of our nuclear decommissioning trust fund assets, which were reported in
investments and other assets on the Consolidated Balance Sheets at December 31,
2002 and 2001 (dollars in millions):
2002 2001
----- -----
Trust fund assets - at cost:
Fixed income securities $ 113 $ 103
Domestic stock 68 61
----- -----
Total $ 181 $ 164
===== =====
Trust fund assets - fair value:
Fixed income securities $ 117 $ 106
Domestic stock 77 96
----- -----
Total $ 194 $ 202
===== =====
See Note 2 for information on a new accounting standard on accounting for
certain liabilities related to closure or removal of long-lived assets.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Consolidated quarterly financial information for 2002 and 2001 is as
follows:
(dollars in thousands, except per share amounts)
2002
-------------------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31 (a)
-------- ------- ------------ ---------------
Operating revenues (b)
Regulated electricity segment $ 380,241 $ 496,837 $ 719,361 $ 416,584
Marketing and trading
segment 75,815 49,503 87,258 113,355
Real estate segment 41,185 69,152 45,108 80,943
Other revenues (c) 4,277 2,881 21,224 33,555
Operating income $ 119,438 $ 166,706 $ 213,025 $ 16,878
Income (loss) before accounting
change $ 53,757 $ 75,365 $ 100,916 $ (14,885)
Cumulative effect of change in
accounting - net of income tax -- -- -- (65,745)
--------- --------- --------- ---------
Net income (loss) $ 53,757 $ 75,365 $ 100,916 $ (80,630)
========= ========= ========= =========
Earnings (loss) per weighted
average common share
outstanding - basic:
Income before accounting
change $ 0.63 $ 0.89 $ 1.19 $ (0.18)
Cumulative effect of change
in accounting -- -- -- (0.77)
--------- --------- --------- ---------
Earnings per weighted average
common share outstanding -
basic $ 0.63 $ 0.89 $ 1.19 $ (0.95)
========= ========= ========= =========
Earnings (loss) per weighted
average common share
outstanding - diluted:
Income before accounting
change $ 0.63 $ 0.89 $ 1.19 $ (0.18)
Cumulative effect of change
in accounting -- -- -- (0.77)
--------- --------- --------- ---------
Earnings per weighted average
common share outstanding -
diluted $ 0.63 $ 0.89 $ 1.19 $ (0.95)
========= ========= ========= =========
Dividends declared per share $ 0.40 $ 0.40 $ 0.40 $ 0.425
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share amounts)
2001
----------------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ ------------
Operating revenues (b)
Regulated electricity segment $ 412,807 $ 739,317 $ 973,398 $ 436,569
Marketing and trading
segment 258,296 233,841 141,674 17,419
Real estate segment 32,335 32,454 43,024 61,095
Other revenues 1,543 1,653 2,682 5,893
Operating income $ 136,646 $ 140,010 $ 298,752 $ 100,615
Income before accounting
change $ 62,205 $ 66,857 $ 162,499 $ 35,806
Cumulative effect of change in
accounting - net of income tax (2,755) -- (12,446) --
--------- --------- --------- ---------
Net income $ 59,450 $ 66,857 $ 150,053 $ 35,806
========= ========= ========= =========
Earnings (loss) per weighted
average common share
outstanding - basic:
Income before accounting
change $ 0.73 $ 0.79 $ 1.92 $ 0.42
Cumulative effect of change
in accounting (0.03) -- (0.15) --
--------- --------- --------- ---------
Earnings per weighted average
common share outstanding -
basic $ 0.70 $ 0.79 $ 1.77 $ 0.42
========= ========= ========= =========
Earnings (loss) per weighted
average common share
outstanding - diluted:
Income before accounting
change $ 0.73 $ 0.79 $ 1.91 $ 0.42
Cumulative effect of change
in accounting (0.03) -- (0.14) --
--------- --------- --------- ---------
Earnings per weighted average
common share outstanding -
diluted $ 0.70 $ 0.79 $ 1.77 $ 0.42
========= ========= ========= =========
Dividends declared per share $ 0.375 $ 0.375 $ 0.375 $ 0.40
(a) The fourth quarter of 2002 included pretax losses of $38 million related to
our investment in NAC (see Note 22), a $49 million pretax write-off related
to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of
approximately $11 million.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(b) Electric revenues are seasonal in nature, with the peak sales periods
generally occurring during the summer months. Comparisons among quarters of
a year may not represent overall trends and changes in operations. We have
reclassified certain operating revenues to conform to the current
presentation of netting energy trading contracts (see Note 18).
(c) NAC financial statements were fully consolidated starting in third quarter
2002 (see Note 22).
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
We believe that the carrying amounts of our cash equivalents and commercial
paper are reasonable estimates of their fair values at December 31, 2002 and
2001 due to their short maturities.
We hold investments in debt and equity securities for purposes other than
trading. The December 31, 2002 and 2001 fair values of such investments, which
we determine by using quoted market prices, approximate their carrying amount.
On December 31, 2002, the carrying value of our long-term debt (excluding
capitalized lease obligations) was $3.15 billion, with an estimated fair value
of $3.25 billion. The carrying value of our long-term debt (excluding
capitalized lease obligations) was $2.80 billion on December 31, 2001, with an
estimated fair value of $2.82 billion. The fair value estimates are based on
quoted market prices of the same or similar issues.
15. EARNINGS PER SHARE
The following table presents earnings per weighted average common share
outstanding for the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000
-------- -------- --------
Basic earnings per share:
Income before accounting
change $ 2.53 $ 3.86 $ 3.57
Cumulative effect of change in
accounting (0.77) (0.18) --
-------- -------- --------
Earnings per share-basic $ 1.76 $ 3.68 $ 3.57
======== ======== ========
Diluted earnings per share:
Income before accounting
change $ 2.53 $ 3.85 $ 3.56
Cumulative effect of change in
accounting (0.77) (0.17) --
-------- -------- --------
Earnings per share-diluted $ 1.76 $ 3.68 $ 3.56
======== ======== ========
Dilutive stock options increased average common shares outstanding by
60,975 shares in 2002, 212,491 shares in 2001 and 202,738 shares in 2000. Total
average common shares outstanding for the purposes of calculating diluted
earnings per share were 84,963,921 shares in 2002, 84,930,140 shares in 2001 and
84,935,282 shares in 2000.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Options to purchase 1,629,958 shares of common stock were outstanding at
December 31, 2002 but were not included in the computation of diluted earnings
per share because the options' exercise price was greater than the average
market price of the common shares. Options to purchase shares of common stock
that were not included in the computation of diluted earnings per share were
212,562 at December 31, 2001 and 517,614 at December 31, 2000.
16. STOCK-BASED COMPENSATION
Pinnacle West offers stock-based compensation plans for officers and key
employees of our company and our subsidiaries.
In May 2002, shareholders approved the 2002 Long-term Incentive Plan (2002
plan), which allows Pinnacle West to grant performance shares, stock ownership
incentive awards and non-qualified and performance-accelerated stock options to
key employees. The Company has reserved 6 million shares of common stock for
issuance under the 2002 plan. No more than 1.8 million shares may be issued in
relation to performance share awards and stock ownership incentive awards. The
plan also provides for the granting of new non-qualified stock options at a
price per option not less than the fair market value of the common stock at the
time of grant. The stock options vest over three years, unless certain
performance criteria are met which can accelerate the vesting period. The term
of the option cannot be longer than 10 years and the option cannot be repriced
during its term.
The 1994 plan provides for the granting of new options (which may be
non-qualified stock options or incentive stock options) of up to 3.5 million
shares at a price per option not less than the fair market value on the date the
option is granted. The 1985 plan includes outstanding options but no new options
will be granted from the plan. Options vest one-third of the grant per year
beginning one year after the date the option is granted and expire ten years
from the date of the grant. The 1994 plan also provides for the granting of any
combination of shares of restricted stock, stock appreciation rights or dividend
equivalents.
In the third quarter of 2002, we began applying the fair value method of
accounting for stock-based compensation, as provided for in SFAS No. 123. The
fair value method of accounting is the preferred method. In accordance with the
transition requirements of SFAS No. 123, we applied the fair value method
prospectively, beginning with 2002 stock grants. In prior years, we recognized
stock compensation expense based on the intrinsic value method allowed in APB
No. 25. We recorded approximately $500,000 in stock option expense before income
taxes in our Consolidated Statements of Income in 2002. This amount may not be
reflective of the stock option expense we will record in future years because
stock options typically vest over several years and additional grants are
generally made each year.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." The standard amends SFAS No. 123 to
provide alternative methods of transition for a voluntary change to the fair
value method of accounting for stock-based compensation. The standard also
amends the disclosure requirements of SFAS No. 123. SFAS No. 148 is effective
for fiscal years ending after December 15, 2002. We adopted the disclosure
requirements in 2002. See Note 1 for our pro forma disclosures on stock-based
compensation and our weighted-average assumptions used to calculate the fair
value of our stock options.
125
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Total stock-based compensation expense, including stock option expense, was
$5 million in 2002, $3 million in 2001 and $2 million in 2000.
The following table is a summary of the status of our stock option plans as
of December 31, 2002, 2001 and 2000 and changes during the years ending on those
dates:
2002 2001 2000
Weighted Weighted Weighted
Average Average Average
2002 Exercise 2001 Exercise 2000 Exercise
Shares Price Shares Price Shares Price
---------- -------- ---------- -------- ---------- --------
Outstanding at
beginning of
year 1,832,725 $39.52 1,569,171 $37.55 1,441,124 $33.45
Granted 603,900 (a) 38.37 444,200 42.55 451,450 43.28
Exercised (163,381) 28.25 (162,229) 28.53 (283,819) 20.90
Forfeited (88,115) 41.54 (18,417) 41.67 (39,584) 39.86
---------- ---------- ----------
Outstanding at end
of year 2,185,129 39.96 1,832,725 39.52 1,569,171 37.55
========== ========== ==========
Options
exercisable
at year-end 1,155,357 39.66 926,315 37.41 831,537 34.37
========== ========== ==========
Weighted average
fair value of
options granted
during the year 6.16 8.84 11.81
(a) Beginning 2002, we recorded compensation expense related to stock options
under SFAS No. 123 (see above discussion).
