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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______ TO ______
COMMISSION FILE NUMBER 1-8962
PINNACLE WEST CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
ARIZONA 86-0512431
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
400 North Fifth Street, P.O. Box 53999 (602) 250-1000
Phoenix, Arizona 85072-3999 (Registrant's telephone number,
(Address of principal executive including area code)
offices, including zip code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name Of Each Exchange On
Title Of Each Class Which Registered
------------------- ----------------
Common Stock, New York Stock Exchange
No Par Value Pacific Stock Exchange
Aggregate Market Value
Of Shares Held By
Title Of Each Class Shares Outstanding As Non-Affiliates As Of
Of Voting Stock Of March 25, 2002 March 25, 2002
--------------- ----------------- --------------
Common Stock, No Par Value 84,770,703 $3,751,951,315(a)
----------
(a) Computed by reference to the closing price on the composite tape on March
25, 2002, as reported by the Wall Street Journal.
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]
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 22, 2002 are incorporated by reference
into Part III hereof.
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TABLE OF CONTENTS
Page
----
GLOSSARY.................................................................... 1
PART I
Item 1. Business........................................................ 3
Item 2. Properties...................................................... 20
Item 3. Legal Proceedings............................................... 24
Item 4. Submission of Matters to a Vote of Security Holders............. 24
Supplemental Item.
Executive Officers of the Registrant............................ 25
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters............................................. 28
Item 6. Selected Consolidated Data...................................... 29
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 33
Item 7A. Quantitative and Qualitative Disclosures about Market Risk...... 56
Item 8. Financial Statements and Supplementary Data..................... 57
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure........................................ 108
PART III
Item 10. Directors and Executive Officers of the Registrant.............. 109
Item 11. Executive Compensation.......................................... 109
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters................................. 109
Item 13. Certain Relationships and Related Transactions.................. 109
PART IV
Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
and Reports on Form 8-K......................................... 110
SIGNATURES.................................................................. 139
i
GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ADEQ - Arizona Department of Environmental Quality
AISA - Arizona Independent Scheduling Administrator
ALJ - Administrative Law Judge
ANPP - Arizona Nuclear Power Project, also known as Palo Verde
APS - Arizona Public Service Company, a subsidiary of the Company
APSES - APS Energy Services Company, Inc., a subsidiary of the Company
CC&N - Certificate of Convenience and Necessity
Cholla - Cholla Power Plant
Citizens - Citizens Communications Company
Clean Air Act - the Clean Air Act, as amended
Company - Pinnacle West Capital Corporation
DOE - United States Department of Energy
EITF - Emerging Issues Task Force
El Dorado - El Dorado Investment Company, a subsidiary of the Company
EPA - United States Environmental Protection Agency
ERMC - Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
FIP - Federal Implementation Plan
Four Corners - Four Corners Power Plant
GAAP - generally accepted accounting principles in the United States of America
ISO - California Independent System Operator
ITC - investment tax credit
KW - kilowatt, one thousand watts
KWh - kilowatt-hour, one thousand watts per hour
MW - megawatt, one million watts
MWh - megawatt-hours, one million watts per hour
1999 Settlement Agreement - Settlement Agreement among APS and other parties
related to the implementation of retail electric competition in Arizona
NOV - Notice of Violation
NRC - United States Nuclear Regulatory Commission
Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended
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Palo Verde - Palo Verde Nuclear Generating Station
PG&E - PG&E Corp.
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the
Company
PPA - purchase power agreement
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
SFAS - Statement of Financial Accounting Standards
SNWA - Southern Nevada Water Authority
SunCor - SunCor Development Company, a subsidiary of the Company
Superfund - Comprehensive Environmental Response, Compensation, and Liability
Act
T&D - transmission and distribution
WestConnect - WestConnect RTO, LLC, a proposed RTO to be formed by owners of
electric transmission lines in the southwestern United States
2
PART I
ITEM 1. BUSINESS
OVERVIEW OF OUR BUSINESS
We were incorporated in 1985 under the laws of the State of Arizona and own
all of the outstanding equity securities of APS. APS is Arizona's largest
electric utility and provides either retail or wholesale electric service to
substantially all of the state, with the major exceptions of the Tucson
metropolitan area and about one-half of the Phoenix metropolitan area. APS also
generates and, through our marketing and trading division, sells and delivers
electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our unregulated
electricity generation operations;
* APSES, which provides commodity energy and energy-related products to
key customers in competitive markets in the western United States;
* SunCor, a developer of residential, commercial, and industrial real
estate projects in Arizona, New Mexico, and Utah; and
* El Dorado, an investment firm.
We discuss each of these subsidiaries in greater detail below.
Pinnacle West's marketing and trading division sells in the wholesale
market APS and Pinnacle West Energy generation production output that is not
needed for APS' native load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. The division also purchases
electricity and natural gas in forward markets to hedge the costs of serving
retail customer demand. Additionally, the marketing and trading division,
subject to specific parameters established by the Board of Directors, 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.
At December 31, 2001, we employed about 7,600 people, including the
employees of our subsidiaries. Of these employees, 5,500 were employees of our
major subsidiary, APS, and employees assigned to jointly-owned generating
facilities for which APS serves as the generating facility manager. About 2,100
people were employed by Pinnacle West and our other subsidiaries. Our principal
executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004
(telephone 602-250-1000).
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 7 and Note 16 of Notes to Consolidated Financial
Statements in Item 8 for a discussion of our business segments.
3
ARIZONA REGULATORY DEVELOPMENTS - OVERVIEW
On September 21, 1999, the ACC approved Rules that provide a framework for
the introduction of retail electric competition in Arizona. On September 23,
1999, the ACC approved a comprehensive Settlement Agreement among APS and
various parties related to the implementation of retail electric competition in
Arizona. See "Retail Electric Competition Rules" and "1999 Settlement Agreement"
in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional
information about the 1999 Settlement Agreement and the Rules, including
outstanding legal challenges to the Rules.
Under the Rules, as modified by the 1999 Settlement Agreement, APS is
required to transfer all of its competitive electric assets and services either
to an unaffiliated party or to a separate corporate affiliate no later than
December 31, 2002. Consistent with that requirement, APS has been addressing the
legal and regulatory requirements necessary to complete the transfer of its
generation assets to Pinnacle West Energy on or before that date. In
anticipation of APS' transfer of generation assets, Pinnacle West Energy has
completed, and is in the process of developing and planning, various generation
expansion projects so that APS can reliably meet the energy requirements of its
Arizona customers.
