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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 1-4473
ARIZONA PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
ARIZONA
(State or other jurisdiction 86-0011170
of incorporation or organization) (I.R.S. Employer Identification No.)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(Address of principal executive (602) 250-1000
offices, (Registrant's telephone number,
including zip code) including area code)
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OR 12(g) OF THE ACT: None.
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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 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 [ ] No [X]
As of March 31, 2003, there were issued and outstanding 71,264,947 shares
of the registrant's common stock, $2.50 par value, all of which were held
beneficially and of record by Pinnacle West Capital Corporation.
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THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I1(a)
AND (b) AND IS THEREFORE FILING THIS DOCUMENT WITH THE REDUCED DISCLOSURE
FORMAT.
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TABLE OF CONTENTS
PAGE
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GLOSSARY..................................................................... 1
PART I
Item 1. Business.......................................................... 3
Item 2. Properties........................................................ 18
Item 3. Legal Proceedings................................................. 23
Item 4. Submission of Matters to a Vote of Security Holders............... 23
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters............................................. 24
Item 6. Selected Financial Data........................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 26
Item 7A. Quantitative and Qualitative Disclosures about Market Risk........ 54
Item 8. Financial Statements and Supplementary Data....................... 55
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..........................................111
PART III
Item 10. Directors and Executive Officers of the Registrant................111
Item 11. Executive Compensation............................................111
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters.................................111
Item 13. Certain Relationships and Related Transactions....................111
Item 14. Controls and Procedures...........................................112
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..113
SIGNATURES...................................................................141
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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, the Company
APS Energy Services - APS Energy Services Company, Inc., a subsidiary of
Pinnacle West
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 - Arizona Public Service Company
CPUC - California Public Utility Commission
DOE - United States Department of Energy
EITF - the FASB's Emerging Issues Task Force
EPA - United States Environmental Protection Agency
ERMC -Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
FIN - FASB Interpretation
Financing Application - our 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 - our 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
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, parent company of the Company
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of
Pinnacle West
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
SPE - special-purpose entity
Standard & Poor's - Standard & Poor's Corporation
SunCor - SunCor Development Company, a subsidiary of Pinnacle West
Superfund - Comprehensive Environmental Response, Compensation and Liability Act
System - non-trading energy related activities
T&D - transmission and distribution
Track A Order - ACC order dated September 10, 2002 regarding generation asset
transfers and related issues
Track B Order -ACC order dated March 14, 2003 regarding competitive solicitation
requirements for power purchases by Arizona's investor-owned electric utilities
Trading - energy-related activities entered into with the objective of
generating profits on changes in market prices
VIE - variable interest entity
WestConnect - WestConnect RTO, LLC, a proposed RTO to be formed by owners of
electric transmission lines in the southwestern United States
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PART I
ITEM 1. BUSINESS
CURRENT STATUS
GENERAL
We were incorporated in 1920 under the laws of Arizona and currently have
more than 902,000 customers. Pinnacle West owns all of our outstanding common
stock. We provide 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 that we own. We also generate, sell
and deliver electricity to wholesale customers in the western United States. Our
marketing and trading division, as discussed below, sells, in the wholesale
market, our and Pinnacle West Energy's generation output that is not needed for
our Native Load, which includes loads for retail customers and cost-of-service
wholesale customers. We do not distribute any products. During 2002, no single
purchaser or user of energy (other than Pinnacle West) accounted for more than
1% of total electric revenues.
At December 31, 2002, we employed approximately 5,100 people, which
includes employees assigned to joint-owned generating facilities for which we
serve as the generating facility manager. Our principal executive offices are
located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone
602-250-1000).
MARKETING AND TRADING
In early 2003, the marketing and trading division was moved from Pinnacle
West to us 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 our generating assets to
Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" below).
The marketing and trading division sells, in the wholesale market, our and
Pinnacle West Energy generation output that is not needed for our Native Load,
which includes loads for retail customers and traditional cost-of-service
wholesale customers. The division focuses primarily on managing our purchased
power and fuel risks in connection with our 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 our implementation of an ACC-mandated process by
which we 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 two principal business segments (determined by services and the
regulatory environment):
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* our regulated electricity segment (98% 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; and
* our marketing and trading segment (2% of operating revenues in 2002),
which consists of our competitive energy business activities,
including wholesale marketing and trading.
See Note 15 of Notes to Financial Statements in Item 8 for financial
information about our business segments.
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 us and various
parties related to the implementation of retail electric competition in Arizona.
Under the Rules, as modified by the 1999 Settlement Agreement, we were required
to transfer all of our competitive electric assets and services to an
unaffiliated party or parties or to a separate corporate affiliate or affiliates
no later than December 31, 2002. Consistent with that requirement, we had been
addressing the legal and regulatory requirements necessary to complete the
transfer of our 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 us not to transfer our generation assets to Pinnacle West
Energy. See Note 3 of Notes to 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.
FINANCING APPLICATION
On September 16, 2002, we filed an application with the ACC requesting the
ACC to allow us to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to Pinnacle West; to guarantee up to $500 million of
Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to
exceed $500 million in the aggregate. In our application, we stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between us 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
Pinnace West provided to fund the construction of Pinnacle West Energy
generation assets or from effectively competing in wholesale markets. On March
27, 2003, the ACC authorized us 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 Financial Statements in Item 8 for
additional information.
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COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that we 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, we will be required to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, we 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 our total retail energy requirements. The bid amounts are
expected to increase in 2004 and 2005 based largely on growth in our retail load
and 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 our right to reject any bids that are unreasonable,
uneconomical or unreliable.
We expect 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 our electricity requirements. See "Track B Order" in Note 3 of Notes
to Financial Statements in Item 8 for additional information.
GENERAL RATE CASE
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
we will file a general rate case with the ACC. In this rate case, we will update
our cost of service and rate design. In addition, we expect 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 us as
a result of the 1999 Settlement Agreement; and
* recovery of costs incurred by us 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.
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;
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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; 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; and other uncertainties, all of which are difficult
to predict and many of which are beyond our control.
REGULATION AND COMPETITION
RETAIL
The ACC regulates our retail electric rates and our issuance of securities.
The ACC must also approve any transfer of our utility property and certain
transactions between us 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 Financial Statements in
Item 8 for a discussion of the status of electric industry restructuring in
Arizona.
We are 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). We also face 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 our service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to our customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter our service territory. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.
WHOLESALE
GENERAL
The FERC regulates rates for wholesale power sales and transmission
services. During 2002, approximately 11% of our electric operating revenues
resulted from such sales and services. In early 2003, the marketing and trading
division was moved from Pinnacle West to us for all future marketing and trading
activities (existing wholesale contracts will remain at Pinnacle West) as a
result of the ACC's Track A Order prohibiting the previously required transfer
of our generating assets to Pinnacle West Energy (see "Overview of Arizona
Regulatory Developments" above). The marketing and trading division sells, in
the wholesale market, our and Pinnacle West Energy's generation output that is
not needed for our Native Load and, in doing so, competes with other utilities,
power marketers and independent power producers. The division focuses primarily
on managing our purchased power and fuel risks in connection with our costs of
serving retail customer energy requirements. See "Track B Order" in Note 3 of
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Notes to Financial Statements in Item 8 for information regarding an
ACC-mandated process by which we must competitively procure energy.
REGIONAL TRANSMISSION ORGANIZATIONS
On December 20, 1999, the FERC issued its Order No. 2000 regarding regional
transmission organizations. In its order, the FERC set minimum characteristics
and functions that must be met by utilities that participate in RTOs. The
characteristics for an acceptable RTO include independence from market
participants, operational control over a region large enough to support
efficient and nondiscriminatory markets and exclusive authority to maintain
short-term reliability.
As stated in Order No. 2000, the FERC believes that a number of benefits
will result from the formation of RTOs throughout the country, and it has moved
aggressively to ensure that all public utilities participate in an RTO or
demonstrate why such participation is not feasible. According to the FERC, the
benefits it expects to result from RTO formation include: (1) improvements in
transmission system operations with resulting enhancements to inter-regional
trade, congestion management, reliability and coordination; and (2) improved
performance of energy markets, including greater incentives for efficient
generator performance and enhanced potential for demand response.
On October 16, 2001, we and other owners of electric transmission lines in
the Southwest filed with the FERC a request for a declaratory order confirming
that their proposal to form WestConnect RTO, LLC would satisfy the FERC's
requirements for the formation of an RTO. We 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 we 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
Financial Statements in Item 8 for additional information regarding the Notice
of Proposed Rulemaking). On November 12, 2002, we 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
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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 FERC's approval of the for-profit structure will
not predetermine its decision in the final SMD rule regarding whether a
for-profit independent transmission company should be permitted to perform all
the functions of an independent transmission provider. To the extent that the
FERC has not addressed aspects of WestConnect's for-profit proposal or
WestConnect's proposed particular functions, such elements will be subject to
review for consistency with Order No. 2000 and other related decisions regarding
functions that may be performed by an independent transmission company. The
WestConnect applicants sought further clarification of that aspect of the
rehearing order. The FERC has indicated that it will issue an order on the
WestConnect applicants' motion for clarification before April 14, 2003.
The ACC Rules also required the formation and implementation of an Arizona
Independent Scheduling Administrator. The purpose of the AISA is to oversee the
application of operating protocols to ensure statewide consistency for
transmission access. The AISA is anticipated to be a temporary organization
until the implementation of an independent system operator or RTO. APS
participated in the creation of the AISA, a not-for-profit entity, and the
filing at the FERC for approval of its operating protocols. The operating
protocols were partially rejected and the remainder are currently under review.
On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to the AISA with several other pending ACC
dockets. In its Track B Order, the ACC directed that a hearing be held on
whether or not we should be required to continue funding the AISA.
PURCHASED POWER AND GENERATING FUEL
See "Properties - Net Accredited Capacity" in Item 2 for information about
our power plants by fuel types.
2002 ENERGY MIX
Our 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 us. We purchase most of Cholla's coal
requirements from a coal supplier that mines all of the coal under a long-term
lease of coal reserves owned by the Navajo Nation, the federal government and
private landholders. Cholla has sufficient coal, including low sulfur coal,
under current contracts to ensure a reliable fuel supply through 2007. We
purchase a portion of Cholla's coal requirements on the spot market to take
advantage of competitive pricing options. Following expiration of current
contracts, we believe that numerous competitive fuel supply options will exist
to ensure the continued operation of Cholla for its useful life.
FOUR CORNERS Four Corners is a coal-fired power plant located in the
northwest corner of New Mexico. It is a jointly-owned facility operated by us.
We purchase all of Four Corners' coal requirements from a supplier with a
long-term lease of coal reserves owned by the Navajo Nation. Four Corners is
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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 - Net Accredited Capacity" in Item 2 for information about
our ownership interest in Cholla, Four Corners and the Navajo Generating
Station. See Note 10 of Notes to Financial Statements in Item 8 for information
regarding our coal mine reclamation obligations.
NATURAL GAS SUPPLY
We purchase the majority of our natural gas requirements for our gas-fired
plants under contracts with a number of natural gas suppliers. Our 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 our (and other companies
with the same contract type) gas transportation rights could be significantly
impacted. Various parties, including Pinnacle West Energy and us, 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 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. We 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. We
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 us.
The fuel cycle for Palo Verde is comprised of the following stages:
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* 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
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).
We have existing fuel storage pools at Palo Verde and have 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, we believe that spent
nuclear fuel storage or disposal methods will be available for use by Palo Verde
to allow its continued operation through the term of the operating license for
each Palo Verde unit. See "Palo Verde Nuclear Generating Station" in Note 10 of
Notes to 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, we are currently shipping low-level waste to off-site facilities. We
currently believe that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
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We believe that scientific and financial aspects of the issues of spent
nuclear fuel and low-level waste storage and disposal can be resolved
satisfactorily. However, we acknowledge that their ultimate resolution in a
timely fashion will require political resolve and action on national and
regional scales which we are less able to predict. We expect to vigorously
protect and pursue our rights related to this matter.
PURCHASED POWER AGREEMENTS
In addition to that available from our own generating capacity (see
"Properties" in Item 2), we purchase electricity under various arrangements. One
of the most important of these is a long-term contract with Salt River Project.
The amount of electricity available to us is based in large part on customer
demand within certain areas now served by us pursuant to a related territorial
agreement. The generating capacity available to us pursuant to the contract was
336 MW from January through May 2002, and starting in June 2002, it changed to
343 MW. In 2002, we 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. We may also cancel the contract
on five years' notice, given no earlier than December 31, 2006.
In September 1990, we entered into a thirty-year seasonal capacity exchange
agreement with PacifiCorp. Under this agreement, we receive electricity from
PacifiCorp during the summer peak season (from May 15 to September 15) and we
return electricity to PacifiCorp during the winter season (from October 15 to
February 15). Until 2020, we and PacifiCorp each has 480 MW of capacity and a
related amount of energy available to it under the agreement for its respective
seasons. In 2002, we received approximately 571,392 MWh of energy under the
capacity exchange. We must also make additional offers of energy to PacifiCorp
each year through October 31, 2020. Pursuant to this requirement, during 2002,
PacifiCorp received offers of 1,129,600 MWh and purchased about 115,750 MWh.
CONSTRUCTION PROGRAM
During the years 2000 through 2002, we incurred approximately $1.4 billion
in capital expenditures. Our 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. Our capital expenditures were
approximately $501 million in 2002. Our 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
======= =======
11
The above amounts exclude capitalized interest costs and include
capitalized property taxes and approximately $30 million per year for nuclear
fuel. These amounts include only our generation (production) assets. We conduct
a continuing review of our construction program.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Capital Needs and Resources" in Item 7 for additional
information about our construction program.
MORTGAGE REPLACEMENT FUND REQUIREMENTS
So long as any of our first mortgage bonds are outstanding, we are required
for each calendar year to deposit with the trustee under our mortgage cash in a
formularized amount related to net additions to our mortgaged utility plant. We
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 we have issued under the mortgage that are callable prior
to maturity are redeemable at their par value plus accrued interest with cash we
deposit 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 Financial Statements
in Item 8 for information regarding our 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
* 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
12
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
how the State of Arizona and/or EPA Region IX will proceed to implement the
Annex, so the actual impact on us 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, we currently cannot estimate the capital
expenditures, if any, which would result from the final rules. However, we do
not currently expect these rules to have a material adverse effect on our
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
13
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 us to make related
expenditures, such as permit fees. We do not expect any of these expenditures to
have a material impact on our 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. We do not currently expect the FIP to have a material impact on
our financial position, results of operations or liquidity.
SUPERFUND The Comprehensive Environmental Response, Compensation, and
Liability Act (Superfund) establishes liability for the cleanup of hazardous
substances found contaminating the soil, water or air. Those who generated,
transported or disposed of hazardous substances at a contaminated site are among
those who are potentially responsible parties. PRPs may be strictly, and often
jointly and severally, liable for clean-up. The EPA had previously advised us
that the EPA considers us to be a PRP in the Indian Bend Wash Superfund Site,
South Area. Our 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, we do not expect this matter to have a material impact on our
financial position, results of operations or liquidity.
MANUFACTURED GAS PLANT SITES We are currently investigating properties
which we now own or which were previously owned by us or our corporate
predecessors, that were at one time sites of, or sites associated with,
manufactured gas plants. The purpose of this investigation is to determine if:
* waste materials are present;
* such materials constitute an environmental or health risk; and
* we have any responsibility for remedial action.
Where appropriate, we have begun clean-up of certain of these sites. We do
not expect these matters to have a material adverse effect on our financial
position, results of operations or liquidity.
ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY
ADEQ issued to us 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
us to achieve and document compliance with specific environmental requirements.
We have 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 us that the ADEQ expects to take enforcement action against us
regarding the violations included in the NOVs, as well as related violations. We
do not expect these matters to have a material adverse effect on our financial
position, results of operations or liquidity.
14
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. We are the Four Corners operating agent.
We own a 100% interest in Four Corners Units 1, 2 and 3, and a 15% interest in
Four Corners Units 4 and 5. We own a 14% interest in Navajo Generating Station
Units 1, 2 and 3.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the
Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts
purport to give the Navajo Nation Environmental Protection Agency authority to
promulgate regulations covering air quality, drinking water and pesticide
activities, including those 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
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. We cannot currently predict the outcome of this matter.
In February 1998, the EPA issued regulations identifying those Clean Air
Act provisions for which it is appropriate to treat Indian tribes in the same
manner as states. The EPA has announced that it has not yet determined whether
the Clean Air Act would supersede pre-existing binding agreements between the
Navajo Nation and the Four Corners participants and the Navajo Generating
Station participants that could limit the Navajo Nation's environmental
regulatory authority over the Navajo Generating Station and Four Corners. We
believe that the Clean Air Act does not supersede these pre-existing agreements.
We cannot currently predict the outcome of this matter.
In April 2000, the Navajo Tribal Council approved operating permit
regulations under the Navajo Nation Air Pollution Prevention and Control Act. We
believe 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.
15
WATER SUPPLY
Assured supplies of water are important for our generating plants. At the
present time, we have adequate water to meet our needs. However, conflicting
claims to limited amounts of water in the southwestern United States have
resulted in numerous court actions.