The following table summarizes information about our stock options at
December 31, 2002:
Weighted Weighted Average Weighted
Average Remaining Average
Exercise Options Exercise Contract Options Exercise
Prices Per Share Outstanding Price Life (Years) Exercisable Price
- ---------------- ----------- ----- ------------ ----------- -----
$18.71 - 23.39 50,584 $ 20.73 1.3 50,584 $ 20.73
23.39 - 28.07 48,417 27.40 3.4 41,750 27.44
28.07 - 32.75 46,000 31.44 3.9 46,000 31.44
32.75 - 37.42 235,160 34.70 6.7 235,160 34.70
37.42 - 42.10 779,700 38.85 8.3 181,900 40.01
42.10 - 46.78 1,025,268 43.95 7.7 599,963 44.59
---------- ----------
2,185,129 1,155,357
========== ==========
126
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of the amount and weighted-average grant
date fair value of stock compensation awards granted, other than options, during
the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000
Weighted Weighted Weighted
Average Average Average
2002 Grant-Date 2001 Grant-Date 2000 Grant-Date
Shares Fair Value Shares Fair Value Shares Fair Value
------ ---------- ------ ---------- ------ ----------
Restricted stock 6,000 $38.84 95,450 $42.84 86,426 $44.03
Performance share
awards 115,975 38.37 -- -- -- --
Stock ownership
incentive awards (a) 9,650 38.37 -- -- -- --
(a) Shares are based on estimated ownership of Pinnacle West common stock.
17. BUSINESS SEGMENTS
We have three principal business segments (determined by products, services
and the regulatory environment):
* our regulated electricity segment, which consists of regulated
traditional retail and wholesale electricity businesses and related
activities, and includes electricity transmission, distribution and
generation;
* our marketing and trading segment, which consists of our competitive
business activities, including wholesale marketing and trading and APS
Energy Services' commodity-related energy services; and
* our real estate segment, which consists of SunCor's real estate
development and investment activities.
The amounts in our other segment include activity principally related to
NAC in 2002 (see Note 22), as well as the parent company and other subsidiaries.
Financial data for the years ended December 31, 2002, 2001 and 2000 by business
segments is provided as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Business Segments for the Year Ended December 31, 2002
-------------------------------------------------------------
Marketing Other
Regulated and (principally
Electricity Trading Real Estate NAC) Total
----------- ------- ----------- ------- -------
Operating revenues $ 2,013 $ 326 $ 236 $ 62 $ 2,637
Purchased power and fuel costs 500 194 -- -- 694
Other operating expenses 659 34 205 105 1,003
------- ------- ------- ------- -------
Operating margin 854 98 31 (43) 940
Depreciation and amortization 416 2 5 2 425
Interest and other expense 160 -- (5) 8 163
------- ------- ------- ------- -------
Pretax margin 278 96 31 (53) 352
Income taxes 108 38 12 (21) 137
------- ------- ------- ------- -------
Income (loss) before accounting
change 170 58 19 (32) 215
Cumulative effect of change in
accounting for trading activities
- net of income taxes of $43 -- (66) -- -- (66)
------- ------- ------- ------- -------
Net income(loss) $ 170 $ (8) $ 19 $ (32) $ 149
======= ======= ======= ======= =======
Total assets $ 7,589 $ 301 $ 504 $ 32 $ 8,426
======= ======= ======= ======= =======
Capital expenditures $ 893 $ 19 $ 72 $ -- $ 984
======= ======= ======= ======= =======
Business Segments for the Year Ended December 31, 2001
-------------------------------------------------------------
Marketing
Regulated and
Electricity Trading Real Estate Other Total
----------- ------- ----------- ------- -------
Operating revenues $ 2,562 $ 651 $ 169 $ 12 $ 3,394
Purchased power and fuel costs 1,161 334 -- -- 1,495
Other operating expenses 598 33 154 11 796
------- ------- ------- ------- -------
Operating margin 803 284 15 1 1,103
Depreciation and amortization 423 1 4 -- 428
Interest and other expense 129 -- 6 -- 135
------- ------- ------- ------- -------
Pretax margin 251 283 5 1 540
Income taxes 99 112 2 -- 213
------- ------- ------- ------- -------
Income before accounting change 152 171 3 1 327
Cumulative effect of change in
accounting for derivatives - net
of income taxes of $10 (15) -- -- -- (15)
------- ------- ------- ------- -------
Net income $ 137 $ 171 $ 3 $ 1 $ 312
======= ======= ======= ======= =======
Total assets $ 6,862 $ 589 $ 477 $ 11 $ 7,939
======= ======= ======= ======= =======
Capital expenditures $ 1,004 $ 23 $ 80 $ 22 $ 1,129
======= ======= ======= ======= =======
128
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Business Segments for the Year Ended December 31, 2000
-------------------------------------------------------------
Marketing
Regulated and
Electricity Trading Real Estate Other Total
----------- ------- ----------- ------- -------
Operating revenues $ 2,539 $ 418 $ 158 $ 4 $ 3,119
Purchased power and fuel costs 1,066 292 -- -- 1,358
Other operating expenses 532 18 134 1 685
------- ------- ------- ------- -------
Operating margin 941 108 24 3 1,076
Depreciation and amortization 426 1 5 -- 432
Interest and other expense 152 -- -- (4) 148
------- ------- ------- ------- -------
Pretax margin 363 107 19 7 496
Income taxes 142 42 8 2 194
------- ------- ------- ------- -------
Net income $ 221 $ 65 $ 11 $ 5 $ 302
======= ======= ======= ======= =======
Total assets $ 6,213 $ 459 $ 429 $ 22 $ 7,123
======= ======= ======= ======= =======
Capital expenditures $ 665 $ -- $ 50 $ -- $ 715
======= ======= ======= ======= =======
18. DERIVATIVE AND TRADING ACCOUNTING
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We manage risks associated with these market fluctuations by utilizing various
commodity derivatives, including exchange-traded futures and options and
over-the-counter forwards, options and swaps. As part of our overall risk
management program, we enter into derivative transactions to hedge purchases and
sales of electricity, fuels, and emissions allowances and credits. The changes
in market value of such contracts have a high correlation to price changes in
the hedged commodities. In addition, subject to specified risk parameters
monitored by the ERMC, we engage in marketing and trading activities intended to
profit from market price movements.
Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires
that entities recognize all derivatives as either assets or liabilities on the
balance sheet and measure those instruments at fair value. Changes in the fair
value of derivative instruments are either recognized periodically in income or,
if hedge criteria is met, in common stock equity (as a component of other
comprehensive income). We use cash flow hedges to limit our exposure to cash
flow variability on forecasted transactions. Hedge effectiveness is related to
the degree to which the derivative contract and the hedged item are correlated.
It is measured based on the relative changes in fair value between the
derivative contract and the hedged item over time. We exclude the time value of
certain options from our assessment of hedge effectiveness. Any change in the
fair value resulting from ineffectiveness, or the amount by which the derivative
contract and the hedged commodity are not directly correlated, is recognized
immediately in net income. See Note 1 for further discussion on our derivative
instrument accounting policy.
In 2001, we recorded a $15 million after-tax charge in net income and a $72
million after-tax credit in common stock equity (as a component of other
comprehensive income), both as cumulative effects of a change in accounting for
derivatives. The charge primarily resulted from electricity option contracts.
The credit resulted from unrealized gains on cash flow hedges.
129
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance was April 1, 2002. The impact of this
guidance was immaterial to our financial statements.
During 2002, the EITF discussed EITF 02-3 and reached a consensus on
certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25,
2002 for any new contracts, and on January 1, 2003 for existing contracts, with
early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in
the fourth quarter of 2002. We recorded a $66 million after-tax charge in net
income as a cumulative effect adjustment for the previously recorded accumulated
unrealized mark-to-market on energy trading contracts that did not meet the
accounting definition of a derivative. As a result, our energy trading contracts
that are derivatives continue to be accounted for at fair value under SFAS No.
133. Contracts that were previously marked-to-market as trading activities under
EITF 98-10 that do not meet the definition of a derivative are now accounted for
on an accrual basis with the associated revenues and costs recorded at the time
the contracted commodities are delivered or received. Additionally, all gains
and losses (realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.
Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the Consolidated
Balance Sheets. For non-trading derivative instruments that qualify for cash
flow hedge accounting treatment, changes in the fair value of the effective
portion are recognized in common stock equity (as a component of accumulated
other comprehensive income (loss)). Non-trading derivatives, or any portion
thereof, that are not effective hedges are adjusted to fair value through
income. Gains and losses related to non-trading derivatives that qualify as cash
flow hedges of expected transactions are recognized in revenue or purchased
power and fuel expense as an offset to the related item being hedged when the
underlying hedged physical transaction impacts earnings. If it becomes probable
that a forecasted transaction will not occur, we discontinue the use of hedge
accounting and recognize in income the unrealized gains and losses that were
previously recorded in other comprehensive income (loss). In the event a
non-trading derivative is terminated or settled, the unrealized gains and losses
remain in other comprehensive income (loss), and are recognized in income when
the underlying transaction impacts earnings.
Derivatives associated with trading activities are adjusted to fair value
through income. Derivative commodity contracts for the physical delivery of
purchase and sale quantities transacted in the normal course of business are
exempt from the requirements of SFAS No. 133 under the normal purchase and sales
exception and are not reflected on the balance sheet at fair value. Most of our
non-trading electricity purchase and sales agreements qualify as normal
purchases and sales and are exempted from recognition in the financial
statements until the electricity is delivered.