Following APS' transfer of its fossil-fueled generation assets and the
receipt of certain regulatory approvals, Pinnacle West Energy expects to sell
its power at wholesale to Pinnacle West's marketing and trading division, which,
in turn, is expected to sell power to APS and to non-affiliated power
purchasers. In a filing with the ACC on October 18, 2001, APS requested the ACC
to:
* grant APS a partial variance from an ACC Rule that would obligate APS
to acquire all of its customers' standard-offer generation
requirements from the competitive market (with at least 50% of those
requirements coming from a "competitive bidding" process) starting in
2003; and
* approve as just and reasonable a long-term purchase power agreement
between APS and Pinnacle West.
APS requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load. See
"Proposed Rule Variance and Purchase Power Agreement" in Note 3 of Notes to
Consolidated Financial Statements in Item 8 for additional information about
APS' October 2001 filing.
On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to APS' October 2001 filing with several
other pending ACC dockets, including a "generic" docket requested by the ACC
Chairman to "determine if changed circumstances require the [ACC] to take
another look at restructuring in Arizona." Although the order consolidates
several dockets, it states that a hearing on the APS matter will commence on
April 29, 2002. The order went on to state that, contrary to APS' position, the
ALJ was construing the October 2001 filing as a request by APS to amend the 1999
ACC order that approved the 1999 Settlement Agreement.
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On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:
* The extent and manner of the ACC's involvement in monitoring market
conditions and/or mitigating the development of market power for
generation and transmission;
* The lack of guidance in the Rules regarding the mechanics of the
"competitive bidding process" referenced above;
* The consideration of alternatives to the transfer of generation assets
required by the Rules (the ACC Staff stated that such transfers would
be "unwise" at the present time and recommended that "all transfer and
separation of utilities' assets be stayed pending the completion of
the generic docket");
* The consideration of transmission constraints that could impact the
development of the wholesale power market;
* The reassessment of adjustor mechanisms for standard-offer rates in
light of problems with the development of a wholesale power market;
and
* The adequacy of customer "shopping credits" in the context of the
development of a competitive retail market (a shopping credit is the
cost a customer does not pay to a utility distribution company if the
customer obtains generation from another party).
Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between APS and
Pinnacle West.
A modification to the electric competition Rules or the 1999 Settlement
Agreement could, among other things, adversely affect APS' ability to transfer
its generation assets to Pinnacle West Energy by December 31, 2002. Pinnacle
West cannot predict the outcome of the consolidated docket or its effect on the
specific requests in APS' October 2001 filing, the Rules or the 1999 Settlement
Agreement.
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. 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 APS' October 2001 ACC filing; the outcome of
regulatory and legislative proceedings relating to the restructuring; state and
federal regulatory and legislative decisions and actions, including the price
mitigation plan adopted by the FERC in June 2001; 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; weather
variations affecting local and regional customer energy usage; conservation
programs;
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power plant performance; the successful completion of our generation expansion
program; regulatory issues associated with generation expansion, such as
permitting and licensing; our ability to compete successfully outside
traditional regulated markets (including the wholesale market); technological
developments in the electric industry; and the strength of the real estate
market in SunCor's market areas, which include Arizona, New Mexico and Utah.
REGULATION AND COMPETITION
RETAIL
The ACC regulates APS' retail electric rates and its issuance of
securities. The ACC must also approve any transfer of APS' utility property and
transactions between APS and affiliated parties. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Business Outlook
- Other Factors Affecting Our Financial Outlook" in Item 7 and Note 3 of Notes
to Consolidated Financial Statements in Item 8 for a discussion of the status of
electric industry restructuring in Arizona.
APS is subject to varying degrees of competition from other utilities in
its region (such as Tucson Electric Power Company, Southwest Gas Corporation,
and Citizens Communications Company) as well as cooperatives, municipalities,
electrical districts, and similar types of governmental organizations
(principally Salt River Project). APS also faces competition from low-cost
hydroelectric power and parties that have access to low-priced preferential
federal power and other subsidies. In addition, some customers, particularly
industrial and large commercial customers, may own and operate facilities to
generate their own electric energy requirements.
WHOLESALE
GENERAL
The FERC regulates rates for wholesale power sales and transmission
services. During 2001, approximately 54% of our electric operating revenues
resulted from such sales and services. APS transferred most of the wholesale
marketing and trading activities to Pinnacle West during 2001. Pinnacle West's
marketing and trading division sells in the wholesale market APS and Pinnacle
West Energy generation production output that is not needed for APS' native load
and, in doing so, competes with other utilities, power marketers, and
independent power producers. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 16 of Notes to
Consolidated Financial Statements in Item 8 for additional information about our
marketing and trading activities, including the historical and prospective
contribution of marketing and trading activities to our financial results. See
Note 10 of Notes to Consolidated Financial Statements in Item 8 for information
regarding our generation expansion plans.
REGIONAL TRANSMISSION ORGANIZATIONS
On December 20, 1999, the FERC issued its Order No. 2000 regarding Regional
Transmission Organizations. In its order, the FERC set minimum characteristics
and functions that must be met by utilities that participate in RTOs. The order
provides for an open, flexible structure for RTOs to meet the needs of the
market and provides for the possibility of incentive ratemaking and other
benefits for utilities that participate in an RTO.
6
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. On October 16, 2001, APS and other owners of electric
transmission lines in the Southwest filed with the FERC a request for a
declaratory order confirming that their proposal to form WestConnect RTO, LLC
would satisfy the FERC's requirements for the formation of an RTO. APS and the
other filing parties have agreed to fund the start-up of WestConnect's
operations, which are subject to FERC approval. WestConnect is projected to
begin operations in 2004. WestConnect has been structured as a for-profit RTO
and evolved from DesertSTAR, a not-for-profit corporation in which APS
participated, which was originally designed to serve as an RTO for the
southwestern United States.
The ACC retail electric competition 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, including a "generic" docket requested by the ACC Chairman
to "determine if changed circumstances require the [ACC] to take another look at
restructuring in Arizona." See "Arizona Regulatory Developments - Overview"
above and "Proposed Rule Variance and Purchase Power Agreement" in Note 3 of
Notes to Consolidated Financial Statements in Item 8 for additional information
about the consolidated ACC docket.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
Following is a discussion of the business of APS, our major subsidiary.