Both groundwater and surface water in areas important to our operations
have been the subject of inquiries, claims and legal proceedings, which will
require a number of years to resolve. We are one of a number of parties in a
proceeding before a state court in New Mexico to adjudicate rights to a stream
system from which water for Four Corners is derived. (STATE OF NEW MEXICO, IN
THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY
OF FARMINGTON, UTAH INTERNATIONAL, INC., ET AL., SAN JUAN COUNTY, NEW MEXICO,
District Court No. 75-184). An agreement reached with the Navajo Nation in 1985,
however, provides that if Four Corners loses a portion of its rights in the
adjudication, the Navajo Nation will provide, for a then-agreed upon cost,
sufficient water from our allocation to offset the loss.
A summons served on us in early 1986 required all water claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987, in an action pending in Maricopa County, Arizona, Superior
Court. (IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA
RIVER SYSTEM AND SOURCE, Supreme Court Nos. WC-79-0001 through WC 79-0004
(Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos.
W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the
geographic area subject to the summons. Our rights and the rights of the Palo
Verde participants to the use of groundwater and effluent at Palo Verde are
potentially at issue in this action. As project manager of Palo Verde, we filed
claims that dispute the court's jurisdiction over the Palo Verde participants'
groundwater rights and their contractual rights to effluent relating to Palo
Verde. Alternatively, we seek confirmation of such rights. Three of our other
power plants and two of Pinnacle West Energy's power plants are also located
within the geographic area subject to the summons. Our claims dispute the
court's jurisdiction over our groundwater rights with respect to these plants.
Alternatively, we seek confirmation of such rights. In November 1999, the
Arizona Supreme Court issued a decision confirming that certain groundwater
rights may be available to the federal government and Indian tribes. In
addition, in September 2000, the Arizona Supreme Court issued a decision
affirming the lower court's criteria for resolving groundwater claims.
Litigation on both of these issues will continue in the trial court. No trial
date concerning our water rights claims has been set in this matter.
We have also filed claims to water in the Little Colorado River Watershed
in Arizona in an action pending in the Apache County, Arizona, Superior Court.
(IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE LITTLE
COLORADO RIVER SYSTEM AND SOURCE, Supreme Court No. WC-79-0006 WC-6, Apache
County No. 6417). Our groundwater resource utilized at Cholla is within the
geographic area subject to the adjudication and is therefore potentially at
issue in the case. Our claims dispute the court's jurisdiction over our
groundwater rights. Alternatively, we seek confirmation of such rights. A number
of parties are in the process of settlement negotiations with respect to certain
claims in this matter. Other claims have been identified as ready for litigation
in motions filed with the court. No trial date concerning our water rights
claims has been set in this matter.
16
Although the foregoing matters remain subject to further evaluation, we
expect that the described litigation will not have a material adverse impact on
our financial position, results of operations or liquidity.
The Four Corners region, in which Four Corners is located, has been
experiencing drought conditions that may affect the water supply for the plants
in 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.
17
ITEM 2. PROPERTIES
NET ACCREDITED CAPACITY
Our 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........................................................... 3,983,900
=========
- ----------
(a) Does not include West Phoenix steam units (108,300 kW), which were retired
in December 2002.
18
RESERVE MARGIN
Our 2002 peak one-hour demand on our 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 us under
long-term purchase power contracts as well as our and Pinnacle West Energy's
generating capacity, our capability of meeting system demand on July 9, 2002,
amounted to 6,046,600 kW, for an installed reserve margin of 6.5%. The power
actually available to us from our 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 "Purchased Power Agreements" in Item 1 for information about certain of
our 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 8 of Notes to 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
us, as operating agent for Palo Verde, to operate the three Palo Verde units at
full power.
NUCLEAR DECOMMISSIONING COSTS
The NRC rules on financial assurance requirements for the decommissioning
of nuclear power plants provide that a licensee may use a trust as the exclusive
financial assurance mechanism if the licensee recovers estimated total
decommissioning costs through cost of service rates or through a "non-bypassable
charge." The "non-bypassable systems benefits" charge is the charge that the ACC
has approved to recover certain types of ACC-approved costs, including costs for
low income programs, demand side management, consumer education, environmental,
renewables, etc. "Non-bypassable" means that if a customer chooses to take
19
energy from an "energy service provider" other than us, the customer will still
have to pay this charge to us as part of the customer's electric bill. Other
mechanisms are prescribed, including prepayment, if the requirements for
exclusive reliance on the external sinking fund mechanism are not met. We
currently rely on the external sinking fund mechanism to meet the NRC financial
assurance requirements for our interests in Palo Verde Units 1, 2 and 3. The
decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in
our ACC jurisdictional rates. ACC retail electric competition Rules provide that
decommissioning costs would be recovered through a non-bypassable "system
benefits" charge, which would allow us to maintain our external sinking fund
mechanism. See Note 11 of Notes to Financial Statements in Item 8 for additional
information about our nuclear decommissioning costs.
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 10 of Notes to
Financial Statements in Item 8 for a discussion of the insurance maintained by
the Palo Verde participants, including us, for Palo Verde.
PROPERTY NOT HELD IN FEE OR SUBJECT TO ENCUMBRANCES
JOINTLY-OWNED FACILITIES
We share ownership of some of our generating and transmission facilities
with other companies. The following table shows our interest in those
jointly-owned facilities recorded on the Balance Sheets at December 31, 2002:
PERCENT
OWNED BY US
-----------
Generating facilities:
Palo Verde Nuclear Generating Station
Units 1 and 3 29.1%
Palo Verde Nuclear Generating Station
Unit 2 (see "Palo Verde Leases" below) 17.0%
Four Corners Steam Generating Station
Units 4 and 5 15.0%
Navajo Steam Generating Station
Units 1, 2, and 3 14.0%
Cholla Steam Generating Station
Common Facilities (a) 62.8%(b)
Transmission facilities:
ANPP 500KV System 35.8%(b)
Navajo Southern System 31.4%(b)
Palo Verde-Yuma 500KV System 23.9%(b)
Four Corners Switchyards 27.5%(b)
Phoenix-Mead System 17.1%(b)
Palo Verde - Estrella 500KV System 50.0%(b)
(a) PacifiCorp owns Cholla Unit 4 and we operate the unit for PacifiCorp. The
common facilities at the Cholla Plant are jointly-owned.
20
(b) Weighted average of interests.
PALO VERDE LEASES
In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. We account for
these leases as operating leases. The leases, which have terms of 29.5 years,
contain options to renew the leases for two additional years and to purchase the
property for fair market value at the end of the lease terms. See Notes 8 and 18
of Notes to Financial Statements in Item 8 for additional information regarding
the Palo Verde Unit 2 sale-leaseback transactions.
FIRST MORTGAGE LIEN
Our first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). See Note 6 of Notes to Financial Statements in Item 8 for
information regarding our outstanding first mortgage bonds.
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.
21
[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.
22
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
Financial Statements in Item 8 for a discussion of the ACC retail electric
competition Rules, the Track A Order and related litigation.
See Note 10 of Notes to Financial Statements in Item 8 for information
relating to the FERC proceedings on California energy market issues and a claim
by Citizens that we overcharged Citizens under a power service agreement.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
STOCK AND RELATED STOCKHOLDER MATTERS
Our common stock is wholly-owned by Pinnacle West and is not listed for
trading on any stock exchange. As a result, there is no established public
trading market for our common stock.
The chart below sets forth the dividends declared on the Company's common
stock for each of the four quarters for 2002 and 2001.
COMMON STOCK DIVIDENDS
(DOLLARS IN THOUSANDS)
QUARTER 2002 2001
----------- ------- -------
1st Quarter $42,500 $42,500
2nd Quarter 42,500 42,500
3rd Quarter 42,500 42,500
4th Quarter 42,500 42,500
After payment or setting aside for payment of cumulative dividends and
mandatory sinking fund requirements, where applicable, on all outstanding issues
of preferred stock, the holders of common stock are entitled to dividends when
and as declared out of funds legally available therefor. See Note 6 of Notes to
Financial Statements in Item 8 for restrictions on retained earnings available
for the payment of common stock dividends. As of December 31, 2002, we did not
have any outstanding preferred stock.
24
ITEM 6. SELECTED FINANCIAL DATA
2002 2001 2000 1999 1998
------------ ------------ ------------ ------------ ------------
(DOLLARS IN THOUSANDS)
Electric operating revenues:
Regulated electricity segment $ 2,059,339 $ 2,562,088 $ 2,538,750 $ 1,914,722 $ 1,741,148
Marketing and trading segment 34,054 549,240 395,392 154,126 180,145
Purchased power and fuel costs:
Regulated electricity segment 595,368 1,227,188 1,065,596 432,844 306,884
Marketing and trading segment 32,662 313,991 267,032 136,522 151,164
Operating expenses 1,136,363 1,171,171 1,155,278 1,115,664 1,097,471
------------ ------------ ------------ ------------ ------------
Operating income 329,000 398,978 446,236 383,818 365,774
Other income/(deductions) (8,041) (79) (6,545) 20,857 20,315
Interest deductions - net 121,616 118,211 133,097 136,353 130,842
------------ ------------ ------------ ------------ ------------
Income before extraordinary
charge and cumulative effect
adjustment 199,343 280,688 306,594 268,322 255,247
Extraordinary charge - net of
tax (a) -- -- -- (139,885) --
Cumulative effect of change in
accounting - net of tax (b) -- (15,201) -- -- --
------------ ------------ ------------ ------------ ------------
Net income 199,343 265,487 306,594 128,437 255,247
Preferred dividends -- -- -- 1,016 9,703
------------ ------------ ------------ ------------ ------------
Earnings for common stock $ 199,343 $ 265,487 $ 306,594 $ 127,421 $ 245,544
============ ============ ============ ============ ============
Total Assets $ 6,521,807 $ 6,225,733 $ 6,349,609 $ 6,079,307 $ 6,356,534
============ ============ ============ ============ ============
Capital Structure:
Common stock equity $ 2,159,312 $ 2,150,690 $ 2,119,768 $ 1,983,174 $ 1,975,755
Non-redeemable preferred
stock -- -- -- -- 85,840
Redeemable preferred stock -- -- -- -- 9,401
Long-term debt less current
maturities 2,217,340 1,949,074 1,806,908 1,997,400 1,876,540
------------ ------------ ------------ ------------ ------------
Total capitalization 4,376,652 4,099,764 3,926,676 3,980,574 3,947,536
Commercial paper -- 171,162 82,100 38,300 178,830
Current maturities of long-term
debt 3,503 125,451 250,266 114,711 164,378
------------ ------------ ------------ ------------ ------------
Total $ 4,380,155 $ 4,396,377 $ 4,259,042 $ 4,133,585 $ 4,290,744
============ ============ ============ ============ ============
- ----------
(a) Changes associated with a regulatory disallowance. See "Regulatory
Accounting" in Note 1.
(b) Change in accounting standards related to derivatives in 2001. See Note 16
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Item 7 for a discussion of certain information in the table
above.
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In this Item, we explain our results of operations, general financial
condition, and outlook 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
Financial Statements in Item 8 of this report. These Notes add further details
to the discussion.
BUSINESS OVERVIEW
We are 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 that
we own. We also generate, sell and deliver electricity to wholesale customers in
the western United States. Our marketing and trading division sells, in the
wholesale market, our and Pinnacle West Energy's generation output that is not
needed for our Native Load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. We do not distribute any
products. Pinnacle West owns all of our outstanding common stock.
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:
* Our $500 million financing application, which the ACC approved on
March 27, 2003;
* The implementation of the ACC-mandated process by which we must
competitively procure energy; and
* Our 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."
26
BUSINESS SEGMENTS
We have two principal business segments (determined by 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; and
* our marketing and trading segment, which consists of our competitive
energy business activities, including wholesale marketing and trading.
The following is a summary of earnings by business segment for the years
ended December 31, 2002, 2001, and 2000 (dollars in millions):
2002 2001 2000
------ ------ ------
Regulated electricity $ 198 $ 138 $ 228
Marketing and trading 1 142 79
Income before accounting change 199 280 307
Cumulative effect of change in
accounting - net of income taxes (a) -- (15) --
Net income $ 199 $ 265 $ 307
(a) We recorded a $15 million after-tax charge in 2001 for the cumulative
effect of a change in accounting for derivatives related to the adoption of
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities." See Note 16.
See Note 15 for additional financial information regarding our business
segments.
27
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.
2002 COMPARED WITH 2001
Our net income for the year ended December 31, 2002 was $199 million
compared with $265 million for the prior year. In 2001, we recognized a $15
million after-tax charge for the cumulative effect of a change in accounting for
derivatives, as required by SFAS No. 133 (see Note 16).
Our income before accounting change for the year ended December 31, 2002
was $199 million compared with $281 million for the prior year. The
period-to-period comparison was lower due to reduced marketing and trading
segment gross margin due to our transfer of the marketing and trading activities
to Pinnacle West in 2001 and severance costs of $34 million in the second half
of 2002 relating to voluntary workforce reductions. These 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, and lower
purchased power costs related to 2001 generation reliability program (the
addition of generating capability to enhance reliability for the summer of
2001). These increases were 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.
For additional details, see the following discussion.
28
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 (24)
Lower purchased power and fuel costs related to the 2001 generation
reliability program 30
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)
----------
Net increase in regulated electricity segment gross margin 129
----------
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 (78)
Decrease in marketing and trading segment margin resulting from our
transfer of marketing and trading activities to Pinnacle West in 2001 (156)
----------
Net decrease in marketing and trading segment gross margin (234)
----------
Net decrease in regulated electricity and marketing and trading segments'
gross margins (105)
Higher operations and maintenance expense related to 2002 severance costs
of approximately $34 million, partially offset by lower generation
reliability costs (30)
Lower depreciation and amortization expense primarily related to lower
regulatory asset amortization 21
Higher taxes other than income taxes (7)
Lower other income primarily due to a 2001 insurance recovery of
environmental remediation costs (15)
Higher net interest expense primarily due to higher debt balances and lower
capitalized interest (3)
Miscellaneous factors, net 2
----------
Net decrease in income before income taxes (137)
Lower income taxes primarily due to lower income 56
----------
Net decrease in income before accounting change $ (81)
==========
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $503 million lower in the year ended
December 31, 2002, compared with the prior year as a result of:
29
* 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
($421 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 ($1 million net increase).
Regulated electricity segment purchased power and fuel costs were $632
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
($426 million);
* increased costs related to higher prices for hedged natural gas and
purchased power, net of mark-to-market reversals ($29 million);
* lower purchased power costs related to the 2001 generation reliability
program ($30 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
* other miscellaneous factors ($1 million net increase).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $515 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 ($128 million); and
* lower marketing and trading revenues as a result of our transfer of
marketing and trading activities to Pinnacle West in 2001 ($387
million).
Marketing and trading segment purchased power and fuel costs were $281
million lower in the year ended December 31, 2002, compared with 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 ($50 million); and
30
* lower marketing and trading purchased power and fuel costs as a result
of our transfer of marketing and trading activities to Pinnacle West
in 2001 ($231 million).
OTHER INCOME STATEMENT ITEMS
The increase in operations and maintenance expense of $30 million was
primarily due to severance costs of $34 million related to a 2002 voluntary
workforce reduction, partially offset by lower costs related to generation
reliability, plant outages and maintenance costs.
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 $15 million primarily due to an insurance recovery
recorded in 2001 related to environmental remediation costs and other costs (see
Note 17).
The decrease in depreciation and amortization expense of $21 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 Settlement Agreement, partially offset by increased depreciation and
amortization on higher property, plant and equipment balances.
2001 COMPARED WITH 2000
Our net income for the year ended December 31, 2001 was $265 million
compared with $307 million for the year ended December 31, 2000. In 2001, we
recognized a $15 million after-tax charge in net income as a cumulative effect
of a change in accounting for derivatives, as required by SFAS No. 133 (see Note
16).
Income before accounting change for the year ended December 31, 2001 was
$281 million compared with $307 million for the year ended December 31, 2000.
The year-to-year comparison benefited from strong marketing and trading results
and retail customer growth. These factors were partially offset by higher
purchased power and fuel costs, due in part to increased power plant
maintenance; generation reliability measures; continuing retail electricity
price decreases; and a charge related to Enron and its affiliates.
For additional details, see the following discussion.
The major factors that increased (decreased) income before accounting
change were as follows (dollars in millions):
31
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 (a) (13)(a)
Higher purchased power costs related to the 2001 generation reliability
program (30)
Miscellaneous revenues 1
----------
Net decrease in regulated electricity segment gross margin (139)
----------
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 11
Increase in mark-to-market value related to future periods 71
----------
Net increase in marketing and trading segment gross margin 107
----------
Net increase in regulated electricity and marketing and trading segments'
gross margins (32)
Higher operations and maintenance expense related to the 2001
generation reliability program (12)
Higher operations and maintenance expense related primarily to employee
benefits, plant outage and maintenance and other costs (23)
Lower net interest expense primarily due to higher capitalized interest 15
Higher other income primarily due to a 2001 insurance recovery of
environmental remediation costs 11
Miscellaneous factors, net 2
----------
Net decrease in income before income taxes (39)
Lower income taxes primarily due to lower income 13
----------
Net decrease in income before accounting change
$ (26)
==========
(a) We recorded charges totaling $13 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 with the prior year as a result of:
* decreased revenues related to other wholesale sales and miscellaneous
revenues as a result of lower sales volumes ($28 million);
* increased retail revenues primarily related to higher sales volumes
primarily due to customer growth ($78 million); and
32
* decreased retail revenues related to reductions in retail electricity
prices ($27 million).