EITF 02-3 requires that derivatives held for trading purposes, whether
settled financially or physically, be reported in the income statement on a net
basis. Conversely, all non-trading contracts and derivatives are to be reported
gross in the income statement. Previous guidance under EITF 98-10 permitted
non-financially settled energy trading contracts to be reported either gross or
net in the income statement. Beginning in the third quarter of 2002, we netted
all of our energy trading activities on the Consolidated Statements of Income
and restated prior year amounts for all periods presented. Reclassification of
such trading activity to a net basis of reporting resulted in reductions in both
revenues and purchased power and fuel costs, but did not have any impact on our
financial condition, results of operations or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our assets and liabilities from risk management and trading activities are
presented in two categories consistent with our business segments:
* System - our regulated electricity business segment, which consists of
non-trading derivative instruments that hedge our purchases and sales
of electricity and fuel for our Native Load requirements; and
* Marketing and Trading - our non-regulated, competitive business
segment, which includes both non-trading and trading derivative
instruments.
The changes in derivative fair value included in the Consolidated
Statements of Income for the years ended December 31, 2002 and 2001 are
comprised of the following (dollars in thousands):
2002 2001
-------- --------
Gains/(losses) on the ineffective portion of
derivatives qualifying for hedge
accounting (a) $ 11,198 $ (6,056)
Losses from the discontinuance of
cash flow hedges (8,820) (4,683)
Losses from non-hedge derivatives (4,324) (7,157)
Prior period mark-to-market losses realized
upon delivery of commodities 8,005 25,948
-------- --------
Total pretax gain $ 6,059 $ 8,052
======== ========
(a) Time value component of options excluded from assessment of hedge
effectiveness.
As of December 31, 2002, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted
transactions is approximately seven years. During the twelve months ending
December 31, 2003, we estimate that a net loss of $26 million before income
taxes will be reclassified from accumulated other comprehensive loss as an
offset to the effect on earnings of market price changes for the related hedged
transactions.
The following table summarizes our assets and liabilities from risk
management and trading activities related to system and marketing and trading at
December 31, 2002 and 2001 (dollars in thousands):
131
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
--------- --------- --------- --------- ---------
Mark-to-
market:
Marketing
and Trading $ 17,640 $ 51,771 $ (9,848) $ (2,583) $ 56,980
System 41,522 6,971 (60,819) (36,678) (49,004)
Emission
allowances
- at cost -- 58,067 -- (14,328) 43,739
Collateral
provided (held) -- 5,527 -- (22,053) (16,526)
--------- --------- --------- --------- ---------
Total $ 59,162 $ 122,336 $ (70,667) $ (75,642) $ 35,189
========= ========= ========= ========= =========
December 31, 2001
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
--------- --------- --------- --------- ---------
Mark-to-
market:
Marketing
and Trading $ 56,876 $ 148,457 $ (14,154) $ (53,253) $ 137,926
System 10,097 -- (21,840) (95,159) (106,902)
Emission
allowances
- at cost -- (3,216) -- (59,164) (62,380)
Collateral
provided -- 55,110 -- -- 55,110
--------- --------- --------- --------- ---------
Total $ 66,973 $ 200,351 $ (35,994) $(207,576) $ 23,754
========= ========= ========= ========= =========
CREDIT RISK
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including two counterparties for which a worst case exposure
represents approximately 33% of our $181 million of risk management and trading
assets as of December 31, 2002. We use a risk management process to assess and
monitor the financial exposure of those and all other counterparties. Despite
the fact that the great majority of trading counterparties are rated as
investment grade by the credit rating agencies, including the counterparties
noted above, there is still a possibility that one or more of these companies
could default, resulting in a material impact on consolidated earnings for a
given period. Counterparties in the portfolio consist principally of major
energy companies, municipalities and local distribution companies. We maintain
credit policies that we believe minimize overall credit risk to within
acceptable limits. Determination of the credit quality of our counterparties is
based upon a number of factors, including credit ratings and our evaluation of
their financial condition. In many contracts, we employ collateral requirements
and standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Credit valuation adjustments
132
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
are established representing our estimated credit losses on our overall exposure
to counterparties. See "Mark-to-Market Accounting" in Note 1 for a discussion of
our credit valuation adjustment policy.
19. OTHER INCOME AND OTHER EXPENSE
The following table provides detail of other income and other expense for
the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):
Year Ended December 31,
------------------------------------
2002 2001 2000
-------- -------- --------
Other income:
Environmental insurance
recovery $ -- $ 12,349 $ --
Equity earnings - net -- -- 6,882
Interest income 4,410 6,763 8,291
SunCor joint venture earnings 7,471 3,687 3,208
Miscellaneous 3,223 3,617 3,451
-------- -------- --------
Total other income $ 15,104 $ 26,416 $ 21,832
======== ======== ========
Other expense:
Equity losses - net (a) $(10,439) $ (5,126) $ --
Non-operating costs - SunCor -- (7,000) --
Non-operating costs (b) (19,430) (16,807) (16,044)
Miscellaneous (3,786) (4,644) (9,285)
-------- -------- --------
Total other expense $(33,655) $(33,577) $(25,329)
======== ======== ========
(a) Primarily related to El Dorado's investment losses in NAC prior to
consolidation in the third quarter of 2002 (see Note 22).
(b) As defined by the FERC, includes below-the-line non-operating utility costs
(primarily community relations and environmental compliance).
20. VARIABLE INTEREST ENTITIES
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 requires that we consolidate a VIE if we have a
majority of the risk of loss from the VIE's activities or we are entitled to
receive a majority of the VIE's residual returns or both. A VIE is a
corporation, partnership, trust or any other legal structure that either does
not have equity investors with voting rights or has equity investors that do not
provide sufficient financial resources for the entity to support its activities.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.
In 1986, APS entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. See Note 9 for
further information about the sale-leaseback transactions. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to
133
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
consolidate the Palo Verde SPEs. However, we continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.
APS is also exposed to losses under the Palo Verde sale-leaseback
agreements upon the occurrence of certain events that APS does not consider to
be reasonably likely to occur. Under certain circumstances (for example, the NRC
issuing specified violation orders with respect to Palo Verde or the occurrence
of specified nuclear events), APS would be required to assume the debt
associated with the transactions, make specified payments to the equity
participants, and take title to the leased Unit 2 interests, which, if
appropriate, may be required to be written down in value. If such an event had
occurred as of December 31, 2002, APS would have been required to assume
approximately $285 million of debt and pay the equity participants approximately
$200 million.
21. INTANGIBLE ASSETS
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." We have no goodwill recorded and have separately disclosed
other intangible assets on our Consolidated Balance Sheets. The intangible
assets continue to be amortized over their finite useful lives. Thus, there was
no impact on our financial position as a result of the adoption of SFAS No. 142.
The Company's gross intangible assets (which are primarily software) were $214
million at December 31, 2002 and $175 million at December 31, 2001. The related
accumulated amortization was $104 million at December 31, 2002 and $88 million
at December 31, 2001. Amortization expense was $21 million in 2002, $22 million
in 2001 and $20 million in 2000. Estimated amortization expense on existing
intangible assets over the next five years is $25 million in 2003, $24 million
in 2004, $23 million in 2005, $21 million in 2006 and $15 million in 2007.
22. EL DORADO'S INVESTMENT IN NAC
Through our unregulated wholly-owned subsidiary, El Dorado, we own a
majority interest in NAC, a company that develops, markets and contracts for the
manufacture of cask designs for spent nuclear fuel storage and transportation.
Prior to the third quarter of 2002, our investment in NAC was accounted for
under the equity method and our share of NAC's earnings and losses was recorded
in other income or expense in our Consolidated Statements of Income. Beginning
in the third quarter of 2002, we fully consolidated NAC's financial statements
after acquiring a controlling interest in NAC as a result of increased voting
representation on NAC's Board of Directors. During the second and third quarters
of 2002, we recorded cumulative losses of approximately $21 million before tax
($13 million after tax, $0.15 per share) related to NAC, primarily as a result
of expected losses under contracts with two customers, including a contract
between NAC and Maine Yankee Atomic Power Company (Maine Yankee).
On January 15, 2003, Maine Yankee notified NAC of its intention to
terminate its contract with NAC. We recorded additional NAC losses of
approximately $38 million before tax ($23 million after tax, or $0.27 per share)
in the fourth quarter of 2002, the substantial majority of which relate to the
termination of the Maine Yankee contract. As a result, in 2002, we recorded NAC
losses of approximately $59 million before tax ($35 million after tax, or $0.42
per share).
134
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NAC LITIGATION On March 4, 2003, Maine Yankee Atomic Power Co. filed suit
against Pinnacle West, NAC and a surety company in federal court in Portland,
Maine. MAINE YANKEE ATOMIC POWER COMPANY V. UNITED STATES FIRE INSURANCE
COMPANY, Civil Action Docket No. 03-58-PC, United States District Court,
District of Maine. The lawsuit alleges that NAC failed to meet its contractual
obligations with respect to certain of NAC's activities relating to the
decommissioning of the Maine Yankee nuclear power plant. The lawsuit was filed a
few weeks after NAC initiated arbitration against Maine Yankee with respect to
matters relating to the same contract. The lawsuit seeks recovery under a
parental guarantee signed by Pinnacle West relating to certain of NAC's
contractual obligations and under performance and payment bonds issued by the
surety which are guaranteed (at least in part) by Pinnacle West. Maine Yankee
also alleges damages in excess of $1 million. We are currently evaluating the
allegations of the lawsuit and expect to vigorously defend our position.