GENERAL
APS was incorporated in 1920 under the laws of Arizona and is Arizona's
largest electric utility, with more than 874,000 customers. APS provides either
retail or wholesale electric service to substantially all of the state of
Arizona, with the major exceptions of the Tucson metropolitan area and about
one-half of the Phoenix metropolitan area. APS also generates and, through our
marketing and trading division, sells and delivers electricity to wholesale
customers in the western United States. During 2001, no single purchaser or user
of energy accounted for more than 2.3% of consolidated electric revenues.
At December 31, 2001, APS employed approximately 5,500 people, which
includes employees assigned to jointly-owned generating facilities for which APS
serves as the generating facility manager. APS' principal executive offices are
located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone
602-250-1000).
GENERATING FUEL AND PURCHASED POWER
See "Properties - Accredited Capacity" in Item 2 for information about our
power plants by fuel types.
7
2001 ENERGY MIX
Our consolidated sources of energy during 2001 were: purchased power and
interchange (net) - 45.6% (approximately 90% of which was for wholesale power
operations); coal - 27.3%; nuclear -18.3%; gas - 8.2%; and other (includes oil,
hydro and solar) - 0.6%.
COAL SUPPLY
CHOLLA Cholla is a coal-fired power plant located in northeastern Arizona.
It is a jointly-owned facility operated by APS. APS purchases most of Cholla's
coal requirements from a coal supplier that mines all of the coal under a
long-term lease of coal reserves owned by the Navajo Nation, the federal
government, and private landholders. Cholla has sufficient coal under current
contracts to ensure a reliable fuel supply through 2005. APS purchases a portion
of Cholla's coal requirements on the spot market to take advantage of
competitive pricing options. Following expiration of current contracts, APS
believes that numerous competitive fuel supply options will exist to ensure
continuous plant operation. APS expects the current supplier to continue to
provide most of Cholla's low sulfur coal requirements through the current
contract. APS believes that there are sufficient reserves of low sulfur coal
available from other suppliers to ensure the continued operation of Cholla for
its useful life.
FOUR CORNERS Four Corners is a coal-fired power plant located in the
northwest corner of New Mexico. It is a jointly-owned facility operated by APS.
APS purchases all of Four Corners' coal requirements from a supplier with a
long-term lease of coal reserves owned by the Navajo Nation. Four Corners is
under contract for coal through 2004, with options to extend the contract
through the plant site lease expiration in 2016. The Four Corners lease and
related federal rights-of-way and easements include covenants to prevent the
Navajo Nation from taxing or assessing Four Corners or the fuel used by the
facility. These covenants expired in July 2001, and the Navajo Nation has
assessed taxes in the form of a Business Activity Tax and a Possessory Interest
Tax on the coal supplier and the plant. The tax paid by the coal supplier is
passed on to the Four Corners participants through the fuel supply agreement.
These amounts have been largely mitigated due to a New Mexico law which provides
tax credits for coal purchased on the Navajo reservation. APS has contested, on
jurisdictional grounds, the right of the Navajo Nation to assess these taxes on
the plant. APS is currently engaged in negotiations with the Navajo Nation on a
settlement that will provide for payments to the Navajo Nation that will allow
the continued economic operation of Four Corners. However, a settlement has not
been finalized and APS cannot currently predict the outcome of this matter.
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 - Accredited Capacity" in Item 2 for information about APS'
ownership interest in Cholla, Four Corners, and the Navajo Generating Station.
See Note 10 of Notes to
8
Consolidated Financial Statements in Item 8 for information regarding our coal
mine reclamation obligations.
NATURAL GAS SUPPLY
APS purchases the majority of its natural gas requirements for its
gas-fired plants under contracts with a number of natural gas suppliers. APS'
natural gas supply is transported pursuant to a firm transportation service
contract with El Paso Natural Gas Company (see description below). We anticipate
that the natural gas requirements for our generation expansion plans (see Note
10 of Notes to Consolidated Financial Statements in Item 8) will be met with
these contracts. We continue to analyze the market to determine the most
favorable source and method of meeting our natural gas requirements.
The gas supply for APS and Pinnacle West Energy gas-fired facilities
located, and to be located (see Note 10 of Notes to Consolidated Financial
Statements in Item 8), in Pinal, Maricopa and Yuma Counties in Arizona, 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 APS' (and other
companies with the same contract type) gas transportation rights could be
significantly impacted. Various parties, including APS and Pinnacle West Energy,
have challenged this allocation as being inconsistent with El Paso Natural Gas
Company's existing contractual obligations and the 1996 settlement. The FERC has
scheduled a public conference in April 2002 to discuss an appropriate mechanism
for allocating capacity on the El Paso Natural Gas Company pipeline. We cannot
currently predict the outcome of this matter.
NUCLEAR FUEL SUPPLY
PALO VERDE FUEL CYCLE Palo Verde is a nuclear power plant located about 50
miles west of Phoenix, Arizona. It is a jointly-owned facility operated by APS.
The fuel cycle for Palo Verde is comprised of the following stages:
* mining and milling of uranium ore to produce uranium concentrates;
* conversion of uranium concentrates to uranium hexafluoride;
* enrichment of uranium hexafluoride;
* fabrication of fuel assemblies;
* utilization of fuel assemblies in reactors; and
* storage and disposal of spent fuel.
The Palo Verde participants have contracted for sufficient uranium
concentrates to meet operational requirements through 2002. Spot purchases on
the uranium market will be made, as appropriate, in lieu of any uranium that
might be obtained through contractual options. Existing uranium concentrates
contracts and options could be utilized to meet approximately 67% of
requirements in 2003.
The Palo Verde participants have contracts and options for uranium
conversion services that could be utilized to meet approximately 100% of
requirements in 2002 and 2003. The Palo Verde
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participants have an enrichment services contract and an enriched uranium
product contract that furnish enrichment services required for the operation of
the three Palo Verde units through 2003.
The Palo Verde participants have a new enriched uranium product contract
that will furnish up to 100% of Palo Verde's requirements for uranium
concentrates, conversion services and enrichment services from 2004 through
2008. This contract could also provide 100% of enrichment services in 2009 and
2010.
In addition, existing contracts will provide 100% of fuel assembly
fabrication services until at least 2015 for each Palo Verde unit.