Regulated electricity segment purchased power and fuel costs were $162
million higher in the year ended December 31, 2001 compared with the prior year
as a result of:
* decreased costs related to other wholesale sales as a result of lower
volumes ($29 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 purchase power costs related to the 2001 generation reliability
program ($30 million);
* higher costs related to retail sales volumes due to customer growth
($78 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 $154 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 ($40 million);
* increased prior period mark-to-market value for losses transferred to
realized margin in current period ($11 million); and
* increased mark-to-market value for future periods primarily as a
result of more forward sales volumes ($71 million).
Marketing and trading segment purchased power and fuel costs were $47
million higher in the year ended December 31, 2001 compared with 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 ($40 million).
OTHER INCOME STATEMENT ITEMS
The increase in operations and maintenance expenses of $35 million
primarily related to the 2001 generation reliability program (the addition of
generating capability to enhance reliability for the summer of 2001) ($12
million) and increased employee benefit costs, plant outage and maintenance and
other costs ($23 million).
33
Interest expense decreased by $15 million primarily because of lower
interest rates and increased capitalized interest resulting from higher
construction project balances.
Net other income increased $11 million primarily because of insurance
recovery of environmental remediation costs (see Note 17).
See "Regulatory Matters - 1999 Settlement Agreement" in Note 3 for a
discussion of the 1999 Settlement Agreement under which, among other things, we
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
------ ------ ------ ------
Delivery $ 369 $ 273 $ 275 $ 329
Generation (a) 132 123 99 164
Other (b) -- 5 5 5
------ ------ ------ ------
Total $ 501 $ 401 $ 379 $ 498
====== ====== ====== ======
(a) As discussed below under "Factors Affecting Our Financial Outlook," as part
of our 2003 general rate case, we intend 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).
(b) 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, we began several major transmission projects in 2001.
These projects are periodic in nature and are driven by strong regional customer
growth. We expect to spend about $105 million on major transmission projects
during the 2003 to 2005 time frame, and these amounts are included in "Delivery"
in the table above.
34
Generation capital expenditures are comprised of various improvements for
our existing fossil and nuclear plants and the replacement of Palo Verde steam
generators. Examples of the types of projects included in this category are
additions, upgrades and capital replacements of various power plant equipment
such as turbines, boilers and environmental equipment. Generation also 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
Our 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 us and Pinnacle West Energy recently
approved by the ACC. On November 22, 2002 the ACC approved our request (Interim
Financing Application), to permit us 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 the inter-affiliate financing arrangement. See the table below
for our contractual requirements, including our debt repayment obligations. The
table does not take into account any funds that we intend to lend to Pinnacle
West Energy or Pinnacle West consistent with the foregoing financing
arrangements.
We pay for our capital requirements with cash from operations and, to the
extent necessary, external financings. We have historically paid for our
dividends to Pinnacle West with cash from operations.
In 2002, we 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, we will redeem $33 million of our first mortgage
bonds.
Our outstanding debt was approximately $2.2 billion at December 31, 2002.
At December 31, 2002, we 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, we had
no outstanding commercial paper or bank borrowings.
Although provisions in our first mortgage bond indenture, articles of
incorporation and ACC financing orders establish maximum amounts of additional
first mortgage bonds, debt and preferred stock that we may issue, we do not
35
expect any of these provisions to limit our ability to meet our capital
requirements.
We are part of a multi-employer pension plan sponsored by Pinnacle West.
Pinnacle West contributes at least the minimum amount required under IRS
regulations, but no more than the maximum tax-deductible amount. The minimum
required funding takes into consideration the value of the fund assets and the
pension obligation. Pinnacle West elected to contribute cash to the pension plan
in each of the last five years; the minimum required contributions during each
of those years was zero. Specifically, Pinnacle West contributed $27 million for
2002, $24 million for 2001, $44 million for 2000, $25 million for 1999 and $14
million for 1998. We fund our share of the pension contribution. We represent
approximately 90% of the total funding amounts described above. The assets in
the plan are mostly domestic common stocks, bonds and real estate. Pinnacle West
currently forecasts 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 a tax accounting method change on the 2001 Pinnacle West 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 the 2001 Pinnacle West
federal consolidated income tax return.
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):
Actual Estimated
------ ---------------------------------------------------
There-
2002 2003 2004 2005 2006 2007 after
------ ------ ------ ------ ------ ------ ------
Long-term debt payments $ 337 $ -- $ 205 $ 400 $ 84 $ -- $1,518
Capital lease payments -- 4 3 3 3 2 5
Operating lease payments 60 59 59 59 59 59 456
Fuel and purchase power
commitments 307 135 82 28 31 17 162
------ ------ ------ ------ ------ ------ ------
Total contractual commitments $ 704 $ 198 $ 349 $ 490 $ 177 $ 78 $2,141
====== ====== ====== ====== ====== ====== ======
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.
36
In 1986, we entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. See Note 8 for
further information about the sale-leaseback transactions. Based on our
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.
We are exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that we do not consider to be reasonably
likely to occur. Under certain circumstances (for example, the NRC issuing
specified violation orders with respect to Palo Verde or the occurrence of
specified nuclear events), we would be required to assume the debt associated
with the transactions, make specified payments to the equity participants and
take title to the leased Unit 2 interests, which if appropriate, may be required
to be written down in value. If such an event had occurred as of December 31,
2002, we would have been required to assume approximately $285 million of debt
and pay the equity participants approximately $200 million.
CREDIT RATINGS
The ratings of our securities as of March 28, 2003 are shown below and are
considered "investment-grade" ratings. The ratings reflect the respective views
of the rating agencies, from which an explanation of the significance of their
ratings may be obtained. There is no assurance that these ratings will continue
for any given period of time. The ratings may be revised or withdrawn entirely
by the rating agencies, if, in their respective judgments, circumstances so
warrant. Any downward revision or withdrawal may adversely affect the market
price of our securities and serve to increase our cost of and access to capital.
Moody's Standard & Poor's Fitch
------- ----------------- -----
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 our debt ratings in the
above chart. On that same date, Standard & Poor's lowered our corporate credit
rating from BBB+ to BBB. Standard & Poor's assigned a stable outlook to the
ratings. All of our credit ratings remain investment grade. In December 2002,
Fitch placed certain of our debt on Ratings Watch Negative. The ratings watch
affects all of our debt ratings with the exception of our commercial paper
rating.
On December 31, 2002, Moody's affirmed the ratings set forth above.
DEBT PROVISIONS
Our significant debt covenants include a debt-to-total-capitalization ratio
and an interest coverage test. We are in compliance with such covenants and
anticipate that we will continue to meet all the significant covenant
requirement levels. The ratio of debt to total capitalization cannot exceed 65%.
37
At December 31, 2002, our ratio is approximately 48%. The provisions regarding
interest coverage require a minimum cash coverage of two times the interest
requirements. The coverage is approximately 5 times for our bank agreements and
15 times for our mortgage indenture. Failure to comply with such covenant levels
would result in an event of default which, generally speaking, would require the
immediate repayment of the debt subject to the covenants.
Our financing agreements do not contain "ratings triggers" that would
result in an acceleration of the required interest and principal payments in the
event of a ratings downgrade. However, in the event of a ratings downgrade, we
may be subject to increased interest costs under certain financing agreements.
All of our bank agreements contain "cross-default" provisions that would
result in defaults and the potential acceleration of payment under these bank
agreements if we were to default under other agreements. Our credit agreements
generally contain provisions under which the lenders could refuse to advance
loans in the event of a material adverse change in our financial condition or
financial prospects.
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 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.
38
* 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.
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 our 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 us not to transfer our generation assets, as
previously required by the 1999 Settlement Agreement (see "Track A Order" in
Note 3). Accordingly, we now consider our 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 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 Balance Sheets at December 31, 2002. See Notes 1 and 3 for more
information.
PENSIONS AND OTHER POSTRETIREMENT BENEFIT ACCOUNTING
Pinnacle West sponsors a qualified defined benefit pension plan and a
non-qualified supplemental excess benefit retirement plan for employees of
Pinnacle West and its subsidiaries. In 2002, we represented 87% of the total
costs of this plan. 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
39
and other postretirement benefit costs. Pension and other postretirement benefit
costs may also be significantly affected by changes in key actuarial
assumptions, including the expected long-term rate of return on plan assets and
the discount rates used in determining the projected benefit obligation and
pension and other postretirement benefit costs.
Pinnacle West's pension and other postretirement plan assets are primarily
made up of equity and fixed income investments. Fluctuations in actual equity
market returns as well as changes in general interest rates may result in
increased or decreased pension and other postretirement benefit costs in future
periods. Likewise, changes in assumptions regarding current discount rates and
the expected long-term rate of return on plan assets could also increase or
decrease recorded pension and other postretirement benefit costs.
We account for our defined benefit pension plans in accordance with SFAS
No. 87, "Employers' Accounting for Pensions," which requires amounts recognized
in our financial statements to be determined on an actuarial basis. Changes in
pension obligations associated with these factors may not be immediately
recognized as pension costs on the income statement, but generally are
recognized in future years over the remaining average service period of plan
participants. As such, significant portions of pension costs recorded in any
period may not reflect the actual level of cash benefits provided to plan
participants.
The following chart reflects the sensitivities associated with a one
percent increase or decrease in certain actuarial assumptions related to our
defined benefit pension plans. Each sensitivity below reflects the impact of
changing only that assumption. The chart shows the increase (decrease) each
change in assumption would have on the 2002 Pinnacle West projected benefit
obligation, the 2002 reported pension liability on the Pinnacle West
Consolidated Balance Sheets and the 2002 reported annual pension expense, after
consideration of amounts capitalized or billed to electric plant participants,
on the Pinnacle West Consolidated Statements of Income (dollars in millions). In
2002, we represented 87% of the total cost of the plans.
Increase/(Decrease)
- --------------------------------------------------------------------------------
Impact on Impact on Impact on
Projected 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.
40
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 Pinnacle West accumulated other
postretirement benefit obligation and the 2002 reported other postretirement
benefit expense, after consideration of amounts capitalized or billed to
electric plant participants, on the Pinnacle West Consolidated Statements of
Income (dollars in millions). In 2002, we represented 87% of the total cost of
this plan.
Increase/(Decrease)
- --------------------------------------------------------------------------------
Impact on Accumulated Impact on Other
Postretirement Benefit Postretirement
Actuarial Assumption Obligation Benefit 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 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.
41
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 the 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 7 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
Statements of Income on a net basis. The rescission of EITF 98-10 has no effect
on the accounting for derivative instruments used for non-trading activities,
which continue to be accounted for in accordance with SFAS No. 133. See "Other
Accounting Matters - Accounting for Derivative and Trading Activities" below for
42
details on the change in accounting for energy trading contracts. See Note 16
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 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 16 for further discussion on credit risk.
The use of models and other valuation methods to determine fair market
value often requires subjective and complex judgment. Actual results could
differ from the results estimated through application of these methods. Our
practice is to hedge within timeframes established by the ERMC.
43
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. 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
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. We adopted
the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. The
impact of the guidance was immaterial to our financial statements.
EITF 02-3 requires derivatives held for trading purposes, whether settled
financially or physically, be reported in the income statement on a net basis.
Previous guidance under EITF 98-10 permitted physically settled energy trading
contracts to be reported either gross or net in the income statement. Beginning
in the third quarter of 2002, we netted all of our energy trading activities on
the Statements of Income and restated prior year amounts for all periods
presented. Reclassification of such trading activity to a net basis of reporting
resulted in reductions in both revenues and purchased power and fuel costs, but
did not have any impact on our financial condition, 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 16 for further information
on accounting for derivatives under SFAS No. 133.
ASSET RETIREMENT OBLIGATIONS
On January 1, 2003 we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." The standard requires the fair value of asset
retirement obligations to be recorded as a liability, along with an offsetting
plant asset, when the obligation is incurred. Accretion of the liability due to
the passage of time will be an operating expense and the capitalized cost is
depreciated over the useful life of the long-lived asset. (See Note 1 for more
information regarding our previous accounting for removal costs.)
We determined that we have asset retirement obligations for our nuclear
facilities (nuclear decommissioning) and certain other generation, transmission
and distribution assets. On January 1, 2003 we recorded a liability of $219
million for our asset retirement obligations including the accretion impacts; a
$67 million increase in the carrying amount of the associated assets; and a net
reduction of $192 million in accumulated depreciation related primarily to the
reversal of previously recorded accumulated decommissioning and other removal
costs related to these obligations. Additionally, we recorded a regulatory
44
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 $333,000 in
stock option expense before income taxes in our Statements of Income for 2002.
See Notes 1 and 14 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 18 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 us and various
parties related to the implementation of retail electric competition in Arizona.
Under the Rules, as modified by the 1999 Settlement Agreement, we were required
to transfer all of our competitive electric assets and services to an
unaffiliated party or parties or to a separate corporate affiliate or affiliates
no later than December 31, 2002. Consistent with that requirement, we had been
addressing the legal and regulatory requirements necessary to complete the
transfer of our 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 us not to transfer our generation assets to Pinnacle West
Energy.
1999 SETTLEMENT AGREEMENT
The 1999 Settlement Agreement has affected, and will affect, our results of
operations. As part of the 1999 Settlement Agreement, we 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
45
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. We 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 Statement of Income. As discussed under
"General Rate Case" below, we intend to seek recovery of this $234 million
write-off in our next general rate case.
Prior to the 1999 Settlement Agreement, the ACC accelerated the
amortization of substantially all of our 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.
FINANCING APPLICATION
On September 16, 2002, we filed an application with the ACC requesting the
ACC to allow us to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to Pinnacle West; to guarantee up to $500 million of
Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to
exceed $500 million in the aggregate. In our application, we stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between us and Pinnacle West Energy under
different regulatory regimes results 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
Pinnacle West provided to fund the construction of Pinnacle West Energy
generation assets or from effectively competing in the wholesale markets. On
March 27, 2003, the ACC authorized APS to lend up to $500 million to Pinnacle
West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a
combination of both, not to exceed $500 million in the aggregate. See "ACC
Applications" in Note 3 for further discussion of the approval and related
conditions.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order. See "Track A
Order" in Note 3.
COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that we 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, we will be required
to solicit
46
bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, we 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 our total retail energy requirements. The bid amounts are
expected to increase in 2004 and 2005 based largely on growth in our retail load
and our retail energy sales. The Track B Order also confirmed that it was "not
intended to change the current rate base status of [APS'] existing assets." The
order recognizes our right to reject any bids that are unreasonable,
uneconomical or unreliable.
We expect 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 our electricity requirements. See "Track B Order" in Note 3 for
additional information.
GENERAL RATE CASE
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
we will file a general rate case with the ACC. In this rate case, we will update
our cost of service and rate design. In addition, we expect 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 us as
part of the 1999 Settlement Agreement ($140 million extraordinary
charge recorded on the 1999 Statement of Income); and
* recovery of costs incurred by us 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 was moved to us 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 our
transfer of generating assets to Pinnacle West Energy, focuses primarily on
managing our purchased power and fuel risks in connection with our 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 Pinnacle West's marketing and trading division were lower in 2002 compared
to 2001 due to weak wholesale power market conditions in the western United
States, which included a lack of market liquidity, fewer creditworthy
counterparties, lower wholesale market prices and resulting decreases in sales
volumes. Our 2003 earnings will be affected by the strength (or weakness) of the
wholesale power market.
47
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.
CUSTOMER GROWTH Customer growth in our 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 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 $34
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 and changes in regulatory asset amortization. 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 was 9.7% of assessed value for
2002 and 9.3% for 2001. We expect property taxes to increase primarily due to
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. Interest expense is affected by interest rates
on variable-rate debt. We are continuing to evaluate our construction program.
48
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 our service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to our customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter our service territory.
GENERAL Our financial results may be affected by a number of broad factors.
See "Forward-Looking Statements" below for further information on such factors,
which may cause our actual future results to differ from those we currently seek
or anticipate.
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 the 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 7) and nuclear decommissioning
trust fund (see Note 11). Our policy is to manage interest rates through the use
of a combination of fixed-rate and floating-rate debt. The pension plan and
nuclear decommissioning fund also have risks associated with changing market
values of equity investments. Pension 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 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.