23. GUARANTEES
On January 1, 2003 we adopted FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." FIN No. 45 elaborates on the disclosures to be made by
a guarantor in its financial statements about its obligations under certain
guarantees. It also clarifies that a guarantor is required to recognize, at
inception of a guarantee, a liability for the fair value of the obligation
undertaken in issuing the guarantee. The disclosure provisions are effective for
the year ended December 31, 2002. The initial recognition and measurement
provisions of FIN No. 45 are effective on a prospective basis to guarantees
issued or modified after December 31, 2002.
We have issued parental guarantees and letters of credit and obtained
surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees
related to Pinnacle West Energy consist of equipment and performance guarantees
related to our generation construction program, transmission service guarantees
for West Phoenix Units 4 and 5 and long-term service agreement guarantees for
new power plants. Our credit support instruments enable APS Energy Services to
provide commodity energy and energy-related products and enable El Dorado to
support the activities of NAC. SunCor has a debt guarantee on behalf of an
affiliated joint venture. Non-performance or payment under the original contract
by our unregulated subsidiaries would require us to perform under the guarantee
or surety bond. No liability is currently recorded on the Consolidated Balance
Sheets related to Pinnacle West's guarantees on behalf of its subsidiaries. Our
guarantees have no recourse (except NAC) or collateral provisions to allow us to
recover amounts paid under the guarantee. The amounts and approximate terms of
our guarantees and surety bonds for each subsidiary at December 31, 2002 are as
follows (dollars in millions):
135
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Guarantees Surety Bonds Letters of Credit
------------------- ---------------------- -----------------------
Term Term Term
Amount (in years) Amount (in years) Amount (in years)
------ ---------- ------ ---------- ------ ----------
Parental:
Pinnacle West Energy $126 1 to 2 $ -- -- $ 42 1 to 2
APS Energy Services 82 less than 2 43 less than 1 -- --
El Dorado (all NAC) 43 1 to 3 -- -- -- --
SunCor guarantees 33 1 -- -- -- --
---- ---- ----
Total $284 $ 43 $ 42
==== ==== ====
At December 31, 2002, we had entered into approximately $42 million of
letters of credit which support various construction agreements. These letters
of credit expire in 2003 and 2004. We intend to provide from either existing or
new facilities for the extension, renewal or substitution of the letters of
credit to the extent required.
APS has entered into various agreements that require letters of credit for
financial assurance purposes. At December 31, 2002, approximately $258 million
of letters of credit were outstanding to support existing pollution control
bonds of approximately $253 million. The letters of credit are available to fund
the payment of principal and interest of such debt obligations. These letters of
credit have expiration dates in 2003. APS has also entered into approximately
$115 million of letters of credit to support certain equity lessors in the Palo
Verde sale-leaseback transactions (see Note 9 for further details on the Palo
Verde sale-leaseback transactions). These letters of credit expire in 2005.
Additionally, APS has approximately $5 million of letters of credit related to
counterparty collateral requirements and approximately $5 million of letters of
credit related to workers' compensation expiring in 2003. APS intends to provide
from either existing or new facilities for the extension, renewal or
substitution of the letters of credit to the extent required.
In conjunction with our financing agreements, including our sale-leaseback
transactions, we generally provide indemnifications relating to liabilities
arising from or related to the agreements, except with certain limited
exceptions depending on the particular agreement. APS has also provided
indemnifications to the equity participants and other parties in the Palo Verde
sale-leaseback transactions with respect to certain tax matters. Generally, a
maximum obligation is not explicitly stated in the indemnification and
therefore, the overall maximum amount of the obligation under such
indemnifications cannot be reasonably estimated. Based on historical experience
and evaluation of the specific indemnities, we do not believe that any material
loss related to such indemnifications is likely and therefore no related
liability has been recorded.
136
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
24. SUBSEQUENT EVENTS
See "ACC Applications" in Note 3 for information regarding the ACC's
approval on March 27, 2003 of a $500 million financing arrangement between APS
and Pinnacle West Energy and "Track B Order" in Note 3 for information regarding
the ACC order issued on March 14, 2003, mandating a process by which APS must
competitively procure energy.
See "California Energy Issues and Refunds in the Pacific Northwest" in Note
11 for information regarding the FERC's adoption on March 26, 2003 of an ALJ's
proposed findings, and issuance on March 26, 2003 of a Final Report on Price
Manipulation in Western Markets.
See Note 22 for information related to the March 4, 2003 NAC litigation.
137
PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Column A Column B Column C Column D Column E
Additions
---------------------
Balance at Charged to Charged Balance
beginning cost and to other at end of
Description of period expenses accounts Deductions Period
----------- --------- -------- -------- ---------- ------
(dollars in thousands)
YEAR ENDED DECEMBER 31, 2002
Real Estate Valuation Reserves $ 2,000 $ -- $ -- $ 339(a) $ 1,661
YEAR ENDED DECEMBER 31, 2001
Real Estate Valuation Reserves $ 2,000 $ -- $ -- $ --(a) $ 2,000
YEAR ENDED DECEMBER 31, 2000
Real Estate Valuation Reserves $ 8,000 $ -- $ -- $ 6,000(a) $ 2,000
YEAR ENDED DECEMBER 31, 2002
Reserve for uncollectibles $ 14,334 $ (21) $ -- $ 4,705 $ 9,608
YEAR ENDED DECEMBER 31, 2001
Reserve for uncollectibles $ 7,580 $ 13,394 $ -- $ 6,640 $ 14,334
YEAR ENDED DECEMBER 31, 2000
Reserve for uncollectibles $ 1,538 $ 10,638 $ -- $ 4,596 $ 7,580
YEAR ENDED DECEMBER 31, 2002
Reserve for contract losses $ -- $ 13,000(b) $ -- $ -- $ 13,000
(a) Represents pro-rata allocations for sale of land.
(b) Contract losses related to NAC.
138
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" and to "Section 16(a)
Beneficial Ownership Reporting Compliance" in the Company's Proxy Statement
relating to the Annual Meeting of Shareholders to be held on May 21, 2003 (the
"2003 Proxy Statement") and to the Supplemental Item --- "Executive Officers of
the Registrant" in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to "The Board and its Committees - How are
Directors Compensated?"; "Performance Graph"; and "Executive Compensation" in
the 2003 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Election of Directors - How many shares of
Pinnacle West stock are owned by management and large shareholders?" in the 2003
Proxy Statement.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth information as of December 31, 2002 with
respect to our compensation plans and individual compensation arrangements under
which our equity securities were authorized for issuance to directors, officers,
employees, consultants and certain other persons and entities in exchange for
the provision to us of goods or services.
139
NUMBER OF SECURITIES
REMAINING AVAILABLE FOR
NUMBER OF SECURITIES TO WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER EQUITY
BE ISSUED UPON EXERCISE EXERCISE PRICE OF COMPENSATION PLANS (EXCLUDING
OF OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, SECURITIES REFLECTED IN
PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS COLUMN (a))
(a) (b) (c)
- ---------------------------- ----------------------- -------------------- -----------------------------
Equity compensation plans
approved by security holders 2,185,129 $ 39.96 5,317,145
Equity compensation plans
not approved by security
holders -- $ -- 172,100
---------- ----------
Total 2,185,129 $ 39.96 5,489,245
========== ==========
EQUITY COMPENSATION PLANS APPROVED BY SECURITY HOLDERS
The Company has four equity compensation plans that were approved by its
shareholders: the Pinnacle West Capital Corporation Stock Option and Incentive
Plan, under which no new options may be granted; the Pinnacle West Capital
Corporation Directors Stock Option Plan under which no new options may be
granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan;
and the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan. See
Note 16 for additional information regarding these plans.
EQUITY COMPENSATION PLANS NOT APPROVED BY SECURITY HOLDERS
The Company has one equity compensation plan, the Pinnacle West Capital
Corporation 2000 Director Equity Plan (the "2000 Plan"), for which the approval
of shareholders was not required.
NUMBER OF SHARES SUBJECT TO THE 2000 PLAN. The total number of shares of
the Company's common stock granted under the 2000 Plan may not exceed 200,000.
In the case of a significant corporate event, such as a reorganization, merger
or consolidation, the 2000 Plan provides for adjustment of the above limit, the
number of shares to be awarded automatically to eligible non-employee directors,
the number of shares of the Company's common stock non-employee directors are
required to own to receive an annual grant of common stock and options granted
under the 2000 Plan.
ELIGIBILITY FOR PARTICIPATION. Only non-employee directors may participate
in the 2000 Plan. A non-employee director is an individual who is a director of
the Company but who is not also an employee of the Company or any of its
subsidiaries.
TERMS OF AWARDS. The 2000 Plan provides for: (1) annual grants of common
stock to eligible non-employee directors, (2) discretionary grants of common
stock to eligible non-employee directors and (3) grants of nonqualified stock
options to eligible non-employee directors.
140
ANNUAL GRANTS OF STOCK
Each individual who is a non-employee director as of July 1 of a calendar
year, and who meets requirements of ownership of the Company's common stock set
forth below, will receive 900 shares of the Company's common stock for such
calendar year. In the first calendar year in which a non-employee director is
eligible to participate in the 2000 Plan, he or she must own at least 900 shares
of the Company's common stock as of December 31 of the same calendar year to
receive a grant of 900 shares of the Company's common stock. If the non-employee
director owns 900 shares of common stock as of June 30, he or she will receive a
grant of 900 shares of common stock as of July 1 of the same calendar year. If
the non-employee director does not own 900 shares of the Company's common stock
as of June 30, but acquires the necessary shares on or before December 31 of the
same year, he or she will receive a grant of 900 shares of common stock within a
reasonable time after the Company verifies that the requisite number of shares
has been acquired. In each subsequent year, the number of shares of the
Company's common stock the non-employee director must own to receive a grant of
900 shares of common stock will increase by 900 shares, until reaching a maximum
of 4,500 shares. In each of the subsequent years, the non-employee director must
own the requisite number of shares of the Company's common stock as of June 30
of the relevant calendar year.