SPENT NUCLEAR FUEL AND WASTE DISPOSAL Nuclear power plant operators are
required to enter into spent fuel disposal contracts with DOE, and 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 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 DOE's
delay, a number of utilities filed damages lawsuits against 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. A Congressional decision on this issue is expected sometime during
mid-summer 2002. We cannot currently predict what further steps will be taken in
this area.
Facility funding is a further complication. While all nuclear utilities pay
into a so-called nuclear waste fund an amount calculated on the basis of the
output of their respective plants, the annual Congressional appropriations for
the permanent repository have been for amounts less than the amounts paid into
the waste fund (the balance of which is being used for other purposes).
APS has existing fuel storage pools at Palo Verde and is in the process of
completing construction of a new facility for on-site dry storage of spent fuel.
With the existing storage pools and the addition of the new facility, APS
believes that spent 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 Consolidated Financial Statements in Item 8 for a discussion
of interim spent fuel storage costs.
Although some low-level waste has been stored on-site in a low-level waste
facility, APS is currently shipping low-level waste to off-site facilities. APS
currently believes that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
APS believes that scientific and financial aspects of the issues of spent
fuel and low-level waste storage and disposal can be resolved satisfactorily.
However, APS acknowledges that their ultimate resolution in a timely fashion
will require political resolve and action on national and
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regional scales which APS is less able to predict. APS expects to vigorously
protect and pursue its rights related to this matter.
PURCHASED POWER AGREEMENTS
In addition to that available from its own generating capacity (see
"Properties" in Item 2), APS purchases electricity under various arrangements.
One of the most important of these is a long-term contract with Salt River
Project. The amount of electricity available to APS is based in large part on
customer demand within certain areas now served by APS pursuant to a related
territorial agreement. The generating capacity available to APS pursuant to the
contract was 329 MW from January through May 2001, and starting in June 2001, as
part of a broad renegotiation of the agreement in light of the electric industry
transition to a competitive generation market, it changed to 336 MW. In 2001,
APS received approximately 1,741,000 MWh of energy under the contract and paid
about $81.5 million for capacity availability and energy received. This contract
may be canceled by Salt River Project on three years' notice, given no earlier
than December 31, 2003. APS may also cancel the contract on five years' notice,
given no earlier than December 31, 2006.
In September 1990, APS entered into a thirty-year seasonal capacity
exchange agreement with PacifiCorp. Under this agreement, APS receives
electricity from PacifiCorp during the summer peak season (from May 15 to
September 15) and APS returns electricity to PacifiCorp during the winter season
(from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW
of capacity and a related amount of energy available to it under the agreement
for their respective seasons. In 2001, APS received approximately 571,000 MWh of
energy under the capacity exchange. APS must also make additional offers of
energy to PacifiCorp each year through October 31, 2020. Pursuant to this
requirement, during 2001, PacifiCorp received offers of 1,112,300 MWh and
purchased about 434,000 MWh.
CONSTRUCTION PROGRAM
During the years 1999 through 2001, APS incurred approximately $1.3 billion
in capital expenditures. APS' capital expenditures for the years 2002 through
2004 are expected to be primarily for expanding transmission and distribution
capabilities to meet growing customer needs, for upgrading existing utility
property, and for environmental purposes. APS' capital expenditures were $471
million in 2001. APS' capital expenditures, including expenditures for
environmental control facilities, for the years 2002 through 2004 have been
estimated as follows:
(dollars in millions)
BY YEAR BY MAJOR FACILITIES
----------------------- -----------------------------------------
2002 $ 498 Production $ 149
2003 271 Transmission and Distribution 900
2004 280 ------
------ Total $1,049
Total $1,049 ======
======
The amounts for 2002 through 2004 assume that APS' generation (production)
assets are transferred to Pinnacle West Energy as of December 31, 2002. These
amounts exclude capitalized interest costs and include capitalized property
taxes and approximately $30 million (only in 2002) for nuclear fuel. APS
conducts a continuing review of its construction program.
11
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Capital Needs and Resources" in Item 7 for additional
information about APS' construction program and for information about Pinnacle
West Energy's generating expansion plans.
MORTGAGE REPLACEMENT FUND REQUIREMENTS
So long as any of its first mortgage bonds are outstanding, APS is required
for each calendar year to deposit with the trustee under its mortgage cash in a
formularized amount related to net additions to its mortgaged utility plant. APS
may satisfy all or any part of this "replacement fund" requirement by using
redeemed or retired bonds, net property additions, or property retirements. For
2001, the replacement fund requirement amounted to approximately $155 million.
Certain of the bonds APS has issued under the mortgage that are callable prior
to maturity are redeemable at their par value plus accrued interest with cash
APS deposits in the replacement fund. These call provisions are subject in many
cases to a period of time after the original issuance of the bonds during which
they may not be redeemed in this manner. See Notes 6 and 18 of Notes to
Consolidated Financial Statements in Item 8 for information regarding APS' first
mortgage bonds.
ENVIRONMENTAL MATTERS
EPA ENVIRONMENTAL REGULATION
CLEAN AIR ACT We are subject to a number of requirements under the Clean
Air Act. The Clean Air Act addresses, among other things:
* "acid rain";
* visibility in certain specified areas;
* hazardous air pollutants; and
* areas that have not attained national ambient air quality standards.
With respect to "acid rain," the Clean Air Act established a system of
sulfur dioxide emissions "allowances" to offset each ton of sulfur dioxide
emitted by affected power plants. Based on EPA allowance allocations, we will
have sufficient allowances to permit continued operation of our plants at
current levels without installing additional equipment. The Clean Air Act also
requires the EPA to set nitrogen oxides emissions limitations for certain
coal-fired units. The EPA rule allows emissions from all units in a plant to be
averaged to demonstrate compliance with the emission limitation. Currently,
nitrogen oxides emissions from all of our units are within the limitations
specified under the EPA's rules. We do not currently expect this rule to have a
material impact on our financial position, results of operations, or liquidity.
The Clean Air Act required the EPA to establish a Grand Canyon Visibility
Transport Commission to complete a study on visibility impairment in sixteen
"Class I Areas" (large national parks and wilderness areas) on the Colorado
Plateau. The Navajo Generating Station, Cholla, and Four Corners are located
near several Class I Areas on the Colorado Plateau. The Visibility Commission
completed its study and on June 10, 1996 submitted its final recommendations to
the EPA.