49
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 $ -- $ -- 5.86% $ 3,503
2004 -- -- 6.16% 208,300
2005 -- -- 7.27% 403,300
2006 -- -- 6.72% 86,517
2007 -- -- 5.78% 2,227
Years thereafter -- 3.17% 386,860 6.08% 1,136,473
---------- ---------- ----------
Total $ -- $ 386,860 $1,840,320
========== ========== ==========
Fair Value $ -- $ 386,860 $1,937,244
========== ========== ==========
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 4.72% $ 171,162 $ -- 8.10% $ 125,451
2003 -- -- -- 6.18% 337
2004 -- -- -- 6.08% 205,185
2005 -- -- -- 7.59% 400,185
2006 -- -- -- 6.77% 83,880
Years thereafter -- -- 2.60% 476,860 6.73% 787,894
---------- ---------- ----------
Total $ 171,162 $ 476,860 $1,602,932
========== ========== ==========
Fair Value $ 171,162 $ 476,860 $1,621,937
========== ========== ==========
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
50
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
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 16
for details on the change in accounting for energy trading contracts and further
discussion regarding derivative accounting.
Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the 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):
51
Marketing and
System Trading
---------- ----------
Mark-to-market of net positions
at December 31, 2001 $ (107) $ --
Change in mark-to-market losses for
future period deliveries (22) --
Changes in cash flow hedges
recorded in OCI 64 --
Ineffective portion of changes in fair value
recorded in earnings 8 --
Mark-to-market losses realized
during the year 7 --
---------- ----------
Mark-to-market of net positions
at December 31, 2002 $ (50) $ --
========== ==========
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) 85
Changes in cash flow hedges
recorded in OCI (166) --
Ineffective portion of changes in fair value
recorded in earnings (6) --
Mark-to-market (gains)/losses realized
during the year (18) 7
Transfer of marketing and trading balance to
Pinnacle West marketing and trading -- (104)
---------- ----------
Mark-to-market of net positions
at December 31, 2001 $ (107) $ --
========== ==========
As of December 31, 2002, a hypothetical adverse price movement of 10% in
the market price of our risk management and trading assets and liabilities would
have decreased the fair market value of these contracts by approximately $16
million, compared to a $23 million decrease that would have been realized as of
December 31, 2001. A hypothetical favorable price movement of 10% would have
increased the fair market value of these contracts by approximately $18 million,
compared to a $23 million increase that would have been realized as of December
31, 2001. These contracts are hedges of our forecasted purchases of natural gas.
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.
52
CREDIT RISK
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We use a risk management process to assess and monitor the
financial exposure related to our counterparties. Despite the fact that the
great majority of trading counterparties are rated as investment grade by the
credit rating agencies, there is still a possibility that one or more of these
companies could default, resulting in a material impact on earnings for a given
period. Counterparties in the portfolio consist principally of major energy
companies, municipalities and local distribution companies. We maintain credit
policies that we believe minimize overall credit risk to within acceptable
limits. Determination of the credit quality of our counterparties is based upon
a number of factors, including credit ratings and our evaluation of their
financial condition. In many contracts, we employ collateral requirements and
standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Valuation adjustments are
established representing our estimated credit losses on our overall exposure to
counterparties. See "Critical Accounting Policies - Mark-to-Market Accounting"
above for a discussion of our credit valuation adjustment policy.
RISK FACTORS
Exhibit 99.3, which is hereby incorporated by reference, contains a
discussion of risk factors affecting the Company.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements or make any
further statements on any of these issues, except as required by applicable
laws. Because actual results may differ materially from expectations, we caution
readers not to place undue reliance on these statements. A number of factors
could cause future results to differ materially from historical results, or from
results or outcomes currently expected or sought by us. These factors include
the ongoing restructuring of the electric industry, including the introduction
of retail electric competition in Arizona and decisions impacting wholesale
competition; the outcome of regulatory and legislative proceedings relating to
the restructuring; state and federal regulatory and legislative decisions and
actions, including price caps and other market constraints imposed by the FERC;
regional economic and market conditions, including the California energy
situation and completion of generation 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; 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; and
other uncertainties, all of which are difficult to predict and many of which are
beyond our control.
53
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.
54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Independent Auditors' Report................................................. 56
Statements of Income for 2002, 2001 and 2000................................. 57
Balance Sheets as of December 31, 2002 and 2001.............................. 58
Statements of Cash Flows for 2002, 2001 and 2000............................. 60
Statements of Changes in Common Stock Equity for 2002, 2001 and 2000......... 61
Notes to Financial Statements................................................ 62
Financial Statement Schedule for 2002, 2001 and 2000 Schedule II - Reserve
for 2002, 2001 and 2000....................................................110
See Note 12 for the selected quarterly financial data required to be presented
in this Item.
55
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and the Stockholder of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service
Company (the "Company") as of December 31, 2002 and 2001 and the related
statements of income, changes in common stock equity and cash flows for each of
the three years in the period ended December 31, 2002. Our audits also included
the financial statement schedule listed in the Index. These financial statements
and the financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and the financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Arizona Public Service Company at December
31, 2002 and 2001 and the results of its operations and its 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 financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
As discussed in Note 16 to the financial statements, in 2001 Arizona Public
Service Company changed its method of accounting for derivatives and hedging
activities in order to comply with the provisions of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities."
DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 3, 2003 (March 14, 26 and 27, 2003 as to Note 20)
56
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
------------ ------------ ------------
Electric Operating Revenues:
Regulated electricity segment $ 2,059,339 $ 2,562,088 $ 2,538,750
Marketing and trading segment 34,054 549,240 395,392
------------ ------------ ------------
Total 2,093,393 3,111,328 2,934,142
------------ ------------ ------------
Purchased Power and Fuel Costs:
Regulated electricity segment 595,368 1,227,188 1,065,596
Marketing and trading segment 32,662 313,991 267,032
------------ ------------ ------------
Total 628,030 1,541,179 1,332,628
------------ ------------ ------------
Operating Revenues less Purchased
Power and Fuel Costs 1,465,363 1,570,149 1,601,514
------------ ------------ ------------
Other Operating Expenses:
Operations and maintenance 495,845 465,561 430,092
Depreciation and amortization 399,640 420,893 425,479
Income taxes (Note 4) 132,953 183,640 199,977
Other taxes 107,925 101,077 99,730
------------ ------------ ------------
Total 1,136,363 1,171,171 1,155,278
------------ ------------ ------------
Operating Income 329,000 398,978 446,236
------------ ------------ ------------
Other Income (Deductions):
Other income (Note 17) 5,149 20,207 9,690
Other expense (Note 17) (19,338) (20,790) (20,547)
Income taxes (Note 4) 6,148 504 4,312
------------ ------------ ------------
Total (8,041) (79) (6,545)
------------ ------------ ------------
Income Before Interest Deduction 320,959 398,899 439,691
------------ ------------ ------------
Interest Deductions:
Interest on long-term debt 128,462 126,118 134,431
Interest on short-term borrowings 5,416 4,407 7,455
Debt discount, premium and expense 2,888 2,650 2,105
Capitalized interest (15,150) (14,964) (10,894)
------------ ------------ ------------
Total 121,616 118,211 133,097
------------ ------------ ------------
Income Before Accounting Change 199,343 280,688 306,594
Cumulative Effect of Change in
Accounting for Derivatives -
net of income taxes of $9,892 -- (15,201) --
------------ ------------ ------------
Net Income $ 199,343 $ 265,487 $ 306,594
============ ============ ============
See Notes to Financial Statements.
57
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS
DECEMBER 31,
----------------------------
2002 2001
------------ ------------
(DOLLARS IN THOUSANDS)
Utility Plant (Notes 1, 8 and 9)
Electric plant in service and held for future use $ 8,299,131 $ 7,935,206
Less accumulated depreciation and amortization 3,442,571 3,287,333
------------ ------------
Total 4,856,560 4,647,873
Construction work in progress 329,089 321,305
Intangible assets, net of accumulated amortization
(Note 19) 93,259 83,135
Nuclear fuel, net of accumulated amortization of
$102,821 and $99,185 7,466 6,933
------------ ------------
Utility Plant - net 5,286,374 5,059,246
------------ ------------
Investments and Other Assets
Decommissioning trust accounts (Note 11) 194,440 202,036
Assets from risk management and trading activities -
long-term 31,622 2,082
Other assets 19,964 76,322
------------ ------------
Total Investments and Other Assets 246,026 280,440
------------ ------------
Current Assets:
Cash and cash equivalents 42,549 16,821
Accounts receivable:
Service customers 136,945 182,749
Other (Note 1) 202,597 55,016
Allowance for doubtful accounts (1,341) (3,349)
Accrued utility revenues 72,915 76,131
Materials and supplies (at average cost) 79,985 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 39,616 10,097
Other 45,361 42,009
------------ ------------
Total Current Assets 650,906 487,712
------------ ------------
Deferred Debits:
Regulatory assets (Notes 1 and 3) 241,045 342,383
Unamortized debt issue costs 16,696 13,163
Other 80,760 42,789
------------ ------------
Total Deferred Debits 338,501 398,335
------------ ------------
Total Assets $ 6,521,807 $ 6,225,733
============ ============
See Notes to Financial Statements.
58
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES AND EQUITY
DECEMBER 31,
----------------------------
2002 2001
------------ ------------
(DOLLARS IN THOUSANDS)
Capitalization:
Common stock $ 178,162 $ 178,162
Additional paid-in capital 1,246,804 1,246,804
Retained earnings 819,632 790,289
Accumulated other comprehensive loss:
Minimum pension liability adjustment (61,487) (966)
Derivative instruments (23,799) (63,599)
------------ ------------
Common stock equity 2,159,312 2,150,690
Long-term debt less current maturities (Note 6) 2,217,340 1,949,074
------------ ------------
Total Capitalization 4,376,652 4,099,764
------------ ------------
Current Liabilities:
Commercial paper (Note 5) -- 171,162
Current maturities of long-term debt (Note 6) 3,503 125,451
Accounts payable 118,133 98,959
Accrued taxes 82,557 107,595
Accrued interest 42,608 41,043
Customer deposits 39,865 28,664
Deferred income taxes (Note 4) -- 3,244
Liabilities from risk management and trading
activities 59,773 21,840
Other 51,820 18,798
------------ ------------
Total Current Liabilities 398,259 616,756
------------ ------------
Deferred Credits and Other:
Deferred income taxes (Note 4) 1,225,552 1,023,079
Liabilities from risk management and trading
activities 36,678 95,159
Unamortized gain - sale of utility plant (Note 8) 59,484 64,060
Customer advances for construction 45,513 69,293
Pension liability (Note 7) 156,442 30,247
Other 223,227 227,375
------------ ------------
Total Deferred Credits and Other 1,746,896 1,509,213
------------ ------------
Commitments and Contingencies (Notes 3, 10 and 11)
Total Liabilities and Equity $ 6,521,807 $ 6,225,733
============ ============
See Notes to Financial Statements.
59
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
------------ ------------ ------------
(DOLLARS IN THOUSANDS)
Cash Flows from Operating Activities:
Net income $ 199,343 $ 265,487 $ 306,594
Items not requiring cash:
Depreciation and amortization 399,640 420,893 425,479
Nuclear fuel amortization 31,185 28,362 30,083
Deferred income taxes 206,767 (26,516) (65,726)
Change in mark-to-market 2,957 (100,030) (11,752)
Cumulative effect of change in
accounting - net of income taxes -- 15,201 --
Changes in certain current assets and liabilities:
Accounts receivable (102,450) 302,283 (209,705)
Materials, supplies and fossil fuel 68 (16,867) 475
Other current assets (136) (5,160) (26,682)
Accounts payable 15,372 (190,141) 101,558
Accrued taxes (25,038) 1,080 43,657
Accrued interest 1,565 1,555 7,189
Other current liabilities 44,224 (58,361) 101,685
Increase in regulatory assets (11,029) (17,516) (14,138)
Change in risk management trading - assets (22,570) 10,730 13,181
Change in customer advances (23,780) 28,599 2,544
Change in pension liability 5,415 (30,346) (18,373)
Change in other net long-term assets (18,923) (14,192) 64,998
Change in other net long-term liabilities 1,902 (9,986) (27,396)
------------ ------------ ------------
Net cash provided by operating activities 704,512 605,075 723,671
------------ ------------ ------------
Cash Flows from Investing Activities:
Capital expenditures (490,156) (465,360) (464,368)
Capitalized interest (15,150) (14,964) (10,894)
Other 44,918 (41,926) (72,189)
------------ ------------ ------------
Net cash used for investing activities (460,388) (522,250) (547,451)
------------ ------------ ------------
Cash Flows from Financing Activities:
Issuance of long-term debt 459,926 396,072 300,000
Short-term borrowings (171,162) 89,062 43,800
Dividends paid on common stock (170,000) (170,000) (170,000)
Repayment and reacquisition of long-term debt (337,160) (383,747) (354,888)
------------ ------------ ------------
Net cash used for financing activities (218,396) (68,613) (181,088)
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents 25,728 14,212 (4,868)
Cash and cash equivalents at beginning of year 16,821 2,609 7,477
------------ ------------ ------------
Cash and cash equivalents at end of year $ 42,549 $ 16,821 $ 2,609
============ ============ ============
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest (excluding capitalized interest) $ 117,081 $ 114,094 $ 123,895
Income taxes paid/(refunded) (Note 4) $ (54,283) $ 212,989 $ 222,866
See Notes to Financial Statements.
60
ARIZONA PUBLIC SERVICE COMPANY
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 $ 178,162 $ 178,162 $ 178,162
------------ ------------ ------------
ADDITIONAL PAID-IN CAPITAL 1,246,804 1,246,804 1,246,804
------------ ------------ ------------
RETAINED EARNINGS
Balance at beginning of year 790,289 694,802 558,208
Net income 199,343 265,487 306,594
Common stock dividends (170,000) (170,000) (170,000)
------------ ------------ ------------
Balance at end of year 819,632 790,289 694,802
------------ ------------ ------------
ACCUMULATED OTHER
COMPREHENSIVE LOSS
Balance at beginning of year (64,565) -- --
Minimum pension liability adjustment, net of
tax of $39,696 and $634 (60,521) (966) --
Cumulative effect of a change in accounting
for derivatives, net of tax of $47,404 in
2001 -- 72,274 --
Unrealized gain/(loss) on derivative
instruments, net of tax of $25,426 and
$71,720 38,764 (109,346) --
Reclassification of realized (gain)/loss to
income, net of tax of $679 and $17,399 1,036 (26,527) --
------------ ------------ ------------
Balance at end of year (85,286) (64,565) --
------------ ------------ ------------
TOTAL COMMON STOCK EQUITY $ 2,159,312 $ 2,150,690 $ 2,119,768
============ ============ ============
COMPREHENSIVE INCOME
Net income $ 199,343 $ 265,487 $ 306,594
Other comprehensive loss (20,721) (64,565) --
------------ ------------ ------------
Comprehensive income $ 178,622 $ 200,922 $ 306,594
============ ============ ============
See Notes to Financial Statements.
61
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
We are 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 us. We also generate, sell and deliver electricity to wholesale customers in
the western United States. In early 2003, the marketing and trading division was
moved from Pinnacle West to us for future marketing and trading activities
(existing wholesale contracts will remain at Pinnacle West) as a result of the
ACC's Track A Order prohibiting the previously required transfer of our
generating assets to Pinnacle West Energy (see Note 3 for a discussion of the
Track A Order). Our marketing and trading division sells, in the wholesale
market, our and Pinnacle West Energy's generation output that is not needed for
our Native Load, which includes loads for retail customers and cost-of-service
wholesale customers. We do not distribute any products. Pinnacle West owns all
of our outstanding stock.
During 2001, we transferred most of our marketing and trading activities to
Pinnacle West, which approximated $219 million in assets and $149 million in
liabilities. From time to time, we enter into transactions with Pinnacle West or
Pinnacle West's subsidiaries. The following table summarizes the amounts
included in the Statements of Income and Balance Sheets related to transactions
with affiliated companies (dollars in millions):
For the year ended
December 31,
----------------------------
2002 2001 2000
------ ------ ------
Electric operating revenues:
Pinnacle West - marketing and trading $ 85 $ 50 $ --
APS Energy Services -- 15 26
------ ------ ------
Total $ 85 $ 65 $ 26
====== ====== ======
Purchased power and fuel costs:
Pinnacle West - marketing and trading $ 135 $ 50 $ --
Pinnacle West Energy -- 14 --
------ ------ ------
Total $ 135 $ 64 $ --
====== ====== ======
As of December 31,
------------------
2002 2001
------ ------
Net intercompany receivables/(payables):
Pinnacle West - marketing and trading $ 135 $ 13
Pinnacle West (1) (11)
Pinnacle West Energy (1) 1
APS Energy Services -- 13
------ ------
Total $ 133 $ 16
====== ======
62
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Electric revenues include sales of electricity to affiliated companies at
contract prices. Purchased power includes purchases of electricity from
affiliated companies at contract prices. Intercompany receivables primarily
include the amounts related to the transfer of marketing and trading activities
discussed above and intercompany sales of electricity. Intercompany payables
primarily include amounts related to the purchase of electricity. Intercompany
receivables and payables are generally settled on a current basis in cash.
ACCOUNTING RECORDS AND USE OF ESTIMATES
Our accounting records are maintained in accordance with accounting
principles generally accepted in the United States of America (GAAP). The
preparation of financial statements in accordance with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements and reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. We have
reclassified certain prior year amounts to conform to the current year
presentation.