DISCRETIONARY GRANTS OF STOCK
The Human Resources Committee of the Board of Directors, excluding those
members who are not "Non-Employee Directors" under SEC Rule 16b-3(b)(3) (the
Committee) administers the 2000 Plan and may grant shares of the Company's
common stock to non-employee directors in its discretion. No discretionary
grants of common stock have been made under the 2000 Plan.
GRANTS OF NONQUALIFIED STOCK OPTIONS
The Committee can grant nonqualified stock options under the 2000 Plan. The
terms and the conditions of the option grant, including the exercise price per
share, which may not be less than fair market value on the date of grant, will
be set by the Committee in a written award agreement. The Committee will
determine the time or times at which any such options may be exercised in whole
or in part. The Committee will also determine the performance or other
conditions, if any, that must be satisfied before all or part of an option may
be exercised. Any such options granted to a participant will expire on the tenth
anniversary date of the date of grant, unless the option is earlier terminated,
forfeited or surrendered pursuant to a provision of the 2000 Plan or the
applicable award agreement. Notwithstanding the foregoing, if a participant
ceases to be a Company director for any reason, including death or disability,
any such options held by that participant will expire on the second anniversary
of the date on which the participant ceased to be a Company director, unless
otherwise provided in the applicable award agreement. Unless the Committee
provides otherwise, no such options may be sold, transferred, pledged, assigned
or otherwise alienated, other than by will, the laws of descent and
distribution, or under any other circumstances allowed by the Committee. No
options have been granted under the 2000 Plan.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to "Executive Compensation - Human Resources
Committee Interlocks and Insider Participation" and "- Employment and Severance
Arrangements" in the 2003 Proxy Statement.
141
ITEM 14. CONTROLS AND PROCEDURES
As of a date within 90 days of the date of this report (the "Evaluation
Date"), we carried out an evaluation, under the supervision and with the
participation of our management, including our Chief Executive Officer and our
Chief Financial Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures, as defined in Rules 13a-14 and 15d-14 under
the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based upon
this evaluation, our Chief Executive Officer and our Chief Financial Officer,
concluded that, as of the Evaluation Date, our disclosure controls and
procedures were adequate to ensure that information required to be disclosed by
us in the reports filed or submitted by us under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms.
There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
the evaluation, including any corrective actions with regard to significant
deficiencies and internal weaknesses.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See the Index to Consolidated Financial Statements and Financial Statement
Schedule in Part II, Item 8.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION
- ----------- -----------
4.1 -- Fifty-sixth Supplemental Indenture to the Mortgage dated as of
March 1, 2003
4.2 -- Fifty-seventh Supplemental Indenture to the Mortgage dated as of
April 1, 2003
10.1(a) -- 2003 Officer Variable Incentive Plan
10.2(a) -- 2003 CEO Variable Incentive Plan
10.3(a) -- Schedules of William J. Post and Jack E. Davis to Arizona Public
Service Company Deferred Compensation Plan, as amended
10.4(a) -- Letter Agreement dated June 28, 2001 between Pinnacle West
Capital Corporation and Steve Wheeler
10.5(a) -- Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
12.1 -- Ratio of Earnings to Fixed Charges
21.1 -- Subsidiaries of the Company
23.1 -- Consent of Deloitte & Touche LLP
142
99.1 -- Certification of William J. Post, the Company's principal
executive officer, pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
99.2 -- Certification of Donald E. Brandt, the Company's principal
financial officer, pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
99.3 -- Risk Factors
In addition to those Exhibits shown above, the Company hereby incorporates
the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation
ss.229.10(d) by reference to the filings set forth below:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
3.1 Articles of Incorporation, 19.1 to the Company's September 1-8962 11-14-88
restated as of July 29, 1988 1988 Form 10-Q Report
3.2 Bylaws, amended as of 3.2 to September 2002 Form 10-Q 1-8962 11-14-02
September 18, 2002 Report
4.3 Mortgage and Deed of Trust 4.1 to APS' September 1992 Form 1-4473 11-9-92
Relating to APS' First 10-Q Report
Mortgage Bonds, together with
forty-eight indentures
supplemental thereto
4.4 Forty-ninth Supplemental 4.1 to APS' 1992 Form 10-K Report 1-4473 3-30-93
Indenture
4.5 Fiftieth Supplemental 4.2 to APS' 1993 Form 10-K Report 1-4473 3-30-94
Indenture
4.6 Fifty-first Supplemental 4.1 to APS' August 1, 1993 Form 1-4473 9-27-93
Indenture 8-K Report
4.7 Fifty-second Supplemental 4.1 to APS' September 30, 1993 1-4473 11-15-93
Indenture Form 10-Q Report
143
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
4.8 Fifty-third Supplemental 4.5 to APS' Registration 1-4473 3-1-94
Indenture Statement No. 33-61228 by means
of February 23, 1994 Form 8-K
Report
4.9 Fifty-fourth Supplemental 4.1 to APS' Registration 1-4473 11-22-96
Indenture Statements Nos. 33-61228,
33-55473, 33-64455 and 333-15379
by means of November 19, 1996
Form 8-K Report
4.10 Fifty-fifth Supplemental 4.8 to APS' Registration 1-4473 4-9-97
Indenture Statement Nos. 33-55473, 33-64455
and 333-15379 by means of April
7, 1997 Form 8-K Report
4.11 Agreement, dated March 21, 4.1 to APS' 1993 Form 10-K Report 1-4473 3-30-94
1994, relating to the filing
of instruments defining the
rights of holders of APS
long-term debt not in excess
of 10% of APS' total assets
4.12 Indenture dated as of January 4.6 to APS' Registration 1-4473 1-11-95
1, 1995 among APS and The Statement Nos. 33-61228 and
Bank of New York, as Trustee 33-55473 by means of January 1,
1995 Form 8-K Report
4.13 First Supplemental Indenture 4.4 to APS' Registration 1-4473 1-11-95
dated as of January 1, 1995 Statement Nos. 33-61228 and
33-55473 by means of January 1,
1995 Form 8-K Report
4.14 Indenture dated as of 4.5 to APS' Registration 1-4473 11-22-96
November 15, 1996 among APS Statements Nos. 33-61228,
and The Bank of New York, as 33-55473, 33-64455 and 333- 15379
Trustee by means of November 19, 1996
Form 8-K Report
144
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
4.15 First Supplemental Indenture 4.6 to APS' Registration 1-4473 11-22-96
Statements Nos. 33-61228,
33-55473, 33-64455 and 333-15379
by means of November 19, 1996
Form 8-K Report
4.16 Second Supplemental Indenture 4.10 to APS' Registration 1-4473 4-9-97
Statement Nos. 33-55473, 33-64455
and 333-15379 by means of April
7, 1997 Form 8-K Report
4.17 Indenture dated as of 4.1 to the Company's Registration 1-8962 1-25-01
December 1, 2000 between the Statement No. 333-53150
Company and The Bank of New
York, as Trustee, relating to
Senior Debt Securities
4.18 First Supplemental Indenture 4.2 to the Company's Registration 1-8962 3-26-01
dated as of March 15, 2001 Statement No. 333-52476
4.19 Indenture dated as of 4.2 to the Company's Registration 1-8962 1-25-01
December 1, 2000 between the Statement No. 333-53150
Company and The Bank of New
York, as Trustee, relating to
subordinated Debt Securities
4.20 Specimen Certificate of 4.2 to the Company's 1988 Form 1-8962 3-31-89
Pinnacle West Capital 10-K Report
Corporation Common Stock, no
par value
4.21 Agreement, dated March 29, 4.1 to the Company's 1987 Form 1-8962 3-30-88
1988, relating to the filing 10-K Report
of instruments defining the
rights of holders of
long-term debt not in excess
of 10% of the Company's
total assets
145
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
4.22 Indenture dated as of January 4.10 to APS' Registration The 1-4473 1-16-98
15, 1998 among APS and Chase Statement Nos. 333-15379 and
Manhattan Bank, as Trustee 333-27551 by means of January 13,
1998 Form 8-K Report
4.23 First Supplemental Indenture 4.3 to APS' Registration 1-4473 1-16-98
dated as of January 15, 1998 Statement Nos. 333-15379 and
333-27551 by means of January 13,
1998 Form 8-K Report
4.24 Second Supplemental Indenture 4.3 to APS' Registration 1-4473 2-22-99
dated as of February 15, 1999 Statement Nos. 333-27551 and
333-58445 by means of February
18, 1999 Form 8-K Report
4.25 Third Supplemental Indenture 4.5 to APS' Registration 1-4473 11-5-99
dated as of November 1, 1999 Statement Nos. 333-58445 by means
of November 2, 1999 Form 8-K
Report
4.26 Fourth Supplemental Indenture 4.1 to Registration Statement No. 1-4473 8-4-00
dated as of August 1, 2000 333-58445 and 333-94277 by means
of August 2, 2000 Form 8-K Report
4.27 Fifth Supplemental Indenture 4.1 to APS' September 2001 Form 1-4473 11-6-01
dated as of October 1, 2001 10-Q
4.28 Sixth Supplemental Indenture 4.1 to APS' Registration 1-4473 2-28-01
dated as of March 1, 2002 Statement Nos. 333-63994 and
333-83398 by means of February
26, 2002 Form 8-K Report
146
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