On April 22, 1999, the EPA announced final regional haze rules. These new
regulations require states to submit, by 2008, implementation plans to eliminate
all man-made emissions causing
12
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 is currently reviewing an "Annex" to the Visibility Commission
recommendations that specifies the regional sulfur dioxide emission milestones.
The EPA's approval of the Annex would allow the Visibility Commission 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
revised implementation plans in 2008 to address visibility in those Class I
Areas which were not included in the Visibility Commission process. Because the
Annex is not final and Arizona and the Navajo Nation have the discretion to
choose between the national or the alternate options, the actual impact on APS
cannot be determined at this time.
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. A federal court determined that the EPA's promulgation of the National
Ambient Air Quality Standards violated the constitutional prohibition on
delegation of legislative power. The court remanded the ozone standard, vacated
the particulate matter standard, and invited the parties that challenged the
standards to brief the court on vacating or remanding the very fine particulates
standard. On February 27, 2001, the U.S. Supreme Court overruled the federal
court's ruling. The Supreme Court further held that the EPA could not consider
the cost of reducing harmful emissions when setting air quality standards.
However, the Supreme Court found the EPA implementation policy for the revised
ozone standards to be unlawful, and remanded this issue for consideration along
with the other preserved challenges to the National Ambient Air Quality
Standards. Because the actual level of emissions controls, if any, for any unit
cannot be determined at this time, APS currently cannot estimate the capital
expenditures, if any, which would result from the final rules. However, APS does
not currently expect these rules to have a material adverse effect on its
financial position, results of operations, or liquidity.
With respect to hazardous air pollutants emitted by electric utility steam
generating units, the EPA recently determined that mercury emissions and other
hazardous air pollutants from coal and oil-fired power plants will be regulated.
We expect that the EPA will propose specific rules for this purpose in 2003 and
finalize them by 2004, with compliance required by 2008. Because the ultimate
requirements that the EPA may impose are not yet known, we cannot currently
estimate the capital expenditures, if any, which may be required.
13
Certain aspects of the Clean Air Act may require APS to make related
expenditures, such as permit fees. APS does not expect any of these expenditures
to have a material impact on its financial position, results of operations, or
liquidity.
FEDERAL IMPLEMENTATION PLAN In September 1999, the EPA proposed a FIP to
set air quality standards at certain power plants, including the Navajo
Generating Station and Four Corners. The comment period on this proposal ended
in November 1999. The FIP is similar to current Arizona regulation of the Navajo
Generating Station and New Mexico regulation of Four Corners, with minor
modifications. APS does not currently expect the FIP to have a material impact
on its financial position, results of operations, or liquidity.
SUPERFUND The Comprehensive Environmental Response, Compensation, and
Liability Act (Superfund) establishes liability for the cleanup of hazardous
substances found contaminating the soil, water, or air. Those who generated,
transported, or disposed of hazardous substances at a contaminated site are
among those who are potentially responsible parties. PRPs may be strictly, and
often jointly and severally, liable for clean-up. The EPA had previously advised
APS that the EPA considers APS to be a PRP in the Indian Bend Wash Superfund
Site, South Area. APS' Ocotillo Power Plant is located in this area. Based on
the information to date, including available insurance coverage and an EPA
estimate of cleanup costs, APS does not expect this matter to have a material
impact on its financial position, results of operations, or liquidity.
MANUFACTURED GAS PLANT SITES APS is currently investigating properties
which it now owns or which were previously owned by it or its corporate
predecessors, that were at one time sites of, or sites associated with,
manufactured gas plants. The purpose of this investigation is to determine if:
* waste materials are present;
* such materials constitute an environmental or health risk; and
* APS has any responsibility for remedial action.
Where appropriate, APS has begun clean-up of certain of these sites. APS
does not expect these matters to have a material adverse effect on its financial
position, results of operations, or liquidity.
ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY
ADEQ issued to APS Notices of Violation (NOV), dated September 25, 2001 and
October 15, 2001 alleging, among other things, burning of unauthorized materials
and storage of hazardous waste without a permit at the Cholla Power Plant. Each
Notice of Violation requires APS to achieve and document compliance with
specific environmental requirements. APS has submitted responses to the NOVs as
well as additional information requested by the agency. To date, ADEQ has not
sought penalties or taken other enforcement actions against APS. APS does not
expect these matters to have a material adverse effect on its financial
position, results of operations, or liquidity.
NAVAJO NATION ENVIRONMENTAL ISSUES
Four Corners and the Navajo Generating Station are located on the Navajo
Reservation and are held under easements granted by the federal government as
well as leases from the Navajo Nation. APS is the Four Corners operating agent.
APS owns a 100% interest in Four Corners Units 1, 2, and 3, and a 15% interest
14
in Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating
Station Units 1, 2, and 3.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the
Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts
purport to give the Navajo Nation Environmental Protection Agency authority to
promulgate regulations covering air quality, drinking water, and pesticide
activities, including those that occur at Four Corners and the Navajo Generating
Station. The Four Corners and Navajo Generating Station participants dispute
that purported authority, and by separate letters dated October 12 and October
13, 1995, the Four Corners participants and the Navajo Generating Station
participants requested the United States Secretary of the Interior to resolve
their dispute with the Navajo Nation regarding whether or not the Navajo Acts
apply to operations of Four Corners and the Navajo Generating Station. On
October 17, 1995, the Four Corners participants and the Navajo Generating
Station participants each filed a lawsuit in the District Court of the Navajo
Nation, Window Rock District, seeking, among other things, a declaratory
judgment that:
* their respective leases and federal easements preclude the application
of the Navajo Acts to the operations of Four Corners and the Navajo
Generating Station; and
* the Navajo Nation and its agencies and courts lack adjudicatory
jurisdiction to determine the enforceability of the Navajo Acts as
applied to Four Corners and the Navajo Generating Station.
On October 18, 1995, the Navajo Nation and the Four Corners and Navajo
Generating Station participants agreed to indefinitely stay these proceedings so
that the parties may attempt to resolve the dispute without litigation. The
Secretary and the Court have stayed these proceedings pursuant to a request by
the parties. APS cannot currently predict the outcome of this matter.