DERIVATIVE ACCOUNTING
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.
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
63
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 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 16 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 Balance Sheets.
We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. We convert quarterly and calendar year quotes into monthly
prices based on historical relationships.
For options, long-term contracts and other contracts for which price quotes
are not available, we use models and other valuation methods. The valuation
models we employ utilize spot prices, forward prices, historical market data and
other factors to forecast future prices. The primary valuation technique we use
to calculate the fair value of contracts where price quotes are not available is
based on the extrapolation of forward pricing curves using observable market
data for more liquid delivery points in the same region and actual transactions
at the more illiquid delivery points. We also value option contracts using a
variation of the Black-Scholes option-pricing model.
For non-exchange traded contracts, we calculate fair market value based on
the average of the bid and offer price, and we discount to reflect net present
value. We maintain certain valuation 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.
64
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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
16 for further discussion on credit risk.
The use of models and other valuation methods to determine fair market
value often requires subjective and complex judgment. Actual results could
differ from the results estimated through application of these methods. Our
practice is to hedge within timeframes established by the ERMC.
REGULATORY ACCOUNTING
We are regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. As a result, we capitalize
certain costs that would be included as expense in the current period by
unregulated companies. Regulatory assets represent incurred costs that have been
deferred because they are probable of future recovery in customer rates.
Regulatory liabilities generally represent 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 our generation
operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a
discussion of the 1999 Settlement Agreement.
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 Statements of Income.
In 2002, the ACC directed us not to transfer our generation assets, as
previously required by the 1999 Settlement Agreement (see "Track A Order" in
Note 3). Accordingly, we now consider our 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 financial statements.
65
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO 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 our 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 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 10) 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).
Regulatory liabilities are included in deferred credits and other on the
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
====== ======
66
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 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 - 20 years;
* Nuclear plant - 22 years
* Transmission - 34 years
* Distribution - 28 years; and
* Other utility property - 9 years
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, 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.
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
67
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
earnings. The rate used to calculate capitalized interest was a composite rate
of 5.28% for 2002, 6.26% 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 Statements of
Income.
All gains and losses (realized and unrealized) on energy trading contracts
that qualify as derivatives are included in marketing and trading segment
revenues on the Statements of Income on a net basis.
CASH AND CASH EQUIVALENTS
For purposes of the 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
We charge nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method based on actual
physical usage. We divide the cost of the fuel by the estimated number of
thermal units we expect to produce with that fuel. We then multiply that rate by
the number of thermal units produced within the current period. This calculation
determines the current period nuclear fuel expense.
We also charge nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear
fuel, and it charges us $0.001 per kWh of nuclear generation. See Note 10 for
information about spent nuclear fuel disposal and Note 11 for information on
nuclear decommissioning costs.
INCOME TAXES
Income taxes are provided using the asset and liability approach prescribed
by SFAS No. 109, "Accounting for Income Taxes." Pinnacle West files the federal
income tax return on a consolidated basis and files the state income tax returns
on a consolidated or unitary basis. In accordance with our intercompany tax
sharing agreement, federal and state income taxes are allocated to us as though
we filed a separate income tax return. Any difference between the aforementioned
allocations and the consolidated (and unitary) income tax liability is
attributed to Pinnacle West.
68
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
REACQUIRED DEBT COSTS
For debt related to the regulated portion of our business, we amortize
those gains and losses incurred upon early retirement over the original
remaining life of the debt. In accordance with the 1999 Settlement Agreement, we
are 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 Statements of Income.
STOCK-BASED COMPENSATION
Pinnacle West offers stock-based compensation plans for officers and key
employees of our company. In 2002, we began applying the fair value method of
accounting for stock-based compensation, as provided for in SFAS No. 123,
"Accounting for Stock-Based Compensation." The fair value method of accounting
is the preferred method. In accordance with the transition requirements of SFAS
No. 123, we applied the fair value method prospectively, beginning with 2002
stock grants. In prior years, we recognized stock compensation expense based on
the intrinsic value method allowed in Accounting Principles Board Opinion (APB)
No. 25, "Accounting for Stock Issued to Employees."
The following chart compares our net income and stock compensation expense
to what those items would have been if we had recorded stock compensation
expense based on the fair value method for all stock grants through 2002
(dollars in thousands):
2002 2001 2000
-------- -------- --------
Net income:
As reported $199,343 $265,487 $306,594
Pro forma (fair value method) 198,381 263,905 305,745
Stock compensation expense
(net of tax):
As reported 200 -- --
Pro forma (fair value method) 962 1,582 849
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 14 for further discussion about our stock compensation plans.
69
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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
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.
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.
70
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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:
* Notes 1 and 14 for a new accounting standard (SFAS No. 148) related to
stock-based compensation;
* Note 16 for a new EITF issue (EITF 02-3) related to accounting for
energy trading contracts;
* Note 18 for a new interpretation (FIN No. 46) related to VIEs; and
* Note 19 for a new standard (SFAS No. 142) related to goodwill and
intangible assets.
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
us and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, we were required to transfer all of our competitive electric assets
and services to an unaffiliated party or parties or to a separate corporate
affiliate or affiliates no later than December 31, 2002. Consistent with that
requirement, we had been addressing the legal and regulatory requirements
necessary to complete the transfer of our 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 us not to transfer our generation
assets to Pinnacle West Energy. See "Track A Order" below.
On September 16, 2002, we filed an application with the ACC requesting the
ACC to allow us to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to Pinnacle West; to guarantee up to $500 million of
Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to
exceed $500 million in the aggregate. In our application, we stated that the
71
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between us 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 Pinnacle West 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 us 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.
COMPETITIVE PROCUREMENT PROCESS
On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that we 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, we will be required to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, we 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 our total retail energy requirements. The bid
amounts are expected to increase in 2004 and 2005 based largely on growth in our
retail load and 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 our right to reject any bids that are
unreasonable, uneconomical or unreliable.
We expect 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 our 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:
* We have 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
72
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
loads of three MW or greater, standard-offer rates have been reduced
in varying annual increments that total 5% in the years 1999 through
2002.
* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the 1999 Settlement Agreement, retroactive to July 1,
1999, and also became subject to annual reductions beginning January
1, 2000, that vary by rate class, through January 1, 2004.
* There 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
limited circumstances. Neither the ACC nor we 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 our
cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or judicial
decisions, actions or orders.
* We will be permitted to defer for later recovery prudent and
reasonable costs of complying with the Rules, system benefits costs in
excess of the levels included in then-current (1999) rates, and costs
associated with the "provider of last resort" and standard-offer
obligations for service after July 1, 2004. These costs are to be
recovered through an adjustment clause or clauses commencing on July
1, 2004.
* Our distribution system opened for retail access effective September
24, 1999. Customers were eligible for retail access in accordance with
the phase-in adopted by the ACC under the Rules (see "Retail Electric
Competition Rules" below), including an additional 140 MW being made
available to eligible non-residential customers. We opened our
distribution system to retail access for all customers on January 1,
2001. The regulatory developments and legal challenges to the Rules
discussed in this note have raised considerable uncertainty about the
status and pace of electric competition in Arizona. Although some very
limited retail competition existed in our service area in 1999 and
2000, there are currently no active retail competitors providing
unbundled energy or other utility services to our customers. As a
result, we cannot predict when, and the extent to which, additional
competitors will re-enter our service territory.
* Prior to the 1999 Settlement Agreement, we were recovering
substantially all of our regulatory assets through July 1, 2004,
pursuant to a 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that we had demonstrated that our
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value (in 1999 dollars).
We will not be allowed to recover $183 million net present value (in
1999 dollars) of the above amounts. The 1999 Settlement Agreement
provides that we will have the opportunity to recover $350 million net
present value (in 1999 dollars) through a competitive transition
73
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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.
* We will form, or cause to be formed, a separate corporate affiliate or
affiliates and transfer to such affiliate(s) our 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. We will be
allowed to defer and later collect, beginning July 1, 2004, 67%
percent of our 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
us from transferring our generation assets.
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 us.
* Effective January 1, 2001, retail access became available to all of
our retail electricity customers.
* Electric service providers that get CC&N's from the ACC can supply
only competitive services, including electric generation, but not
electric transmission and distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
noncompetitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
electric assets and services to an unaffiliated party or parties or to
a separate corporate affiliate or affiliates. Under the 1999
Settlement Agreement, we received a waiver to allow transfer of our
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 us to transfer our generation assets.
74
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Under the 1999 Settlement Agreement, the Rules are to be interpreted and
applied, to the greatest extent possible, in a manner consistent with the 1999
Settlement Agreement. If the two cannot be reconciled, we must seek, and the
other parties to the 1999 Settlement Agreement must support, a waiver of the
Rules in favor of the 1999 Settlement Agreement.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, to operate in Arizona. We do not believe the
ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was
not at issue in the consolidated cases before the judge. Further, the ACC made
findings related to the fair value of our property in the order approving the
1999 Settlement Agreement. The ACC and other parties aligned with the ACC have
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, we are the "provider of last resort"
for standard-offer, full-service customers under rates that have been approved
by the ACC. These rates are established until at least July 1, 2004. The 1999
Settlement Agreement allows us to seek adjustment of these rates in the event of
emergency conditions or circumstances, such as the inability to secure financing
on reasonable terms; material changes in our cost of service for ACC-regulated
services resulting from federal, tribal, state or local laws; regulatory
requirements; or judicial decisions, actions or orders. Energy prices in the
western wholesale market vary and, during the course of the last two years, have
been volatile. At various times, prices in the spot wholesale market have
significantly exceeded the amount included in our current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation or
transmission outages, we may need to purchase additional supplemental power in
the wholesale spot market. Unless we are able to obtain an adjustment of our
rates under the emergency provisions of the 1999 Settlement Agreement, there can
be no assurance that we would be able to fully recover the costs of this power.
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 our 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
75
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
hearings would begin on June 17, 2002 on various issues, including our 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
us to transfer our 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 the transfer of our generating assets, and directed us to
cancel our activities to transfer our generation assets to Pinnacle
West Energy.
Provisions related to the wholesale competitive energy procurement process
(Track B issues):
* The ACC stayed indefinitely the requirement of the Rules that we
acquire 100% of our energy needs for our standard offer customers from
the competitive market, with at least 50% obtained through a
competitive bid process;
* the ACC established a requirement that we competitively procure, at a
minimum, any required power that we cannot produce from our 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 our existing assets and the Pinnacle West
Energy assets.
On November 15, 2002, we filed appeals of the Track A Order in the Maricopa
County, Arizona Superior Court and in the Arizona Court of Appeals. ARIZONA
PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION COMMISSION, CV2002-0222 32.
ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION COMMISSION, 1CA CC
02-0002. On December 13, 2002, we and the ACC staff agreed to principles for
resolving certain issues raised by us in our appeals of the Track A Order. We
and the ACC
76
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 our upcoming general rate case,
anticipated to be filed before June 30, 2003:
* the generating assets to be included in our 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
our rate base;
* the appropriate treatment of the $234 million pretax asset
write-off agreed to by us as part of a 1999 settlement agreement
approved by the ACC among us and various parties related to the
implementation of retail competition in Arizona; and
* the appropriate treatment of costs incurred by us in preparation
for the previously anticipated transfer of generation assets to
Pinnacle West Energy.
* Upon the ACC's issuance of a final decision that is no longer subject
to appeal approving the Financing Application, with appropriate
conditions, our appeals of the Track A Order would be limited to the
issues described in the preceding bullet points, each of which would
be presented to the ACC for consideration prior to any final judicial
resolution.
On February 21, 2003, a Notice of Claim was filed with the ACC and the
Arizona Attorney General on behalf of Pinnacle West, Pinnacle West Energy and us
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, we will be required to solicit bids for certain
estimated capacity and energy requirements for periods beginning July 1, 2003.
For 2003, we 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 our total retail energy requirements. The bid amounts are expected to
increase in 2004 and 2005 based largely on growth in our retail load and 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 our 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 us and any of our affiliates that may
77
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
participate in the competitive solicitation, requires that we treat bidders in a
non-discriminatory manner and requires us to file a protocol regarding
short-term and emergency procurements. The order permits the provision of
corporate oversight support and governance as long as such activities do not
favor Pinnacle West Energy in the procurement process or provide Pinnacle West
Energy with our confidential bidding information that is not available to other
bidders. The order directs us to evaluate bids on cost, reliability and
reasonableness. The decision requires bidders to allow the ACC to inspect their
plants and requires assurances of appropriate competitive market conduct from
senior officers of such bidders. Following the solicitation, we will prepare a
report evaluating environmental issues relating to the procurement and a series
of workshops on environmental risk management will be commenced thereafter.
We expect 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 our electricity requirements.
ACC APPLICATIONS
On September 16, 2002, we filed a Financing Application requesting the ACC
to allow us to borrow up to $500 million and to lend the proceeds to Pinnacle
West Energy or Pinnacle West; to guarantee up to $500 million of Pinnacle West
Energy's or Pinnacle West'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:
* We noted that our 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 our generation
assets under a common financial and regulatory regime. We 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
our 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.
* We stated that we did not intend or desire to foreclose the
possibility that we would acquire all or part of the Pinnacle West
Energy Assets or that we may propose that the Pinnacle West Energy
Assets be included in our rate base or afforded cost-of-service
regulatory treatment to the extent the Pinnacle West Energy Assets are
used by our customers. We stated that these issues would be
appropriate topics in our 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.
78
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
* We stated that the Track A Order's reversal of the generation asset
transfer requirement and the resulting bifurcation of generation
assets between us 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 Pinnacle West to fund the construction of the
Pinnacle West Energy Assets or from effectively competing in the
wholesale markets. We noted that Pinnacle West Energy had previously
received investment-grade credit ratings contingent upon its receipt
of our generation assets and that Pinnacle West'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
Pinnacle West's senior unsecured debt rating from "BBB" to "BBB-."
* We stated that the amount of the requested loan and/or guarantee is
our present estimate of the amount of credit support necessary through
us to restore Pinnacle West Energy and Pinnacle West to their credit
status prior to the ACC's issuance of the Track A Order. We further
stated that if the requested amount proves to be inadequate, we
reserve the right to submit a second financing application seeking
additional credit support.
On March 27, 2003, the ACC approved the Financing Application, subject to
the following principal conditions:
* any debt issued by us pursuant to the order must be unsecured;
* we 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 our debt that could be issued and sold on
equivalent terms (including, but not limited to, maturity and
security);
* the 264 basis points referred to in the previous bullet point will be
capitalized as a deferred credit and used to offset retail rates in
the future, with the deferred credit balance bearing an interest rate
of six percent per annum;
* the APS Loan must have a maturity date of not more than four years,
unless otherwise ordered by the ACC;
* any demonstrable increase in our cost of capital as a result of the
transaction (such as from a decline in bond rating) will be excluded
from future rate cases;
79
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
* we must maintain a common equity ratio of at least forty percent and
may not pay common dividends if such payment would reduce our common
equity ratio below that threshold, unless otherwise waived by the ACC.
The ACC will process any waiver request within sixty days, and for
this sixty-day period this condition will be suspended. However, this
condition, which will continue indefinitely, will not be permanently
waived without an order of the ACC; and
* certain waivers of the ACC's affiliated interest rules previously
granted to 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 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 Southern Nevada Water Authority if Southern Nevada Water
Authority 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, Pinnacle West will need to refinance approximately $475
million of their indebtedness. We expect that this indebtedness will be repaid
through funds borrowed by Pinnacle West Energy from us under the APS Loan.
On November 22, 2002, the ACC approved our request to permit us 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
80
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 our service area in 1999 and 2000, there are currently no
active retail competitors providing unbundled energy or other utility services
to our customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter our service territory. As competition in
the electric industry continues to evolve, we will continue to evaluate
strategies and alternatives that will position us to compete in the new
regulatory environment.
4. INCOME TAXES
We are included in Pinnacle West's consolidated tax return. However, when
Pinnacle West allocates income taxes to us, it does so based on our taxable
income or loss alone.
Certain assets and liabilities are reported differently for income tax
purposes than they are for financial statements. The tax effect of these
differences is recorded as deferred taxes. We calculate deferred taxes using the
current income tax rates.
We have recorded a regulatory asset related to income taxes on our Balance
Sheets in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. We amortize this amount as the differences reverse. In accordance
with ACC settlement agreements, we are continuing to accelerate amortization of
a regulatory asset related to income taxes over an eight-year period that will
end June 30, 2004 (see Note 1). Accordingly, we are including this accelerated
amortization in depreciation and amortization expense on the Statements of
Income.
As a result of a change in IRS guidance, we claimed a tax deduction related
to a tax accounting method change on the 2001 Pinnacle West federal consolidated
income tax return. The accelerated deduction 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 the 2001 Pinnacle West
federal consolidated income tax return.