4.29 Amended and Restated Rights 4.1 to the Company's March 22, 1-8962 4-19-99
Agreement, dated as of March 1999 Form 8-K Report
26, 1999, between Pinnacle
West Capital Corporation and
BankBoston, N.A., as Rights
Agent, including (i) as
Exhibit A thereto the form of
Amended Certificate of
Designation of Series A
Participating Preferred Stock
of Pinnacle West Capital
Corporation, (ii) as Exhibit
B thereto the form of Rights
Certificate and (iii) as
Exhibit C thereto the Summary
of Right to Purchase
Preferred Shares
4.30 Amendment to Rights 4.1 to March 2002 Form 10-Q Report 1-8962 5-15-02
Agreement, effective as of
January 1, 2002
10.6 Two separate Decommissioning 10.2 to APS' September 1991 Form 1-4473 11-14-91
Trust Agreements (relating 10-Q Report
to PVNGS Units 1 and 3,
respectively), each dated
July 1, 1991, between APS and
Mellon Bank, N.A., as
Decommissioning Trustee
10.7 Amendment No. 1 to 10.1 to APS' 1994 Form 10- K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 1),
dated as of December 1, 1994
147
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.8 Amendment No. 1 to 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 3),
dated as of December 1, 1994
10.9 Amendment No. 2 to APS 10.4 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 1)
dated as of July 1, 1991
10.10 Amendment No. 2 to APS 10.6 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 3)
dated as of July 1, 1991
10.11 Amended and Restated 10.1 to the Company's 1991 Form 1-8962 3-26-92
Decommissioning Trust 10-K Report
Agreement (PVNGS Unit 2)
dated as of January 31,
1992, among APS, Mellon
Bank, N.A., as
Decommissioning Trustee, and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
under two separate Trust
Agreements, each with a
separate Equity Participant,
and as Lessor under two
separate Facility Leases,
each relating to an undivided
interest in PVNGS Unit 2
148
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.12 First Amendment to Amended 10.2 to APS' 1992 Form 10-K 1-4473 3-30-93
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2), dated as of November 1,
1992
10.13 Amendment No. 2 to Amended 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2), dated as of November 1,
1994
10.14 Amendment No. 3 to Amended 10.1 to APS' June 1996 Form 10-Q 1-4473 8-9-96
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2), dated as of November 1,
1994
10.15 Amendment No. 4 to Amended APS 10.5 to APS' 1996 Form 10-K 1-4473 3-28-97
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2) dated as of January 31,
1992
10.16 Amendment No. 5 to the 10.1 to Pinnacle West's March 1-8962 5-15-02
Amended and Restated 2002 Form 10-Q Report
Decommissioning Trust
Agreement (PVNGS Unit 2),
dated as of June 30, 2000
10.17 Amendment No. 3 to the 10.2 to Pinnacle West's March 1-8962 5-15-02
Decommissioning Trust 2002 Form 10-Q Report
Agreement (PVNGS Unit 1),
dated as of March 18, 2002
149
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.18 Amendment No. 6 to the 10.3 to Pinnacle West's March 1-8962 5-15-02
Amended and Restated 2002 Form 10-Q Report
Decommissioning Trust
Agreement (PVNGS Unit 2),
dated as of March 18, 2002
10.19 Amendment No. 3 to the 10.4 to Pinnacle West's March 1-8962 5-15-02
Decommissioning Trust 2002 Form 10-Q Report
Agreement (PVNGS Unit 3),
dated as of March 18, 2002
10.20 Asset Purchase and Power 10.1 to APS' June 1991 Form 10-Q 1-4473 8-8-91
Exchange Agreement dated Report
September 21, 1990 between
APS and PacifiCorp, as
amended as of October 11,
1990 and as of July 18, 1991
10.21 Long-Term Power Transaction 10.2 to APS' June 1991 Form 10-Q 1-4473 8-8-91
Agreement dated September 21, Report
1990 between APS and
PacifiCorp, as amended as of
October 11, 1990, and as of
July 8, 1991
10.22 Amendment No. 1 dated April 10.3 to APS' 1995 Form 10-K 1-4473 3-29-96
5, 1995 to the Long-Term Report
Power Transaction Agreement
and Asset Purchase and Power
Exchange Agreement between
PacifiCorp and APS
10.23 Restated Transmission 10.4 to APS' 1995 Form 10-K 1-4473 3-29-96
Agreement between PacifiCorp Report
and APS dated April 5, 1995
150
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.24 Contract among PacifiCorp, 10.5 to APS' 1995 Form 10-K 1-4473 3-29-96
APS and United States Report
Department of Energy Western
Area Power Administration,
Salt Lake Area Integrated
Projects for Firm
Transmission Service dated
May 5, 1995
10.25 Reciprocal Transmission 10.6 to APS' 1995 Form 10-K 1-4473 3-29-96
Service Agreement between APS Report
and PacifiCorp dated as of
March 2, 1994
10.26 Contract, dated July 21, 10.31 to the Company's Form S-14 2-96386 3-13-85
1984, with DOE providing for Registration Statement
the disposal of nuclear fuel
and/or high-level
radioactive waste, ANPP
10.27 Indenture of Lease with 5.01 to APS' Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Four Registration Statement
Corners Plant
10.28 Supplemental and Additional 5.02 to APS' Form S-7 2-59644 9-1-77
Indenture of Lease, including Registration Statement
amendments and supplements
to original lease with
Navajo Tribe of Indians,
Four Corners Plant
10.29 Amendment and Supplement No. 10.36 to the Company's 1-8962 7-25-85
1 to Supplemental and Registration Statement on Form
Additional Indenture of Lease 8-B Report
Four Corners, dated April
25, 1985
151
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.30 Application and Grant of 5.04 to APS' Form S-7 2-59644 9-1-77
multi-party rights-of-way and Registration Statement
easements, Four Corners Plant
Site
10.31 Application and Amendment No. 10.37 to the Company's 1-8962 7-25-85
1 to Grant of multi-party Registration Statement on Form
rights-of-way and easements, 8-B
Four Corners Power Plant
Site dated April 25, 1985
10.32 Application and Grant of 5.05 to APS' Form S-7 2-59644 9-1-77
Arizona Public Service Registration Statement
Company rights-of-way and
easements, Four Corners Plant
Site
10.33 Four Corners Project 10.7 to the Company's 2000 Form 1-8962 3-14-01
Co-Tenancy Agreement 10-K Report
Amendment No. 6
10.34 Application and Amendment No. 10.38 to the Company's 1-8962 7-25-85
1 to Grant of Arizona Public Registration Statement on Form
Service Company 8-B
rights-of-way and easements,
Four Corners Power Plant
Site dated April 25, 1985
10.35 Indenture of Lease, Navajo 5(g) to APS' Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.36 Application of Grant of 5(h) to APS Form S-7 Registration 2-36505 3-23-70
rights-of-way and easements, Statement
Navajo Plant
10.37 Water Service Contract 5(l) to APS' Form S-7 2-394442 3-16-71
Assignment with the United Registration Statement
States Department of
Interior, Bureau of
Reclamation, Navajo Plant
152
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.38 Arizona Nuclear Power Project 10.1 to APS' 1988 Form 10-K 1-4473 3-8-89
Participation Agreement,
dated August 23, 1973, among
APS Salt River Project
Agricultural Improvement and
Power District, Southern
California Edison Company,
Public Service Company of
New Mexico, El Paso
Electric Company, Southern
California Public Power
Authority, and Department of
Water and Power of the City
of Los Angeles, and
amendments 1-12 thereto
10.39 Amendment No. 13, dated as 10.1 to APS' March 1991 Form 10-Q 1-4473 5-15-91
of April 22, 1991, to Arizona
Nuclear Power Project
Participation Agreement,
dated August 23, 1973, among
APS, Salt River Project
Agricultural Improvement and
Power District, Southern
California Edison Company,
Public Service Company of New
Mexico, El Paso Electric
Company, Southern California
Public Power Authority, and
Department of Water and Power
of the City of Los Angeles
153
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.40 Amendment No. 14 to Arizona 99.1 to the Company's June 2000 1-8962 8-14-00
Nuclear Power Project Form 10-Q Report
Participation Agreement,
dated August 23, 1973, among
APS, Salt River Project
Agricultural Improvement and
Power District, Southern
California Edison Company,
Public Service Company of New
Mexico, El Paso Electric
Company, Southern California
Public Power Authority, and
Department of Water and Power
of the City of Los Angeles
10.41(c) Facility Lease, dated as of 4.3 to APS' Form S-3 Registration 33-9480 10-24-86
August 1, 1986, between State Statement
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and APS, as Lessee
10.42(c) Amendment No. 1, dated as of 10.5 to APS' September 1986 Form 1-4473 12-4-86
November 1, 1986, to Facility 10-Q Report by means of
Lease, dated as of August 1, Amendment No. on December 3,
1986, between State Street 1986 Form 8
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its capacity as Owner
Trustee, as Lessor, and APS,
as Lessee
154
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.43(c) Amendment No. 2 dated as of 10.3 to APS' 1988 Form 10-K 1-4473 3-8-89
June 1, 1987 to Facility Report
Lease dated as of August 1,
1986 between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and APS, as Lessee
10.44(c) Amendment No. 3, dated as of 10.3 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and APS, as Lessee
10.45 Facility Lease, dated as of 10.1 to APS' November 18 1986 1-4473 1-20-87
December 15, 1986, between Form 8-K Report
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and APS, as Lessee
10.46 Amendment No. 1, dated as of 4.13 to APS' Form S-3 1-4473 8-24-87
August 1, 1987, to Facility Registration Statement No.