In February 1998, the EPA issued regulations identifying those Clean Air
Act provisions for which it is appropriate to treat Indian tribes in the same
manner as states. The EPA has announced that it has not yet determined whether
the Clean Air Act would supersede pre-existing binding agreements between the
Navajo Nation and the Four Corners participants and the Navajo Generating
Station participants that could limit the Navajo Nation's environmental
regulatory authority over the Navajo Generating Station and Four Corners. APS
believes that the Clean Air Act does not supersede these pre-existing
agreements. APS cannot currently predict the outcome of this matter.
On August 8, 2000, the EPA signed an Eligibility Determination for the
Navajo Nation for Grants Under Section 105 of the Clean Air Act in which the EPA
determined that the Navajo Nation was eligible to receive grants under the Clean
Air Act. On September 8, 2001, after learning of the eligibility determination,
APS filed a Petition for Review of the EPA's decision in the United States Court
of Appeals for the Ninth Circuit in order to ensure that the EPA's August 2000
determination not be construed to constitute a determination of the Navajo
Nation's authority to regulate Four Corners and the Navajo Generating Station.
APS V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, No. 01-71577. APS, the EPA
and other parties have requested that the Court stay any further briefing while
they negotiate a settlement.
15
In April 2000, the Navajo Tribal Council approved operating permit
regulations under the Navajo Nation Air Pollution Prevention and Control Act. We
believe that the regulations fail to recognize that the Navajo Nation did not
intend to assert jurisdiction over Four Corners and the Navajo Generating
Station. On July 12, 2000, the Four Corners participants and the Navajo
Generating Station participants each filed a petition with the Navajo Supreme
Court for review of the operating permit regulations. We cannot currently
predict the outcome of this matter.
WATER SUPPLY
Assured supplies of water are important for our generating plants. At the
present time, APS has adequate water to meet its needs. However, conflicting
claims to limited amounts of water in the southwestern United States have
resulted in numerous court actions.
Both groundwater and surface water in areas important to APS' operations
have been the subject of inquiries, claims, and legal proceedings which will
require a number of years to resolve. APS is one of a number of parties in a
proceeding before a state court in New Mexico to adjudicate rights to a stream
system from which water for Four Corners is derived. (STATE OF NEW MEXICO, IN
THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY
OF FARMINGTON, UTAH INTERNATIONAL, INC., ET AL., SAN JUAN COUNTY, NEW MEXICO,
District Court No. 75-184). An agreement reached with the Navajo Nation in 1985,
however, provides that if Four Corners loses a portion of its rights in the
adjudication, the Navajo Nation will provide, for a then-agreed upon cost,
sufficient water from its allocation to offset the loss.
A summons served on APS in early 1986 required all water claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987, in an action pending in Maricopa County, Arizona, Superior
Court. (IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA
RIVER SYSTEM AND SOURCE, Supreme Court Nos. WC-79-0001 through WC 79-0004
(Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos.
W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the
geographic area subject to the summons. APS' rights and the rights of the Palo
Verde participants to the use of groundwater and effluent at Palo Verde are
potentially at issue in this action. As project manager of Palo Verde, APS filed
claims that dispute the court's jurisdiction over the Palo Verde participants'
groundwater rights and their contractual rights to effluent relating to Palo
Verde. Alternatively, APS seeks confirmation of such rights. Three of APS' other
power plants and one of Pinnacle West Energy's power plants are also located
within the geographic area subject to the summons. APS' claims dispute the
court's jurisdiction over its groundwater rights with respect to these plants.
Alternatively, APS seeks confirmation of such rights. In November 1999, the
Arizona Supreme Court issued a decision confirming that certain groundwater
rights may be available to the federal government and Indian tribes. In
addition, in September 2000, the Arizona Supreme Court issued a decision
affirming the lower court's criteria for resolving groundwater claims.
Litigation on both of these issues will continue in the trial court. No trial
date concerning APS' water rights claims has been set in this matter.
APS has also filed claims to water in the Little Colorado River Watershed
in Arizona in an action pending in the Apache County, Arizona, Superior Court.
(IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE LITTLE
COLORADO RIVER SYSTEM AND SOURCE, Supreme Court No. WC-79-0006 WC-6, Apache
County No. 6417). APS' groundwater resource utilized at Cholla is within the
geographic area subject to the adjudication and is therefore potentially at
issue in the case. APS' claims dispute the court's jurisdiction over its
groundwater rights. Alternatively, APS seeks
16
confirmation of such rights. A number of parties are in the process of
settlement negotiations with respect to certain claims in this matter. Other
claims have been identified as ready for litigation in motions filed with the
court. No trial date concerning APS' water rights claims has been set in this
matter.
Although the foregoing matters remain subject to further evaluation, APS
expects that the described litigation will not have a material adverse impact on
its financial position, results of operations or liquidity.
BUSINESS OF PINNACLE WEST ENERGY CORPORATION
Pinnacle West Energy was incorporated in 1999 under the laws of the State
of Arizona and is engaged principally in the business of the development of
generating plants and production of wholesale electricity. Pinnacle West Energy
is the subsidiary through which we conduct our unregulated generation
operations. Pinnacle West Energy had approximately 65 employees as of December
31, 2001. Pinnacle West Energy's principal offices are located at 400 North
Fifth Street, Phoenix, Arizona 85004 (telephone (602) 250-4145).
Pinnacle West Energy's capital expenditures in 2001 were $533 million.
Projected capital expenditures are $411 million in 2002; $362 million in 2003;
and $212 million in 2004. The amounts include about $107 million in 2003 and
$99 million in 2004 for capital improvements to existing generating facilities.
These amounts exclude capitalized interest costs, and include capitalized
property taxes and (only in 2003 and 2004) approximately $30 million a year for
nuclear fuel. These amounts assume that APS' generation assets are transferred
to Pinnacle West Energy as of December 31, 2002. In 2004, based on an agreement
with SNWA, we expect SNWA to reimburse Pinnacle West Energy approximately $100
million of Pinnacle West Energy's cumulative capital expenditures on the
Silverhawk project in exchange for the completion of SNWA's purchase of a 25%
interest in the project. At December 31, 2001, Pinnacle West Energy had total
assets of $781 million.
Pinnacle West Energy reported net income of $18 million in 2001 and a net
loss of $2 million in 2000.
See "Arizona Regulatory Developments Overview" above and Note 3 of Notes to
Consolidated Financial Statements in Item 8 for information regarding the
pending transfer of APS' generation assets to Pinnacle West Energy. See Note 10
of Notes to Consolidated Financial Statements in Item 8 for information
regarding Pinnacle West Energy's generation expansion plans.