The components of income tax expense for income before accounting change
are (dollars in thousands):
81
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Year Ended December 31,
------------------------------------
2002 2001 2000
---------- ---------- ----------
Current:
Federal $ (61,962) $ 174,251 $ 211,139
State (18,000) 35,401 50,252
---------- ---------- ----------
Total current (79,962) 209,652 261,391
Deferred 206,767 (26,516) (65,726)
---------- ---------- ----------
Total income tax expense $ 126,805 $ 183,136 $ 195,665
========== ========== ==========
The following table compares pretax income at the 35% federal income tax
rate to income tax expense (dollars in thousands):
Year Ended December 31,
------------------------------------
2002 2001 2000
---------- ---------- ----------
Federal income tax expense at 35%
statutory rate $ 114,152 $ 162,338 $ 175,791
Increases (reductions) in tax expense
resulting from:
State income tax net of federal income
tax benefit 15,036 20,563 20,007
Other (2,383) 235 (133)
---------- ---------- ----------
Income tax expense $ 126,805 $ 183,136 $ 195,665
========== ========== ==========
The following table sets forth the net deferred income tax liability
recognized on the 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 (1,225,552) (1,023,079)
----------- -----------
Accumulated deferred income taxes - net $(1,221,458) $(1,026,323)
=========== ===========
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows (dollars
in thousands):
December 31,
--------------------------
2002 2001
----------- -----------
DEFERRED TAX ASSETS
Pension liability $ 61,966 $ 13,450
Risk management and trading activities 38,204 46,343
Deferred gain on Palo Verde Unit 2 sale-leaseback 23,562 25,374
Other 80,965 97,868
----------- -----------
Total deferred tax assets 204,697 183,035
----------- -----------
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 (28,884) (18,394)
----------- -----------
Total deferred tax liabilities (1,426,155) (1,209,358)
----------- -----------
Accumulated deferred income taxes - net $(1,221,458) $(1,026,323)
=========== ===========
5. LINES OF CREDIT AND SHORT-TERM BORROWINGS
We 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
mature in June 2003. The commitment fees at December 31, 2002 and 2001 for these
lines of credit were 0.09% per annum. We had no bank borrowings outstanding
under these lines of credit at December 31, 2002 and 2001.
We 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, our short-term
borrowings cannot exceed 7% of our total capitalization unless approved by the
ACC.
On November 22, 2002, the ACC approved our request to permit us 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.
6. LONG-TERM DEBT
Borrowings under our mortgage bond indenture are secured by substantially
all of the Company's utility plant. We also have unsecured debt. The following
table presents the components of long-term debt on the Balance Sheets
outstanding at December 31, 2002 and 2001 (dollars in thousands):
83
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31,
Maturity Interest -------------------------
Dates (a) Rates 2002 2001
--------- ------ ----------- -----------
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
----------- -----------
Total long-term debt 2,220,843 2,074,525
Less current maturities 3,503 125,451
----------- -----------
Total long-term debt less current
maturities $ 2,217,340 $ 1,949,074
=========== ===========
(a) This schedule does not reflect the timing of redemptions that may occur
prior to maturity.
(b) On March 15, 2002, we redeemed at maturity, $125 million of our First
Mortgage Bonds, 8.125% Series due 2002.
(c) On April 15, 2002, we redeemed $122 million of our 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 us pursuant to a loan agreement. The bonds
were issued to refinance $90 million of outstanding pollution control
bonds. The bondholders were issued $90 million of first mortgage bonds
(senior note mortgage bonds) as collateral.
84
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(g) We currently have outstanding $84 million of first mortgage bonds (senior
note mortgage bonds) issued to the senior note trustee as collateral for
the senior notes, as well as, the $90 million issue discussed in footnote
(f) above. The senior note mortgage bonds have the same interest rate,
interest payment dates, maturity and redemption provisions as the senior
notes. Our payments of principal, premium and/or interest on the senior
notes satisfy our corresponding payment obligations on the senior note
mortgage bonds. As long as the senior note mortgage bonds secure the senior
notes, the senior notes will effectively rank equally with the first
mortgage bonds. When we repay all of our first mortgage bonds, other than
those that secure senior notes, the senior note mortgage bonds will no
longer secure the senior notes and will cease to be outstanding.
Our significant debt covenants related to our financing arrangements
include a debt-to-total-capitalization ratio and an interest coverage test. We
are in compliance with such covenants and anticipate that we 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.
Our financing agreements do not contain "ratings triggers" that would
result in an acceleration of the required interest and principal payments in the
event of a ratings downgrade. However, in the event of a ratings downgrade, we
may be subject to increased interest costs under certain financing agreements.
All of our bank agreements contain "cross-default" provisions under which a
default by us in a specified amount under another agreement would result in a
default and the potential acceleration of payment under the agreements. Our
credit agreements generally contain provisions under which the lenders could
refuse to advance loans in the event of a material adverse change in the
borrower's business or financial condition.
The following is a list of payments due on total long-term debt and
capitalized lease requirements through 2007:
* $ 4 million in 2003;
* $ 208 million in 2004;
* $ 403 million in 2005;
* $ 87 million in 2006;
* $ 2 million in 2007; and
* $1,523 million, thereafter.
Our first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. We may pay dividends on our common
stock if there is a sufficient amount "available" from retained earnings and the
excess of cumulative book depreciation (since the mortgage's inception) over
mortgage depreciation, which is the cumulative amount of additional property
pledged each year to address collateral depreciation. As of December 31, 2002,
the amount "available" under the mortgage would have allowed us to pay
85
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
approximately $3 billion of dividends compared to our current annual common
stock dividends of $170 million.
7. 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 its 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. In 2002, we represented 87% of the total cost of this plan. 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
Pinnacle West's Board of Directors. Our employees do not contribute to the
plans. Generally, the benefits under these plans are calculated based on age,
years of service and pay. Pinnacle West funds 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.
The following table shows our contributions and pension expense, including
administrative costs, and after consideration of amounts capitalized or billed
to electric plant participants for 2002, 2001, and 2000 (dollars in millions):
2002 2001 2000
------ ------ ------
Contributions $ 26 $ 44 $ 23
Pension expense $ 11 $ 6 $ 2
The following table shows the components of Pinnacle West's consolidated
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):
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 Pinnacle West's Consolidated Balance Sheets
at 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 Pinnacle West's 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 Pinnacle West's qualified defined benefit
pension plans' change in the fair value of plan assets for the plan years 2002
and 2001 (dollars in thousands):
87
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO 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 Pinnacle West's defined benefit pension
plans' amounts recognized in Pinnacle West's 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 Pinnacle West's 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 its subsidiaries. In 2002, we represented 93% of
the total cost of this plan. In a defined contribution savings plan, the
88
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
benefits a participant will receive result from regular contributions they make
to a participant account. Under this plan, Pinnacle West makes matching
contributions in Pinnacle West stock to participant accounts. After a five-year
vesting period, participants have a choice to change the employer 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 $4 million for 2002, $4 million for 2001, and $3 million for 2000.
OTHER POSTRETIREMENT BENEFITS
Pinnacle West sponsors other postretirement benefits for the employees of
Pinnacle West and its subsidiaries. In 2002, we represented 87% of the total
cost of this plan. 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 following table shows our contributions and postretirement benefit
expense after consideration of amounts capitalized or billed to electric plant
participants for 2002, 2001 and 2000 (dollars in millions):
2002 2001 2000
------ ------ ------
Contributions $ 7 $ 11 $ 5
Other postretirement benefit expense $ 9 $ 6 $ 2
The following table shows the components of Pinnacle West's 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 Pinnacle West's Consolidated Balance Sheets as of
December 31, 2002 and 2001 (dollars in thousands):
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO 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 Pinnacle West's 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.
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The following table sets forth Pinnacle West's 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
========== ==========
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 of 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)
91
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
SEVERANCE CHARGES
In July 2002, we implemented a voluntary workforce reduction as part of our
cost reduction program. We recorded $34 million before taxes in voluntary
severance costs in 2002. No further charges are expected.
8. LEASES
In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. We account for
these leases as operating leases. The 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 18 for a discussion of VIEs, including the SPEs involved in the Palo Verde
sale-leaseback transactions.
In addition, we lease certain land, buildings, equipment, vehicles and
miscellaneous other items through operating rental agreements with varying
terms, provisions and expiration dates.
Total lease expense recognized in the Statements of Income was $52 million
in 2002, $52 million in 2001 and $53 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, we are continuing to accelerate amortization of the regulatory asset
for leases over an eight-year period that will end June 30, 2004 (see Note 1).
All regulatory asset amortization is included in depreciation and amortization
expense in the Statements of Income. The balance of this regulatory asset at
December 31, 2002 was $14 million.
Estimated future minimum lease payments for our operating leases are
approximately $59 million for each of the years 2003 to 2007 and $456 million
thereafter.
92
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
9. JOINTLY-OWNED FACILITIES
We share ownership of some of our generating and transmission facilities
with other companies. The following table shows our interest in those
jointly-owned facilities recorded on the Balance Sheets at December 31, 2002.
Our share of operating and maintaining these facilities is included in the
Statements of Income in operations and maintenance expense.
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 8) 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 we operate the unit for PacifiCorp. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
10. COMMITMENTS AND CONTINGENCIES
ENRON
We recorded charges totaling $13 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. These charges take
into consideration our rights of set-off with respect to the Enron related
contractual obligations. The basis of the set-offs included, but was not limited
to, provisions in the various contractual arrangements with Enron and its
affiliates, including an International Swaps and Derivative Agreement (ISDA)
between us and Enron North America. The write-off is also net of the expected
recovery based on secondary market quotes from the bond market. The amounts were
93
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
written-off from the balances of the related assets and liabilities from risk
management and trading activities on the 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
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 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.
We have existing fuel storage pools at Palo Verde and are 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, we believe that spent nuclear fuel storage or disposal methods will be
available for use by Palo Verde to allow its continued operation through the
term of the operating license for each Palo Verde unit.
Although some low-level waste has been stored on-site in a low-level waste
facility, we are currently shipping low-level waste to off-site facilities. We
currently believe that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
We currently estimate that we will incur $115 million (in 2002 dollars)
over the life of Palo Verde for our share of the costs related to the on-site
interim storage of spent nuclear fuel. As of December 31, 2002, we had spent $2
million and had 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, we 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
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
million per incident. Based on our interest in the three Palo Verde units, our
maximum potential assessment per incident for all three units is approximately
$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. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
PURCHASED POWER AND FUEL COMMITMENTS
We are party 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 $135 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 we have for the
supply of our 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
We 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 Balance
Sheets.
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
A regulatory asset has been established for amounts not yet recovered from
ratepayers related to the coal obligations. In accordance with the 1999
Settlement Agreement with the ACC, we are continuing to accelerate the
amortization of the regulatory asset for coal mine reclamation over an
eight-year period that will end June 30, 2004. Amortization is included in
depreciation and amortization expense on the Statements of Income.
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
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.
We were a seller and a purchaser in the California markets at issue, and to
the extent that refunds are ordered, we should be a recipient as well as a payor
of such amounts. On December 12, 2002, an 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. We do not anticipate material changes in our
exposure and still believes, subject to the finalization of the revised proxy
prices, that we 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.
96
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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.
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 operation 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.
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 us, attempting
to expand those matters to such other participants. We have not yet filed a
responsive pleading in the matter, but we believe the claims by Reliant and Duke
as they relate to us are without merit.
97
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
We were 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 us and numerous other PX
participants. CAL PX V. THE STATE OF CALIFORNIA Superior Court in and for the
County of Sacramento, JCCP No. 4203. Various 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 Pinnacle West, 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 Pinnacle West 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 us that it believes we overcharged Citizens by over $50 million under a
power service agreement. We believe that our charges under the agreement were
fully in accordance with the terms of the agreement. In addition, in testimony
filed with the ACC on March 13, 2002, Citizens acknowledged that, based on its
review, "if Citizens filed a complaint with FERC, it probably would lose the
central issue in the contract interpretation dispute." We and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, Pinnacle West and Citizens entered into a power
sale agreement under which Pinnacle West will supply Citizens with future
specified amounts of electricity and ancillary services through May 31, 2008.
This new agreement does not address issues previously raised by Citizens with
respect to charges under the original power service agreement through June 1,
2001.
LETTERS OF CREDIT
We have 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 on such debt obligations. These letters of
credit have expiration dates in 2003. We have 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, we have 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. 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.
98
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
INDEMNIFICATIONS
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. We have 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.
CONSTRUCTION PROGRAM
Total capital expenditures in 2003 are estimated at $401 million.
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 financial statements, results of operations or liquidity.
11. NUCLEAR DECOMMISSIONING COSTS
We recorded $11 million for nuclear decommissioning expense in each of the
years 2002, 2001 and 2000. We estimate it will cost approximately $1.8 billion
($528 million in 2002 dollars) to decommission our 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. We charge decommissioning costs to expense
over each unit's operating license term and we include them in the accumulated
depreciation balance until each unit is retired. Nuclear decommissioning costs
are recovered in rates.
Our 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. We are required by the ACC to
update the study every three years.
To fund the costs we expect to incur to decommission the plant, we
established external decommissioning trusts in accordance with NRC regulations
and ACC orders. We invest the trust funds primarily in fixed income securities
and domestic stock and classify 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 Balance Sheets at December 31, 2002 and 2001
(dollars in millions):
99
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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.
12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial information for 2002 and 2001 is as follows:
(dollars in thousands)
2002
-------------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
---------- ---------- ------------ -----------
Electric operating revenues (a)
Regulated electricity segment $ 383,741 $ 507,711 $ 744,463 $ 423,424
Marketing and trading segment 10,693 2,369 9,126 11,866
Operating income $ 61,221 $ 97,555 $ 120,452 $ 49,772
Net income $ 31,763 $ 64,439 $ 86,570 $ 16,571
100
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
2001
-------------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
---------- ---------- ------------ -----------
Electric operating revenues (a)
Regulated electricity segment $ 412,807 $ 739,317 $ 973,398 $ 436,566
Marketing and trading segment 247,022 230,894 65,129 6,195
Operating income $ 97,034 $ 95,238 $ 135,139 $ 71,567
Income before accounting
change $ 64,606 $ 69,639 $ 107,556 $ 38,887
Cumulative effect of change in
accounting - net of income tax (2,755) -- (12,446) --
---------- ---------- ---------- ----------
Net income $ 61,851 $ 69,639 $ 95,110 $ 38,887
========== ========== ========== ==========
(a) Our utility business is 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 16).
13. 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 $2.21 billion, with an estimated fair value
of $2.30 billion. The carrying value of our long-term debt (excluding
capitalized lease obligations) was $2.08 billion on December 31, 2001, with an
estimated fair value of $2.10 billion. The fair value estimates are based on
quoted market prices of the same or similar issues.
14. STOCK-BASED COMPENSATION
Pinnacle West offers stock-based compensation plans for officers and key
employees of our company.
In May 2002, Pinnacle West's shareholders approved the 2002 Long-term
Incentive Plan (2002 plan), which allows Pinnacle West to grant performance
shares, stock ownership incentive awards and non-qualified and
performance-accelerated stock options to key employees. Pinnacle West has
reserved 6 million shares of common stock for issuance under the 2002 plan. No
more than 1.8 million shares may be issued in relation to performance share
awards and stock ownership incentive awards. The plan also provides for the
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 $333,000 in stock option expense before income
taxes in our 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.
Total stock-based compensation expense, including stock option expense, was
$3 million in 2002, $2 million in 2001 and $2 million in 2000.
15. BUSINESS SEGMENTS
We have two principal business segments (determined by services and the
regulatory environment):
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
* our regulated electricity segment, which consists of regulated
traditional retail and wholesale electricity businesses and related
activities, and includes electricity transmission, distribution and
generation; and
* our marketing and trading segment, which consists of our competitive
energy business activities, including wholesale marketing and trading.
See Note 1 for information about the transfers of the marketing and
trading division. See Note 1 for more information regarding our
marketing and trading activities.
Financial data for the years ended December 31, 2002, 2001 and 2000 by
business segments is provided as follows (dollars in millions):
Business Segments for Year Ended
December 31, 2002
----------------------------------------
Regulated Marketing and
Electricity Trading Total
----------- ---------- ----------
Operating revenues $ 2,059 $ 34 $ 2,093
Purchased power and fuel costs 595 33 628
Other operating expenses 604 -- 604
---------- ---------- ----------
Operating margin 860 1 861
Depreciation and amortization 400 -- 400
Interest and other expenses 136 -- 136
---------- ---------- ----------
Pretax margin 324 1 325
Income taxes 126 -- 126
---------- ---------- ----------
Net income $ 198 $ 1 $ 199
========== ========== ==========
Total assets $ 6,522 $ -- $ 6,522
========== ========== ==========
Capital expenditures $ 501 $ -- $ 501
========== ========== ==========
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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Business Segments for Year Ended
December 31, 2001
----------------------------------------
Regulated Marketing and
Electricity Trading Total
----------- ---------- ----------
Operating revenues $ 2,562 $ 549 $ 3,111
Purchased power and fuel costs 1,227 314 1,541
Other operating expenses 567 -- 567
----------- ---------- ----------
Operating margin 768 235 1,003
Depreciation and amortization 421 -- 421
Interest and other expenses 119 -- 119
----------- ---------- ----------
Pretax margin 228 235 463
Income taxes 90 93 183
----------- ---------- ----------
Income before accounting change 138 142 280
Cumulative effect of change in
accounting for derivatives - net of
income taxes of $10 (15) -- (15)
----------- ---------- ----------
Net income $ 123 $ 142 $ 265
========== ========== ==========
Total assets $ 6,052 $ 174 $ 6,226
========== ========== ==========
Capital expenditures $ 471 $ -- $ 471
========== ========== ==========
Business Segments for Year Ended
December 31, 2000
----------------------------------------
Regulated Marketing and
Electricity Trading Total
----------- ---------- ----------
Operating revenues $ 2,539 $ 395 $ 2,934
Purchased power and fuel costs 1,065 267 1,332
Other operating expenses 531 -- 531
---------- ---------- ----------
Operating margin 943 128 1,071
Depreciation and amortization 425 -- 425
Interest and other expenses 144 -- 144
---------- ---------- ----------
Pretax margin 374 128 502
Income taxes 146 49 195
---------- ---------- ----------
Net income $ 228 $ 79 $ 307
========== ========== ==========
Total assets $ 5,958 $ 392 $ 6,350
========== ========== ==========
Capital expenditures $ 472 $ -- $ 472
========== ========== ==========
16. 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
104
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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.