Lease, dated as of December 33-9480 by means of August 1,
15, 1986, between State 1987 Form 8-K Report
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Lessor, and APS,
as Lessee
155
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.47 Amendment No. 2, dated as of 10.4 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Lessor, and APS,
as Lessee
10.48(a) Pinnacle West Capital 10.13 to the Company's 1999 Form 1-8962 3-30-00
Corporation Supplemental 10-K Report
Excess Benefit Retirement
Plan, as amended and
restated, dated December 7,
1999
10.49(a) First Amendment to the 10.4 to Pinnacle West's 2001 Form 1-8962 3-27-02
Pinnacle West Capital 10-K Report
Corporation Supplemental
Excess Benefit Retirement Plan
10.50(a) Second Amendment to the 10.5 to Pinnacle West's 2001 Form 1-8962 3-27-02
Pinnacle West Capital 10-K Report
Corporation Supplemental
Excess Benefit Retirement Plan
10.51(a) Trust for the Pinnacle West 10.14 to the Company's 1999 Form 1-8962 3-30-00
Capital Corporation, Arizona 10-K Report
Public Service Company and
SunCor Development Company
Deferred Compensation Plans
dated August 1, 1996
156
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.52(a) First Amendment dated 10.15 to the Company's 1999 Form 1-8962 3-30-00
December 7, 1999 to the Trust 10-K Report
for the Pinnacle West Capital
Corporation, Arizona Public
Service Company and SunCor
Development Company Deferred
Compensation Plans
10.53(a) Directors' Deferred 10.1 to APS' June 1986 Form 10-Q 1-4473 8-13-86
Compensation Plan, as Report
restated, effective January
1, 1986
10.54(a) Second Amendment to the 10.2 to APS' 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred Compensation
Plan, effective as of
January 1, 1993
10.55(a) Third Amendment to the 10.1 to APS' September 1994 Form 1-4473 11-10-94
Arizona Public Service 10-Q
Company Directors' Deferred
Compensation Plan, effective
as of May 1, 1993
10.56(a) Fourth Amendment dated 10.8 to the Company's 1999 Form 1-8962 3-30-00
December 28, 1999 to the 10-K Report
Arizona Public Service
Company Directors Deferred
Compensation Plan
10.57(a) Arizona Public Service 10.4 to APS' 1988 Form 10-K 1-4473 3-8-89
Company Deferred Compensation Report
Plan, as restated, effective
January 1, 1984, and the
second and third amendments
thereto, dated December 22,
1986, and December 23, 1987
respectively
157
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.58(a) Third Amendment to the 10.3 to APS' 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.59(a) Fourth Amendment to the 10.2 to APS' September 1994 Form 1-4473 11-10-94
Arizona Public Service 10-Q Report
Company Deferred Compensation
Plan effective as of May 1,
1993
10.60(a) Fifth Amendment to the 10.3 to APS' 1996 Form 10-K 1-4473 3-28-97
Arizona Public Service Report
Company Deferred
Compensation Plan
10.61(a) Sixth Amendment to Arizona 10.8 to the Company's 2000 Form 1-8962 3-14-01
Public Service Company 10-K Report
Deferred Compensation Plan
10.62(a) First Amendment effective as 10.7 to the Company's 1999 Form 1-8962 3-30-00
of January 1, 1999, to the 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and El
Dorado Investment Company
Deferred Compensation Plan
158
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.63(a) Second Amendment effective 10.10 to the Company's 1999 Form 1-8962 3-30-00
January 1, 2000 to the 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and El
Dorado Investment Company
Deferred Compensation Plan
10.64(a) Pinnacle West Capital 10.10 to APS' 1995 Form 10-K 1-4473 3-29-96
Corporation, Arizona Public Report
Service Company, SunCor
Development Company and El
Dorado Investment Company
Deferred Compensation Plan as
amended and restated
effective January 1, 1996
10.65(a) Pinnacle West Capital 10.7 to APS' 1994 Form 10-K 1-4473 3-30-95
Corporation and Arizona Report
Public Service Company
Directors' Retirement Plan,
effective as of January 1,
1995
10.66(a) Letter Agreement dated July 10.16 to the Company's 1999 Form 1-8962 3-30-00
28, 1995 between Arizona 10-K Report
Public Service Company and
Armando B. Flores
10.67(a) Letter Agreement dated as of 10.8 to APS' 1995 Form 10-K 1-4473 3-29-96
January 1, 1996 between APS Report
and Robert G. Matlock &
Associates, Inc. for
consulting services
159
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.68(a) Letter Agreement dated 10.7 to APS' 1994 Form 10-K Report 1-4473 3-30-96
December 21, 1993, between
APS and William L. Stewart
10.69(a) Letter Agreement dated 10.8 to APS' 1996 Form 10-K 1-4473 3-28-97
August 16, 1996 between APS Report
and William L. Stewart
10.70(a) Letter Agreement between APS 10.2 to APS' September 1997 Form 1-4473 11-12-97
and William L. Stewart 10-Q Report
10.71(a) Letter Agreement dated 10.9 to 1999 Form 10-K Report 1-8962 3-30-00
December 13, 1999 between APS
and William L. Stewart
10.72(a) Amendment to Letter 10.1 to June 2002 Form 1-8962 8-13-02
Agreement, effective as of 10-Q Report
January 1, 2002, between APS
and William L. Stewart
10.73(a) Letter Agreement dated 10.17 to the Company's 1999 Form 1-8962 3-30-00
October 3, 1997 between 10-K Report
Arizona Public Service
Company and James M. Levine
10.74(a) Summary of James M. 10.2 to March 2002 Form 10-Q 1-8962 5-15-02
Levine Retirement Benefits Report
10.75(a) Employment Agreement, 10.1 to November 2002 Form 10-Q 1-8962 11-14-02
effective as of October 1, Report
2002, between APS and James
M. Levine
160
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.76(ad) Key Executive Employment and 10.1 to June 1999 Form 1-8962 8-16-99
Severance Agreement between 10-Q Report
Pinnacle West and certain
executive officers of
Pinnacle West and its
subsidiaries
10.77(a) Pinnacle West Capital 10.1 to APS' 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option and Report
Incentive Plan
10.78(a) First Amendment dated 10.11 to the Company's 1999 Form 1-8962 3-30-00
December 7, 1999 to the 10-K Report
Pinnacle West Capital
Corporation Stock Option and
Incentive Plan
10.79(a) Pinnacle West Capital A to the Proxy Statement for the 1-8962 4-16-94
Corporation 1994 Long- Term Plan Report for the Company's
Incentive Plan, effective as 1994 Annual Meeting of
of March 23, 1994 Shareholders
10.80(a) First Amendment dated 10.12 to the Company's 1999 Form 1-8962 3-30-00
December 7, 1999 to the 10-K Report
Pinnacle West Capital
Corporation 1994 Long-Term
Incentive Plan
10.81(a) Pinnacle West Capital B to the Proxy Statement for the 1-8962 4-16-94
Corporation Director Equity Plan Report for the Company's
Participation Plan 1994 Annual Meeting of
Shareholders
10.82(a) Pinnacle West Capital 99.1 to the Company's 1-8962 7-3-00
Corporation 2000 Director Registration Statement on Form
Equity Plan S-8 (No. 333-40796)
10.83(a) Pinnacle West Capital 99.2 to the Company's 1-8962 7-3-00
Corporation and Arizona Registration Statement on Form
Public Service Company S-8 (No. 333-40796)
Directors' Retirement Plan,
as amended and restated on
June 21, 2000
161
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.84 Agreement No. 13904 (Option 10.3 to APS' 1991 Form 10-K 1-4473 3-19-92
and Purchase of Effluent) Report
with Cities of Phoenix,
Glendale, Mesa, Scottsdale,
Tempe, Town of Youngtown, and
Salt River Project
Agricultural Improvement and
Power District, dated April
23, 1973
10.85 Agreement for the Sale and 10.4 to APS' 1991 Form 10-K 1-4473 3-19-92
purchase of Wastewater Report
Effluent with City of
Tolleson and Salt River
Agricultural Improvement and
Power District, dated June
12, 1981, including Amendment
No. 1 dated as of November
12, 1981 and Amendment No. 2
dated as of June 4, 1986
10.86(a) APS Director Equity Plan 10.1 to September 1997 Form 10-Q 1-4473 11-12-97
Report
10.87 Territorial Agreement between 10.1 to APS' March 1998 Form 10-Q 1-4473 5-15-98
the Company and Salt River Report
Project
10.88 Power Coordination Agreement 10.2 to APS' March 1998 Form 10-Q 1-4473 5-15-98
between the Company and Salt Report
River Project
10.89 Memorandum of Agreement 10.3 to APS' March 1998 Form 10-Q 1-4473 5-15-98
between the Company and Salt Report
River Project
162
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.90 Addendum to Memorandum of 10.2 to APS' May 19, 1998 Form 1-4473 6-26-98
Agreement between APS and 8-K Report
Salt River Project dated as
of May 19, 1998
99.4 Collateral Trust Indenture 4.2 to APS' 1992 Form 10 K Report 1-4473 3-30-93
among PVNGS II Funding
Corp., Inc., APS and
Chemical Bank, as Trustee
99.5 Supplemental Indenture to 4.3 to APS' 1992 Form 10 K Report 1-4473 3-30-93
Collateral Trust Indenture
among PVNGS II Funding
Corp., Inc., APS and
Chemical Bank, as Trustee
163
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.6(c) Participation Agreement, 28.1 to APS' September 1992 Form 1-4473 11-9-92
dated as of August 1, 1986, 10-Q Report
among PVNGS Funding Corp.,
Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and
as Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Equity
Participant named therein
99.7(c) Amendment No. 1 dated as of 10.8 to APS' September 1986 Form 1-4473 12-4-86
November 1, 1986, to 10-Q Report by means of
Participation Agreement, Amendment No. 1, on December 3,
dated as of August 1, 1986, 1986 Form 8
among PVNGS Funding Corp.,
Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and
as Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Equity
Participant named therein
164
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.8(c) Amendment No. 2, dated as of 28.4 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of August 1, 1986,
among PVNGS Funding Corp.,
Inc., PVNGS II Funding Corp.,
Inc., State Street Bank and
Trust Company, as successor
to The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and
as Indenture Trustee, APS,
and the Equity Participant
named therein
99.9(c) Trust Indenture, Mortgage, 4.5 to APS' Form S-3 Registration 33-9480 10-24-86
Security Agreement and Statement
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank and
Trust Company, as successor
to The First National Bank
of Boston, as Owner Trustee,
and Chemical Bank, as
Indenture Trustee
165
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.10(c) Supplemental Indenture No. 1, 10.6 to APS' September 1986 Form 1-4473 12-4-86
dated as of November 1, 1986 10-Q Report by means of
to Trust Indenture, Mortgage, Amendment No. 1 on December 3,
Security Agreement and 1986 Form 8
Assignment of Facility
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.11(c) Supplemental Indenture No. 2 28.14 to APS' 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture, Mortgage, Report
Security Agreement and
Assignment of Facility
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Lease Indenture
Trustee
99.12(c) Assignment, Assumption and 28.3 to APS' Form S-3 33-9480 10-24-86
Further Agreement, dated as Registration Statement
of August 1, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
166
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.13(c) Amendment No. 1, dated as of 10.10 to APS' September 1986 Form 1-4473 12-4-86
November 1, 1986, to 10-Q Report by means of
Assignment, Assumption and Amendment No. l on December 3,
Further Agreement, dated as 1986 Form 8
of August 1, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.14(c) Amendment No. 2, dated as of 28.6 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.15 Participation Agreement, 28.2 to APS' September 1992 Form 1-4473 11-9-92
dated as of December 15, 10-Q Report
1986, among PVNGS Funding
Report Corp., Inc., State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and
as Indenture Trustee under a
Trust Indenture, APS, and the
Owner Participant named
therein
167
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.16 Amendment No. 1, dated as of 28.20 to APS' Form S-3 1-4473 8-10-87
August 1, 1987, to Registration Statement No.