BUSINESS OF APS ENERGY SERVICES COMPANY, INC.
APSES was incorporated in 1998 under the laws of the State of Arizona and
provides commodity energy and energy-related products to key customers in
competitive markets in the western United States. APSES had approximately 65
employees as of December 31, 2001. APSES' principal offices are located at 400
East Van Buren Street, Phoenix, Arizona 85004 (telephone (602) 250-5000).
During the first full two years of operations, APSES' pretax net losses
were about $10 million in 2001 and $13 million in 2000. Income tax benefits
related to APSES' pretax losses are
17
recorded by Pinnacle West because of filing consolidated income tax returns. At
December 31, 2001, APSES had total assets of $70 million.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
SunCor was incorporated in 1965 under the laws of the State of Arizona and
is a developer of residential, commercial and industrial real estate projects in
Arizona, New Mexico and Utah. The principal executive offices of SunCor are
located at 3838 North Central, Suite 1500, Phoenix, Arizona 85012 (telephone
602-285-6800). SunCor and its subsidiaries had approximately 900 full and
part-time employees at December 31, 2001.
SunCor's assets consist primarily of land with improvements, commercial
buildings, and other real estate investments. SunCor's largest project is the
Palm Valley master-planned community, which has approximately 7,250 acres
remaining to be developed west of Phoenix in the area of the towns of Avondale,
Goodyear, and Litchfield Park, Arizona. SunCor has completed the master plan for
development of Palm Valley. There has been significant residential and
commercial development at Palm Valley by SunCor and by other developers that
have acquired land from SunCor or entered into joint ventures with SunCor. Palm
Valley currently includes residential subdivisions with golf courses, hotels,
restaurants, commercial projects, retail stores, medical facilities, elementary
and secondary schools, a community college, and a retirement community, known as
PebbleCreek.
SunCor projects under development include seven master-planned communities
and several commercial projects. The commercial projects and five of the
master-planned communities are in Arizona. Other master-planned communities are
located near St. George, Utah, and Santa Fe, New Mexico. Several of the
master-planned communities and commercial projects are joint ventures with other
developers, financial partners, or landowners. SunCor began two new projects in
2001 which will commence sales and leasing activity in 2002:
* Hayden Ferry Lakeside - an 18-acre, mixed-use commercial and
residential project located in Tempe, Arizona will open its first
office building in mid-2002; and
* StoneRidge - an 1,850-acre, master-planned community with a golf
course in Prescott Valley, Arizona will open its initial phase of
homes and lots sales and its golf course in 2002.
For the past three years, SunCor's operating revenues were about: $169
million in 2001; $158 million in 2000; and $130 million in 1999. For those same
periods, SunCor's net income was about: $3 million in 2001; $11 million in 2000;
and $6 million in 1999.
SunCor's capital needs consist primarily of capital expenditures for land
development and home construction for SunCor's home-building subsidiary, Golden
Heritage Homes, Inc. SunCor's capital expenditures were approximately $80
million in 2001. On the basis of projects currently under development, SunCor
expects its capital needs over the next three years to be: $79 million in 2002;
$48 million in 2003; and $52 million in 2004.
At December 31, 2001, SunCor had total assets of about $518 million. See
Note 6 of Notes to Consolidated Financial Statements in Item 8 for information
regarding SunCor's long-term debt.
18
SunCor intends to continue its focus on real estate development of
master-planned communities, mixed-use residential, commercial, office, and
industrial projects.
See "Legal Proceedings" in Item 3 for information regarding a SunCor
litigation matter that was settled during 2001.
BUSINESS OF EL DORADO INVESTMENT COMPANY
El Dorado was incorporated in 1983 under the laws of the State of Arizona
and is an investment firm. El Dorado's short-term goal is to prudently realize
the value of its existing investments. On a long-term basis, we may use El
Dorado, when appropriate, as our subsidiary for investments that are strategic
to our principal business of generating, distributing, and marketing
electricity. At December 31, 2001, El Dorado held various investments,
including: a company specializing in nuclear spent fuel technology, a company
specializing in digital and fiber optic solutions for the control and
measurement of high voltage electric power, an interest in a venture capital
partnership, and interests in two professional sports teams. El Dorado's offices
are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone
602-250-3517).
For the past three years, El Dorado's net income was about: $0.2 million in
2001; $2 million in 2000; and $11 million in 1999. At December 31, 2001, El
Dorado had total assets of $23 million.
19
ITEM 2. PROPERTIES
ACCREDITED CAPACITY
APS
APS' present generating facilities have an accredited capacity 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(1)
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................................................. 6,585
----------
Total APS facilities............................................ 3,982,885
----------
PINNACLE WEST ENERGY
Pinnacle West Energy's present generating facility has an accredited
capacity as follows:
Gas or Oil:
One combined cycle unit.................................... 112,000(2)
----------
Total Consolidated Accredited Capacity 4,094,885
==========
----------
(1) Does not include West Phoenix steam units (108,300 kW), which were removed
from mothballs and placed in service for 2001 summer reliability.
(2) See Note 10 of Notes to Consolidated Financial Statements in Item 8 for
information regarding Pinnacle West Energy's generation expansion plans.
20
RESERVE MARGIN
APS' 2001 peak one-hour demand on its electric system was recorded on July
2, 2001 at 5,687,200 kW, compared to the 2000 peak of 5,478,500 kW recorded on
July 25, 2000. Taking into account additional capacity then available to APS
under long-term purchase power contracts as well as APS' and Pinnacle West
Energy's generating capacity, APS' capability of meeting system demand on July
2, 2001, amounted to 5,180,600 kW, for an installed reserve margin of (11.1%).
The power actually available to APS from its resources fluctuates from time to
time due in part to planned outages and technical problems. The available
capacity from sources actually operable at the time of the 2001 peak amounted to
3,234,500 kW, for a margin of (43.3%). Firm purchases, including short-term
seasonal purchases and unit contingent purchases, totaling 2,490,000 kW were in
place at the time of the peak ensuring the ability to meet the load requirement,
with an actual reserve margin of 1.1%.
See "Business of Arizona Public Service Company - Purchased Power
Agreements" in Item 1 for information about certain of APS' long-term power
agreements.