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. 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
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. We adopted
the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. The
impact of this guidance was immaterial to our financial statements.
105
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the Balance Sheets.
For non-trading derivative instruments that qualify for cash flow hedge
accounting treatment, changes in the fair value of the effective portion are
recognized in common stock equity (as a component of 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 on 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 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.
The changes in derivative fair value included in the 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) $ 8,482 $ (6,056)
Losses from the discontinuance of
cash flow hedges (9,206) (4,683)
Losses from non-hedge derivatives (12,645) (7,157)
Prior period mark-to-market losses realized
upon delivery of commodities 10,413 25,948
---------- ----------
Total pretax gain/(loss) $ (2,956) $ 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 two years. During the twelve months ending
December 31, 2003, we estimate that a net loss of $26 million before income
106
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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.
CREDIT RISK
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of counterparties. Despite the fact that the great majority
of trading counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could
default, resulting in a material impact on earnings for a given period.
Counterparties in the portfolio consist principally of major energy companies,
municipalities and local distribution companies. We maintain credit policies
that we believe minimize overall credit risk to within acceptable limits.
Determination of the credit quality of our counterparties is based upon a number
of factors, including credit ratings and our evaluation of their financial
condition. In many contracts, we employ collateral requirements and standardized
agreements that allow for the netting of positive and negative exposures
associated with a single counterparty. Credit valuation adjustments 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.
17. 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 -- -- 1,624
Interest income 3,455 5,004 4,924
Miscellaneous 1,694 2,854 3,142
---------- ---------- ----------
Total other income $ 5,149 $ 20,207 $ 9,690
========== ========== ==========
Other expense:
Equity losses - net $ (1,131) $ (3,355) $ --
Non-operating costs (a) (16,424) (14,637) (14,853)
Miscellaneous (1,783) (2,798) (5,694)
---------- ---------- ----------
Total other expense $ (19,338) $ (20,790) $ (20,547)
========== ========== ==========
(a) As defined by FERC, includes below-the-line non-operating utility costs
(primarily community relations and environmental compliance).
107
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
18. 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, we entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. See Note 8 for
further information about the sale-leaseback transactions. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to
consolidate the Palo Verde SPEs. However, we will continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.
We are exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that we do not consider to be reasonably
likely to occur. Under certain circumstances (for example, the NRC issuing
specified violation orders with respect to Palo Verde or the occurrence of
specified nuclear events), we would be required to assume the debt associated
with the transactions, make specified payments to the equity participants, and
take title to the leased Unit 2 interests, which if appropriate, may be required
to be written down in value. If such an event had occurred as of December 31,
2002, we would have been required to assume approximately $285 million of debt
and pay the equity participants approximately $200 million.
19. 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 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 $193 million at
December 31, 2002 and $170 million at December 31, 2001. The related accumulated
amortization was $100 million at December 31, 2002 and $87 million at December
31, 2001. Amortization expense was $19 million in 2002, $21 million in 2001 and
$20 million in 2000. Estimated amortization expense on existing intangible
assets over the next five years is $21 million in 2003, $20 million in 2004, $19
million in 2005, $17 million in 2006 and $14 million in 2007.
108
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
20. 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 us
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 we must
competitively procure energy.
See "California Energy Issues and Refunds in the Pacific Northwest" in Note
10 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.
109
ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES
(DOLLARS IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
BALANCE AT CHARGED CHARGED TO BALANCE AT
BEGINNING TO COST AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- --------- --------- -------- ---------- -------
RESERVE FOR UNCOLLECTIBLES
Year ended December 31, 2002 $ 3,349 $ 2,680 $ -- $ 4,688 $ 1,341
Year ended December 31, 2001 $ 2,380 $ 7,609 $ -- $ 6,640 $ 3,349
Year ended December 31, 2000 $ 1,538 $ 5,438 $ -- $ 4,596 $ 2,380
110
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
Not applicable.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
111
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.
112
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See the Index to Financial Statements in Part II, Item 8.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION
- ----------- -----------
12.1 -- Computation of Ratio of Earnings to Fixed Charges
23.1 -- Consent of Deloitte & Touche LLP
99.1 -- Certification of Jack E. Davis, 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 Bylaws, amended as of 3.2 to Pinnacle West 1-8962 11-14-02
September 18, 2002 September 2002 Form 10-Q
Report
3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95
Directors temporarily Report
suspending Bylaws in part
3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, 1988 Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report
113
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
4.1 Mortgage and Deed of Trust 4.1 to September 1992 1-4473 11-9-92
Relating to the Company's Form 10-Q Report
First Mortgage Bonds,
together with forty-eight
indentures supplemental
thereto
4.2 Forty-ninth Supplemental 4.1 to 1992 Form 10-K 1-4473 3-30-93
Indenture Report
4.3 Fiftieth Supplemental 4.2 to 1993 Form 10-K 1-4473 3-30-94
Indenture Report
4.4 Fifty-first Supplemental 4.1 to August 1, 1993 1-4473 9-27-93
Indenture Form 8-K Report
4.5 Fifty-second Supplemental 4.1 to September 30, 1993 1-4473 11-15-93
Indenture Form 10-Q Report
4.6 Fifty-third Supplemental 4.5 to Registration 1-4473 3-1-94
Indenture Statement No. 33-61228
by means of February 23,
1994 Form 8-K Report
4.7 Fifty-fourth Supplemental 4.1 to 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
4.8 Fifty-fifth Supplemental 4.8 to 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
4.9 Fifty-sixth Supplemental 4.1 to Pinnacle West 2002 1-8962 3-31-03
Indenture Form 10-K Report
4.10 Fifty-seventh Supplemental 4.2 to Pinnacle West 2002 1-8962 3-31-03
Indenture Form 10-K Report
114
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
4.11 Agreement, dated March 21, 4.1 to 1993 Form 10-K 1-4473 3-30-94
1994, relating to the filing Report
of instruments defining the
rights of holders of long-term
debt not in excess of 10% of
the Company's total assets
4.12 Indenture dated as of January 4.6 to Registration 1-4473 1-11-95
1, 1995 among the Company Statement Nos. 33-61228
and The Bank of New York, and 33-55473 by means of
as Trustee January 1, 1995 Form 8-K
Report
4.13 First Supplemental Indenture 4.4 to 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 Registration 1-4473 11-22-96
November 15, 1996 among Statements Nos. 33-61228,
the Company and The Bank 33-55473, 33-64455 and
of New York, as Trustee 333-15379 by means of
November 19, 1996
Form 8-K Report
4.15 First Supplemental Indenture 4.6 to 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 Inden- 4.10 to Registration 1-4473 4-9-97
ture dated as of April 1, 1997 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 January 4.10 to Registration 1-4473 1-16-98
15, 1998 among the Company Statement Nos. 333-15379
and The Chase Manhattan and 333-27551 by means
Bank, as Trustee of January 13, 1998
Form 8-K Report
115
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
4.18 First Supplemental Indenture 4.3 to 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
4.19 Second Supplemental 4.3 to Registration 1-4473 2-22-99
Indenture dated as of Statement Nos. 333-27551
February 15, 1999 and 333-58445 by means of
February 18, 1999
Form 8-K Report
4.20 Third Supplemental Indenture 4.5 to Registration 1-4473 11-5-99
dated as of November 1, 1999 Statement No. 333-58445
by means of November 2,
1999 Form 8-K Report
4.21 Fourth Supplemental Inden- 4.1 to Registration 1-4473 8-4-00
ture dated as of August 1, Statement Nos. 333-58445
2000 and 333-94277 by means
of August 2, 2000 Form
8-K Report
4.22 Fifth Supplemental Inden- 4.1 to September 2001 1-4473 11-6-01
ture dated as of October 1, Form 10-Q
2001
4.23 Sixth Supplemental Inden- 4.1 to Registration 1-4473 2-28-02
ture dated as of March 1, Statement Nos.
2002 333-63994 and
333-83398 by means
of February 26, 2002
Form 8-K Report
10.1 Two separate 10.2 to September 1991 1-4473 11-14-91
Decommissioning Trust Form 10-Q
Agreements (relating to
PVNGS Units 1 and 3,
respectively), each dated
July 1, 1991, between the
Company and Mellon Bank,
N.A., as Decommissioning
Trustee
116
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.2 Amendment No. 1 to 10.1 to 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 1)
dated as of December 1,
1994
10.3 Amendment No. 2 to 10.4 to 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS
Unit 1) dated as of
July 1, 1991
10.4 Amendment No. 1 to 10.2 to 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS
Unit 3) dated as of
December 1, 1994
10.5 Amendment No. 2 to 10.6 to 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS
Unit 3) dated as of
July 1, 1991
10.6 Amended and Restated 10.1 to Pinnacle West 1-8962 3-26-92
Decommissioning Trust 1991 Form 10-K Report
Agreement (PVNGS Unit 2)
dated as of January 31,
1992, among the Company,
Mellon Bank, N.A., as
Decommissioning Trustee,
and State Street Bank and
Trust Company, as
successor to The First
National Bank of Boston,
as Owner Trustee under
two separate Trust
Agreements, each with a
separate Equity
Participant, and as
Lessor under two separate
Facility Leases, each
relating to an undivided
interest in PVNGS Unit 2
117
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.7 First Amendment to Amended 10.2 to 1992 Form 10-K 1-4473 3-30-93
and Restated Report
Decommissioning Trust
Agreement (PVNGS
Unit 2), dated as of
November 1, 1992
10.8 Amendment No. 2 to 10.3 to 1994 Form 10-K 1-4473 3-30-95
Amended and Restated Report
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
November 1, 1994
10.9 Amendment No. 3 to 10.1 to June 1996 Form 1-4473 8-9-96
Amended and Restated 10-Q Report
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
January 31, 1992
10.10 Amendment No. 4 to 10.5 to 1996 Form 10-K 1-4473 3-28-97
Amended and Restated Report
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
January 31, 1992
10.11 Amendment No. 5 to the 10.1 to Pinnacle West's 1-8962 5-15-02
Amended and Restated March 2002 Form 10-Q
Decommissioning Trust Report
Agreement (PVNGS Unit
2), dated as of June 30,
2000
10.12 Amendment No. 3 to the 10.2 to Pinnacle West's 1-8962 5-15-02
Decommissioning Trust March 2002 Form 10-Q
Agreement (PVNGS Unit Report
1), dated as of March 18,
2002
118
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.13 Amendment No. 6 to the 10.3 to Pinnacle West's 1-8962 5-15-02
Amended and Restated March 2002 Form 10-Q
Decommissioning Trust Report
Agreement (PVNGS Unit
2), dated as of March 18,
2002
10.14 Amendment No. 3 to the 10.4 to Pinnacle West's 1-8962 5-15-02
Decommissioning Trust March 2002 Form 10-Q
Agreement (PVNGS Unit Report
3), dated as of March 18,
2002
10.15 Asset Purchase and Power 10.1 to June 1991 Form 1-4473 8-8-91
Exchange Agreement dated 10-Q Report
September 21, 1990 between
the Company and PacifiCorp,
as amended as of October 11,
1990 and as of July 18, 1991
10.16 Long-Term Power Trans- 10.2 to June 1991 Form 1-4473 8-8-91
actions Agreement dated 10-Q Report
September 21, 1990
between the Company and
PacifiCorp, as amended as
of October 11, 1990 and
as of July 8, 1991
10.17 Contract, dated July 21, 1984, 10.31 to Pinnacle West's 2-96386 3-13-85
with DOE providing for the Form S-14 Registration
disposal of nuclear fuel Statement
and/or high-level radioactive
waste, ANPP
10.18 Amendment No. 1 dated 10.3 to 1995 Form 10-K 1-4473 3-29-96
April 5, 1995 to the Long- Report
Term Power Transactions
Agreement and Asset Purchase
and Power Exchange Agree-
ment between PacifiCorp and
the Company
119
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.19 Restated Transmission 10.4 to 1995 Form 10-K 1-4473 3-29-96
Agreement between Report
PacifiCorp and the Company
dated April 5, 1995
10.20 Contract among PacifiCorp, 10.5 to 1995 Form 10-K 1-4473 3-29-96
the Company and United Report
States Department of Energy
Western Area Power
Administration, Salt Lake
Area Integrated Projects
for Firm Transmission
Service dated May 5, 1995
10.21 Reciprocal Transmission 10.6 to 1995 Form 10-K 1-4473 3-29-96
Service Agreement between Report
the Company and PacifiCorp
dated as of March 2, 1994
10.22 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Registration Statement
Four Corners Plant
10.23 Supplemental and Additional 5.02 to 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
10.24 Amendment and Supplement 10.36 to Registration 1-8962 7-25-85
No. 1 to Supplemental and Statement on Form 8-B of
Additional Indenture of Pinnacle West
Lease, Four Corners, dated
April 25,1985
10.25 Application and Grant of 5.04 to Form S-7 2-59644 9-1-77
multi-party rights-of-way Registration Statement
and easements, Four
Corners Plant Site
120
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.26 Application and Amendment 10.37 to Registration 1-8962 7-25-85
No. 1 to Grant of multi-party Statement on Form 8-B of
rights-of-way and easements, Pinnacle West
Four Corners Power Plant
Site, dated April 25, 1985
10.27 Four Corners Project 10.7 to Pinnacle West 1-8962 3-14-01
Co-Tenancy Agreement 2000 Form 10-K Report
Amendment No. 6
10.28 Application and Grant of 5.05 to Form S-7 2-59644 9-1-77
Arizona Public Service Registration Statement
Company rights-of-way
and easements, Four
Corners Plant Site
10.29 Application and Amendment 10.38 to Registration 1-8962 7-25-85
No. 1 to Grant of Arizona Statement on Form 8-B of
Public Service Company Pinnacle West
rights-of-way and easements,
Four Corners Power Plant
Site, dated April 25, 1985
10.30 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.31 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70
rights-of-way and ease- Registration Statement
ments, Navajo Plant
10.32 Water Service Contract 5(l) to Form S-7 2-39442 3-16-71
Assignment with the United Registration Statement
States Department of
Interior, Bureau of
Reclamation, Navajo Plant
121
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.33 Arizona Nuclear Power 10.1 to 1988 Form 10-K 1-4473 3-8-89
Project Participation Agree- Report
ment, dated August 23, 1973,
among the Company, Salt
River Project Agricultural
Improvement and Power
District, Southern California
Edison Company, Public
Service Company of New
Mexico, El Paso Electric
Company, Southern
California Public Power
Authority, and Department
of Water and Power of the
City of Los Angeles, and
amendments 1-12 thereto
10.34 Amendment No. 13 dated as 10.1 to March 1991 Form 1-4473 5-15-91
of April 22, 1991, to Arizona 10-Q Report
Nuclear Power Project Partici-
pation Agreement, dated
August 23, 1973, among
the Company, Salt River
Project Agricultural Improve-
ment 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
122
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.35 Amendment No. 14, to 10.4 to the Pinnacle West 1-8962 8-14-00
Arizona Nuclear Power June 30, 2000 Form 10-Q
Project Participation Report
Agreement, dated August
23, 1973, among the
Company, Salt River
Project Agricultural Improve-
ment 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
10.36(c) Facility Lease, dated as of 4.3 to Form S-3 33-9480 10-24-86
August 1, 1986, between Registration Statement
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and the Company, as Lessee
10.37(c) Amendment No. 1, dated as 10.5 to September 1986 1-4473 12-4-86
of November 1, 1986, to Form 10-Q Report by
Facility Lease, dated as of means of Amendment No.