Participation Agreement, 33-9480 by means of a November
dated as of December 15, 6, 1986 Form 8-K Report
1986, among PVNGS Funding
Corp., Inc. as Funding
Corporation, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, Chemical
Bank, as Indenture Trustee,
APS, and the Owner
Participant named therein
99.17 Amendment No. 2, dated as of 28.5 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS Funding
Corp., Inc., PVNGS II Funding
Corp., Inc., State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and
as Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Owner
Participant named therein
168
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.18 Trust Indenture, Mortgage 10.2 to APS' November 18, 1986 1-4473 1-20-87
Security Agreement and Form 10-K Report
Assignment of Facility
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee, and
Chemical Bank, as Indenture
Trustee
99.19 Supplemental Indenture No. 1, 4.13 to APS' Form S-3 1-4473 8-24-87
dated as of August 1, 1987, Registration Statement No.
to Trust Indenture, Mortgage, 33-9480 by means of August 1,
Security Agreement and 1987 Form 8-K Report
Assignment of Facility
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee, and
Chemical Bank, as Indenture
Trustee
169
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.20 Supplemental Indenture No. 2 4.5 to APS' 1992 Form 10-K Report 1-4473 3-30-93
to Trust Indenture Mortgage,
Security Agreement and
Assignment of Facility
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee, and
Chemical Bank, as Lease
Indenture Trustee
99.21 Assignment, Assumption and 10.5 to APS' November 18, 1986 1-4473 1-20-87
Further Agreement, dated as Form 8-K Report
of December 15, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.22 Amendment No. 1, dated as of 28.7 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of December 15, 1986,
between APS and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.23(c) Indemnity Agreement dated as 28.3 to APS' 1992 Form 10-K Report 1-4473 3-30-93
of March 17, 1993 by APS
170
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.24 Extension Letter, dated as of 28.20 to APS' Form S-3 1-4473 8-10-87
August 13, 1987, from the Registration Statement No.
signatories of the 33-9480 by means of a November
Participation Agreement to 6, 1986 Form 8-K Report
Chemical Bank
99.25 Rate Reduction Agreement 10.1 to APS' December 4, 1995 1-4473 12-14-95
dated December 4, 1995 8-K Report
between APS and the ACC Staff
99.26 ACC Order dated April 24, 1996 10.1 to APS' March 1996 Form 10-Q 1-4473 5-14-96
Report
99.27 Arizona Corporation 99.1 to APS' 1996 Form 10-K 1-4473 3-28-97
Commission Order, Decision Report
No. 59943, dated December 26,
1996, including the Rules
regarding the introduction of
retail competition in Arizona
99.28 Retail Electric Competition 10.1 to APS' June 1998 Form 10-Q 1-4473 8-14-98
Rules Report
99.29 Arizona Corporation 10.1 to APS' September 1999 10-Q 1-4473 11-15-99
Commission Order, Decision Report
No. 61973, dated October 6,
1999, approving APS'
Settlement Agreement
99.30 Addendum to Settlement 10.1 to the Company's September 1-8962 11-14-00
Agreement 2000 Form 10-Q Report
99.31 Arizona Corporation 10.2 to APS' September 1999 10-Q 1-4473 11-15-99
Commission Order, Decision Report
No. 61969, dated September
29, 1999, including the
Retail Electric Competition
Rules
171
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.32 Track 'A' Appeals Issues - 99.1 to the Company's November 1-8962 12-16-02
Principles for Resolution 15, 2002 Form 8-K
99.33 ACC Opinion and Order dated 99.1 to the Company's September 1-8962 9-17-02
September 10, 2002, Decision 10, 2002 Form 8-K Report
No. 65154 (Track A Order)
99.34 Arizona Public Service 99.2 to the Company's September 1-8962 9-17-02
Company Application filed 10, 2002 Form 8-K Report
with the Arizona Corporation
Commission on September 16,
2002
- ----------
(a) Management contract or compensatory plan or arrangement to be filed as an
exhibit pursuant to Item 14(c) of Form 10-K.
(b) Reports filed under File No. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
(c) An additional document, substantially identical in all material respects to
this Exhibit, has been entered into, relating to an additional Equity
Participant. Although such additional document may differ in other respects
(such as dollar amounts, percentages, tax indemnity matters, and dates of
execution), there are no material details in which such document differs
from this Exhibit.
(d) Additional agreements, substantially identical in all material respects to
this Exhibit have been entered into with additional persons. Although such
additional documents may differ in other respects (such as dollar amounts
and dates of execution), there are no material details in which such
agreements differ from this Exhibit.
REPORTS ON FORM 8-K
During the quarter ended December 31, 2002, and the period ended March 31,
2003, the Company filed the following Reports on Form 8-K:
Report dated September 30, 2002 containing exhibits comprised of financial
information and earnings variance explanations.
Report dated October 17, 2002 regarding the Company's earnings outlook and
a slide presentation for use at an analyst conference.
172
Report dated November 14, 2002 regarding an ACC staff recommendation that
the Interim Financing Application be approved.
Report dated November 15, 2002 regarding: (i) appeals of the Track A Order
and an agreement between APS and the ACC staff; (ii) ACC staff testimony on the
Financing Application; and (iii) EITF 02-3.
Report dated November 21, 2002 regarding reclassifications of revenue from
electricity trading activities to a net basis of reporting.
Report dated November 22, 2002 regarding ACC approval of the Interim
Financing Application and Pinnacle West Energy's decision to cancel Redhawk
Units 3 and 4.
Report dated December 17, 2002 containing exhibits to Registration
Statement Nos. 333-52476 and 333-101457.
Report dated December 31, 2002 regarding an ACC staff report on Track B and
containing exhibits comprised of financial information and earnings variance
explanations.
Report dated January 15, 2003 regarding NAC losses and earnings outlook.
Report dated February 27, 2003 regarding the ACC Track B decision.
Report dated March 11, 2003 regarding an ACC ALJ recommendation on the
Financing Application.
Report dated March 27, 2003 regarding ACC approval of a financing
arrangement.
173
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Date: March 31, 2003
William J. Post
----------------------------------------
(William J. Post, Chairman of the
Board of Directors and Chief
Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
William J. Post Principal Executive Officer March 31, 2003
- -------------------------------- and Director
(William J. Post, Chairman
of the Board of Directors and
Chief Executive Officer)
Jack E. Davis Principal Accounting March 31, 2003
- -------------------------------- Officer and Director
(Jack E. Davis, President)
Donald E. Brandt Principal Financial Officer March 31, 2003
- --------------------------------
(Donald E. Brandt,
Senior Vice President and)
Chief Financial Officer)
Edward N. Basha, Jr. Director March 31, 2003
- --------------------------------
(Edward N. Basha, Jr.)
Michael L. Gallagher Director March 31, 2003
- --------------------------------
(Michael L. Gallagher)
174
Pamela Grant Director March 31, 2003
- --------------------------------
(Pamela Grant)
Roy A. Herberger, Jr. Director March 31, 2003
- --------------------------------
(Roy A. Herberger, Jr.)
Martha O. Hesse Director March 31, 2003
- --------------------------------
(Martha O. Hesse)
William S. Jamieson, Jr. Director March 31, 2003
- --------------------------------
(William S. Jamieson, Jr.)
Humberto S. Lopez Director March 31, 2003
- --------------------------------
(Humberto S. Lopez)
Robert G. Matlock Director March 31, 2003
- --------------------------------
(Robert G. Matlock)
Kathryn L. Munro Director March 31, 2003
- --------------------------------
(Kathryn L. Munro)
Bruce J. Nordstrom Director March 31, 2003
- --------------------------------
(Bruce J. Nordstrom)
William L. Stewart Director March 31, 2003
- --------------------------------
(William L. Stewart)
CERTIFICATIONS
I, William J. Post, certify that:
1. I have reviewed this annual report on Form 10-K of Pinnacle West Capital
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
175
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003.
William J. Post
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William J. Post
Chairman and Chief Executive Officer
I, Donald E. Brandt, certify that:
1. I have reviewed this annual report on Form 10-K of Pinnacle West Capital
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
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3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003.
Donald E. Brandt
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Donald E. Brandt
Senior Vice President and Chief
Financial Officer
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