August 1, 1986, between 1 on December 3, 1986
State Street Bank and Trust Form 8
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and the Company, as Lessee
123
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.38(c) Amendment No. 2 dated as 10.3 to 1988 Form 10-K 1-4473 3-8-89
of 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
10.39(c) Amendment No. 3, dated as 10.3 to 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Facility Lease, dated as
of August 1, 1986, between
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Lessor, and the
Company, as Lessee
10.40 Facility Lease, dated as of 10.1 to 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 the Company, as Lessee
10.41 Amendment No. 1, dated as of 4.13 to Form S-3 1-4473 8-24-87
August 1, 1987, to Facility Registration Statement
Lease, dated as of December No. 33-9480 by means of
15, 1986, between State Street August 1, 1987 Form 8-K
Bank and Trust Company, as Report
successor to The First
National Bank of Boston, as
Lessor, and the Company, as
Lessee
124
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.42 Amendment No. 2, dated as 10.4 to 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Facility Lease, dated as
of December 15, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston,
as Lessor, and the Company,
as Lessee
10.43(a) Directors' Deferred 10.1 to June 1986 Form 1-4473 8-13-86
Compensation Plan, as 10-Q Report
restated, effective January 1,
1986
10.44(a) Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Directors'
Deferred Compensation
Plan, effective as of
January 1, 1993
10.45(a) Third Amendment to the 10.1 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q
Company Directors'
Deferred Compensation
Plan effective as of
May 1, 1993
10.46(a) Fourth Amendment dated 10.8 to Pinnacle West's 1-8962 3-30-00
December 28, 1999 to the 1999 Form 10-K
Arizona Public Service
Company Directors
Deferred Compensation
Plan
125
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.47(a) Arizona Public Service 10.4 to 1988 Form 10-K 1-4473 3-8-89
Company Deferred Report
Compensation Plan, as
restated, effective January 1,
1984, and the second and
third amendments thereto,
dated December 22, 1986, and
December 23, 1987,
respectively
10.48(a) Third Amendment to the 10.3 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.49(a) Fourth Amendment to the 10.2 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q Report
Company Deferred
Compensation Plan effective
as of May 1, 1993
10.50(a) Fifth Amendment to the 10.3 to 1997 Form 10-K 1-4473 3-28-97
Arizona Public Service Report
Company Deferred
Compensation Plan
126
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.51(a) Sixth Amendment to 10.8 to Pinnacle West 1-8962 3-14-01
Arizona Public Service 2000 Form 10-K Report
Company Deferred
Compensation Plan
10.52(a) Schedules of William J. Post 10.2 to Pinnacle West 1-8962 3-31-03
and Jack E. Davis to Form 10-K Report
Arizona Public Service
Company Deferred
Compensation Plan, as
amended
10.53(a) Pinnacle West Capital 10.10 to 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
10.54(a) First Amendment effective as 10.6 to Pinnacle West's 1-8962 3-30-00
of January 1, 1999, to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and
El Dorado Investment
Company Deferred Compen-
sation Plan
10.55(a) Second Amendment effective 10.10 to Pinnacle West's 1-8962 3-30-00
as of January 1, 2000, to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and
El Dorado Investment
Company Deferred Compen-
sation Plan
127
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.56(a) Pinnacle West Capital 10.13 to Pinnacle West's 1-8962 3-30-00
Corporation Supplemental 1999 Form 10-K Report
Excess Benefit Retirement
Plan, as amended and
restated, dated December 7,
1999
10.57(a) First Amendment to the 10.7 to Pinnacle West's 1-8962 3-27-02
Pinnacle West Capital 2001 Form 10-K Report
Corporation Supplemental
Excess Benefit Retirement
Plan
10.58(a) Second Amendment to the 10.8 to Pinnacle West's 1-8962 3-27-02
Pinnacle West Capital 2001 Form 10-K Report
Corporation Supplemental
Excess Benefit Retirement
Plan
10.59(a) Pinnacle West Capital 10.7 to 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
10.60(a) Pinnacle West Capital 99.2 to Pinnacle West's 1-8962 7-3-00
Corporation and Arizona Registration Statement on
Public Service Company Form S-8 No. 333-40796
Directors' Retirement Plan,
as amended and restated
on June 21, 2000
10.61(a) Arizona Public Service 10.1 to September 1997 1-4473 11-12-97
Company Director Form 10-K Report
Equity Plan
10.62(a) Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95
December 21, 1993, between Report
the Company and William L.
Stewart
128
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.63(a) Letter Agreement dated 10.8 to 1996 Form 10-K 1-4473 3-28-97
August 16, 1996 between Report
the Company and
William L. Stewart
10.64(a) Letter Agreement between 10.2 to September 1997 1-4473 11-12-97
the Company and Form 10-Q Report
William L. Stewart
10.65(a) Letter Agreement dated 10.9 to Pinnacle West's 1-8962 3-30-00
December 13, 1999 between 1999 Form 10-K Report
the Company and
William L. Stewart
10.66(a) Amendment to Letter 10.1 to Pinnacle West's 1-8962 8-13-02
Agreement, effective as of June 2002 Form 10-Q
January 1, 2002, between Report
APS and William L. Stewart
10.67(a) Letter Agreement dated as 10.8 to 1995 Form 10-K 1-4473 3-29-96
of January 1, 1996 between Report
the Company and Robert G.
Matlock & Associates, Inc.
for consulting services
10.68(a) Letter Agreement dated 10.17 to Pinnacle West's 1-8962 3-30-00
October 3, 1997 between 1999 Form 10-K Report
the Company and James M.
Levine
10.69(a) Summary of James M. 10.2 to Pinnacle West's 1-8962 5-15-02
Levine Retirement March 2002 Form
Benefits 10-Q Report
10.70(a) Employment Agreement, 10.1 to Pinnacle West's 1-8962 11-14-02
effective as of October 1, November 2002 Form
2002, between APS and 10-Q
James M. Levine
10.71(a) Letter Agreement dated 10.4 to Pinnacle West's 1-8962 3-31-03
June 28, 2001 between 2002 Form 10-K Report
Pinnacle West Capital
Corporation and Steve
Wheeler
129
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.72(a)(d) Key Executive Employment 10.1 to Pinnacle West's 1-8962 8-16-99
and Severance Agreement June 1999 Form 10-Q
between Pinnacle West and Report
certain executive officers of
Pinnacle West and its
subsidiaries
10.73(a) Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option Report
and Incentive Plan
10.74(a) First Amendment dated 10.11 to Pinnacle West's 1-8962 3-30-00
December 7, 1999 to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation Stock Option
and Incentive Plan
10.75(a) Pinnacle West Capital A to the Proxy Statement 1-8962 4-16-94
Corporation 1994 Long- for the Plan Report
Term Incentive Plan Pinnacle West 1994
effective as of Annual Meeting of
March 23, 1994 Shareholders
10.76(a) First Amendment dated 10.12 to Pinnacle West's 1-8962 3-30-00
December 7, 1999, to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation 1994 Long-
Term Incentive Plan
10.77(a) Pinnacle West Capital 10.5 to Pinnacle West's 1-8962 3-31-03
Corporation 2002 Long-Term 2002 Form 10-K Report
Incentive Plan
10.78(a) Trust for the Pinnacle West 10.14 to Pinnacle West's 1-8962 3-30-00
Capital Corporation, Arizona 1999 Form 10-K Report
Public Service Company
and SunCor Development
Company Deferred
Compensation Plans
dated August 1, 1996
10.79(a) First Amendment dated 10.15 to Pinnacle West's 1-8962 3-30-00
December 7, 1999, to the 1999 Form 10-K Report
Trust for the Pinnacle West
Capital Corporation, Arizona
Public Service Company and
SunCor Development
Company Deferred
Compensation Plans
130
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.80(a) 2003 Management Officer 10.1 to Pinnacle West's 1-8962 3-31-03
Incentive Plan 2002 Form 10-K Report
10.81(a) 2003 CEO Variable 10.2 to Pinnacle West's 1-8962 3-31-03
Incentive Plan 2002 Form 10-K Report
10.82 Agreement No. 13904 (Option 10.3 to 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
10.83 Agreement for the Sale and 10.4 to 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
10.84 Territorial Agreement 10.1 to March 1998 1-4473 5-15-98
between the Company Form 10-Q Report
and Salt River Project
10.85 Power Coordination 10.2 to March 1998 1-4473 5-15-98
Agreement between Form 10-Q Report
the Company and Salt
River Project
10.86 Memorandum of Agreement 10.3 to March 1998 1-4473 5-15-98
between the Company and Form 10-Q Report
Salt River Project
131
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
10.87 Addendum to Memorandum 10.2 to May 19, 1998 1-4473 6-26-98
of Agreement between the Form 8-K Report
Company and Salt River
Project dated as of May
19, 1998
99.1 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93
among PVNGS II Funding Report
Corp., Inc., the Company and
Chemical Bank, as Trustee
99.2 Supplemental Indenture to 4.3 to 1992 Form 10-K 1-4473 3-30-93
Collateral Trust Indenture Report
among PVNGS II Funding
Corp., Inc., the Company and
Chemical Bank, as Trustee
99.3(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92
dated as of August 1, 1986, Form 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, the Company, and
the Equity Participant named
therein
132
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.4(c) Amendment No. 1 dated as 10.8 to September 1986 1-4473 12-4-86
of November 1, 1986, to Form 10-Q Report by
Participation Agreement, means of Amendment No.
dated as of August 1,1986, 1, on December 3, 1986
among PVNGS Funding Form 8
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
99.5(c) Amendment No. 2, dated as 28.4 to 1992 Form 10-K 1-4473 3-30-93
of 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, the
Company, and the Equity
Participant named therein
133
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.6(c) Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86
Security Agreement and Registration 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
99.7(c) Supplemental Indenture No. 10.6 to September 1986 1-4473 12-4-86
1, dated as of November 1, Form 10-Q Report by
1986 to Trust Indenture, means of Amendment No.
Mortgage, Security Agree- 1 on December 3, 1986
ment and Assignment of Form 8
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
99.8(c) Supplemental Indenture No. 2 4.4 to 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 Indenture Trustee
99.9(c) Assignment, Assumption and 28.3 to Form S-3 33-9480 10-24-86
Further Agreement, dated as Registration Statement
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
134
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.10(c) Amendment No. 1, dated 10.10 to September 1986 1-4473 12-4-86
as of November 1, 1986, to Form 10-Q Report by
Assignment, Assumption and means of Amendment No.
Further Agreement, dated as 1 on December 3, 1986
of August 1, 1986, between Form 8
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.11(c) Amendment No. 2, dated 28.6 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.12 Participation Agreement, 28.2 to September 1992 1-4473 11-9-92
dated as of December 15, Form 10-Q Report
1986, among PVNGS
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor
to The First National Bank
of Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank,
in its individual capacity
and as Indenture Trustee
under a Trust Indenture,
the Company, and the
Owner Participant named
therein
135
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.13 Amendment No. 1, dated 28.20 to Form S-3 1-4473 8-10-87
as of August 1, 1987, to Registration Statement
Participation Agreement, No. 33-9480 by means of a
dated as of December 15, November 6, 1986 Form
1986, among PVNGS 8-K Report
Funding Corp., Inc. as
Funding Corporation, State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Owner Trustee,
Chemical Bank, as Indenture
Trustee, the Company, and
the Owner Participant named
therein
99.14 Amendment No. 2, dated 28.5 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS Fund-
ing Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and
as Indenture Trustee, the
Company, and the Owner
Participant named therein
99.15 Trust Indenture, Mortgage, 10.2 to November 18, 1986 1-4473 1-20-87
Security Agreement and 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
136
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.16 Supplemental Indenture No. 4.13 to Form S-3 1-4473 8-24-87
1, dated as of August 1, 1987, Registration Statement
to Trust Indenture, Mortgage, No. 33-9480 by means of
Security Agreement and August 1, 1987 Form 8-K
Assignment of 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 Owner
Trustee, and Chemical Bank,
as Indenture Trustee
99.17 Supplemental Indenture 4.5 to 1992 Form 10-K 1-4473 3-30-93
No. 2 to Trust Indenture, Report
Mortgage, Security Agree-
ment and Assignment of
Facility Lease, dated as of
December 15, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston,
as Owner Trustee, and
Chemical Bank, as Indenture
Trustee
99.18 Assignment, Assumption and 10.5 to November 18, 1986 1-4473 1-20-87
Further Agreement, dated as Form 8-K Report
of December 15, 1986,
between the Company and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
137
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.19 Amendment No. 1, dated 28.7 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993, to Report
Assignment, Assumption
and Further Agreement,
dated as of December 15,
1986, between the Company
and State Street Bank and
Trust Company, as successor
to The First National Bank
of Boston, as Owner Trustee
99.20(c) Indemnity Agreement dated 28.3 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993 by the Report
Company
99.21 Extension Letter, dated as of 28.20 to Form S-3 1-4473 8-10-87
August 13, 1987, from the Registration Statement
signatories of the No. 33-9480 by means of a
Participation Agreement to November 6, 1986 Form
Chemical Bank 8-K Report
99.22 Rate Reduction Agreement 10.1 to December 4, 1995 1-4473 12-14-95
dated December 4, 1995 Form 8-K Report
between the Company and
the ACC Staff
99.23 Arizona Corporation 10.1 to March 1996 1-4473 5-14-96
Commission Order Form 10-Q Report
dated April 24, 1996
99.24 Arizona Corporation 99.1 to 1996 Form 10-K 1-4473 3-28-97
Commission Order, Report
Decision No. 59943,
dated December 26, 1996,
including the Rules regard-
ing the introduction of retail
competition in Arizona
99.25 Retail Electric Competition 10.1 to June 1998 1-4473 8-14-98
Rules Form 10-Q Report
138
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
99.26 Arizona Corporation 10.1 to September 1999 1-4473 11-15-99
Commission Order, 10-Q Report
Decision No. 61973, dated
October 6, 1999, approving
our Settlement Agreement
99.27 Arizona Corporation 10.2 to September 1999 1-4473 11-15-99
Commission Order, 10-Q Report
Decision No. 61969, dated
September 29, 1999, includ-
ing the Retail Electric
Competition Rules
99.28 Addendum to Settlement 10.1 to Pinnacle West 1-8962 11-14-00
Agreement September 2000 10-Q
99.29 ACC Opinion and Order 99.1 to Pinnacle West's 1-8962 9-17-02
dated September 10, 2002, September 10, 2002
Decision No. 65154 Form 8-K Report
99.30 Arizona Public Service 99.2 to Pinnacle West's 1-8962 9-17-02
Company Application filed September 10, 2002
with the Arizona Form 8-K Report
Corporation Commission on
September 16, 2002
99.31 Track "A" Appeals Issues - 99.1 to Pinnacle West's 1-8962 12-16-02
Principles for Resolution November 15, 2002
Form 8-K Report
- ----------
(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 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 officers and key
employees of the Company. 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.
139
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 October 17, 2002 regarding Pinnacle West's earnings outlook.
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 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 January 15, 2003 regarding NAC losses and Pinnacle West's
earnings outlook.
Report dated January 30, 2003 regarding an ACC staff report on Track B.
Report dated February 24, 2003 regarding reclassifications of revenue from
electricity trading activities to a net basis of reporting.
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.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
Date: March 31, 2003 (Registrant)
Jack E. Davis
--------------------------------------
(Jack E. Davis, President and Chief
Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
William J. Post Director March 31, 2003
- -------------------------------
(William J. Post, Chairman
of the Board of Directors)
Jack E. Davis Principal Executive Officer March 31, 2003
- ------------------------------- and Director
(Jack E. Davis, President
and Chief Executive Officer)
Donald E. Brandt Principal Financial Officer March 31, 2003
- -------------------------------
(Donald E. Brandt,
Senior Vice President,
and Chief Financial Officer)
Chris N. Froggatt Principal Accounting Officer March 31, 2003
- -------------------------------
(Chris N. Froggatt,
Vice President and Controller)
Edward N. Basha, Jr. Director March 31, 2003
- -------------------------------
(Edward N. Basha, Jr.)
141
Michael L. Gallagher Director March 31, 2003
- -------------------------------
(Michael L. Gallagher)
Pamela Grant Director March 31, 2003
- -------------------------------
(Pamela Grant)
Roy A. Herberger, Jr. Director March 31, 2003
- -------------------------------
(Roy A. Herberger, Jr.)
Martha O. Hesse Director March 31, 2003
- -------------------------------
(Martha O. Hesse)
William S. Jamieson, Jr. Director March 31, 2003
- -------------------------------
(William S. Jamieson, Jr.)
Humberto S. Lopez Director March 31, 2003
- -------------------------------
(Humberto S. Lopez)
Robert G. Matlock Director March 31, 2003
- -------------------------------
(Robert G. Matlock)
Kathryn L. Munro Director March 31, 2003
- -------------------------------
(Kathryn L. Munro)
Bruce J. Nordstrom Director March 31, 2003
- -------------------------------
(Bruce J. Nordstrom)
CERTIFICATIONS
I, Jack E. Davis, certify that:
1. I have reviewed this annual report on Form 10-K of Arizona Public Service
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
142
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.
Jack E. Davis
----------------------------------------
Jack E. Davis
President and Chief Executive Officer
I, Donald E. Brandt, certify that:
1. I have reviewed this annual report on Form 10-K of Arizona Public Service
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
143
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003.
Donald E. Brandt
----------------------------------------
Donald E. Brandt
Senior Vice President and Chief
Financial Officer
144