PLANT SITES LEASED FROM NAVAJO NATION
The Navajo Generating Station and Four Corners are located on land held
under easements from the federal government and also under leases from the
Navajo Nation. These are long-term agreements with options to extend, and we do
not believe that the risk with respect to enforcement of these easements and
leases is material. The majority of coal contracted for use in these plants and
certain associated transmission lines are also located on Indian reservations.
See "Generating Fuel and Purchased Power - Coal Supply" in Item 1.
PALO VERDE NUCLEAR GENERATING STATION
PALO VERDE LEASES
See Note 8 of Notes to Consolidated Financial Statements in Item 8 for a
discussion of three sale-leaseback transactions related to Palo Verde Unit 2.
REGULATORY
Operation of each of the three Palo Verde units requires an operating
license from the NRC. The NRC issued full power operating licenses for Unit 1 in
June 1985, Unit 2 in April 1986, and Unit 3 in November 1987. The full power
operating licenses, each valid for a period of approximately 40 years, authorize
APS, as operating agent for Palo Verde, to operate the three Palo Verde units at
full power.
NUCLEAR DECOMMISSIONING COSTS
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." Other mechanisms are prescribed, including prepayment, if the
requirements for exclusive reliance on the external sinking fund mechanism are
not met. APS currently relies on the external sinking fund mechanism to meet the
NRC financial assurance requirements for its interests in Palo Verde Units 1, 2,
21
and 3. The decommissioning costs of Palo Verde Units 1, 2, and 3 are currently
included in APS' ACC jurisdictional rates. ACC retail electric competition Rules
provide that decommissioning costs would be recovered through a non-bypassable
"system benefits" charge, which would allow APS to maintain its external sinking
fund mechanism. See Note 11 of Notes to Consolidated Financial Statements in
Item 8 for additional information about our nuclear decommissioning costs. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Business Outlook - Others Factors Affecting Our Financial Outlook"
in Item 7 and Note 3 of Notes to Consolidated Financial Statements in Item 8 for
additional information about the ACC retail electric competition Rules and the
legal challenges to these Rules.
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 10 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the insurance
maintained by the Palo Verde participants, including APS, for Palo Verde.
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.
See Notes 6, 8, and 9 of Notes to Consolidated Financial Statements in Item
8 with respect to APS' property not held in fee or held subject to any major
encumbrance.
INFORMATION REGARDING PROPERTIES OF PINNACLE WEST ENERGY AND SUNCOR
See "Business of Pinnacle West Energy Corporation" and "Business of SunCor
Development Company" for information regarding Pinnacle West Energy's and
SunCor's properties.
22
[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 plant, 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; and the Palo Verde
Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona
(each of which plants is reflected on such map as being jointly owned with other
utilities), as well as the Ocotillo Power Plant and West Phoenix Power Plant,
each located near Phoenix, Arizona, and the Saguaro Power Plant, located near
Tucson, Arizona. Pinnacle West Energy's power plant shown on such map is Unit 4
of the West Phoenix 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.
23
ITEM 3. LEGAL PROCEEDINGS
See "Environmental Matters" and "Water Supply" in Item 1 in regard to
pending or threatened litigation and other disputes. See Note 3 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of competition and
the ACC retail electric competition Rules and related litigation. In December
1999, APS filed a lawsuit to protect its legal rights regarding the Rules, and
in the complaint APS asked the Court for (i) a judgment vacating the retail
electric competition Rules, (ii) a declaratory judgment that the Rules are
unlawful because, among other things, they were entered into without proper
legal authorization, and (iii) a permanent injunction barring the ACC from
enforcing or implementing the Rules and from promulgating any other regulations
without lawful authority. ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION
COMMISSION, CV 99-21907. On August 28, 1998, APS filed two lawsuits to protect
its legal rights under the stranded cost order and in its complaints APS asked
the Court to vacate and set aside the order. ARIZONA PUBLIC SERVICE COMPANY V.
ARIZONA CORPORATION COMMISSION, CV 98-15728. ARIZONA PUBLIC SERVICE COMPANY V.
ARIZONA CORPORATION COMMISSION, 1-CA-CC-98-0008. Consistent with its obligations
under the 1999 Settlement Agreement, on January 7, 2002, APS and the ACC filed
in Maricopa County, Arizona, Superior Court a stipulation to dismiss the
foregoing litigation. On January 15, 2002, a Maricopa County Superior Court
judge issued an order dismissing the litigation. See "1999 Settlement Agreement"
in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional
information about the 1999 Settlement Agreement and the resolution of legal
challenges to the 1999 Settlement Agreement.
See Note 10 of Notes to Consolidated Financial Statements in Item 8 for
information relating to FERC proceedings on California energy market issues and
a claim by Citizens that APS overcharged Citizens under a power service
agreement.
On March 15, 2001, a jury returned a verdict against SunCor in the amount
of $28.6 million, $25.7 million of which represented a punitive damage award, in
a lawsuit in Maricopa County, Arizona, Superior Court entitled SUNCOR
DEVELOPMENT COMPANY V. BERGSTROM CORPORATION, CV 98-11472. The verdict was based
on the Bergstrom Corporation's claims that it was defrauded in connection with
the acquisition of approximately ten acres of land in a SunCor commercial
development and a subsequent settlement agreement relating to those claims. On
December 14, 2001, the Court ruled that the jury award was constitutionally
excessive and reduced the punitive damage award to $5 million. Following this
ruling, SunCor settled the matter for an amount that did not have a material
adverse impact on the Company's 2001 financial position, results of operations
or liquidity.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
24
SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers are as follows:
Name Age at March 1, 2002 Position(s) at March 1, 2002
---- -------------------- ----------------------------
William J. Post 51 Chairman of the Board and
Chief Executive Officer (1)
Jack E. Davis 55 President and President, APS Energy
Delivery and Sales (1)
Robert S. Aiken 45 Vice President, Federal Affairs
John G. Bohon 56 Vice President, Corporate Services &
Human Resources
Dennis L. Brown 51 Vice President and Chief Information
Officer
Armando B. Flores 58 Executive Vice President, Corporate
Business Services
Edward Z. Fox 48 Vice President, Communications,
Environment & Safety
Chris N. Froggatt 44 Vice President & Controller
Barbara M. Gomez 47 Treasurer
David A. Hansen 42 Vice President, Bulk Power
Marketing and Trading
James M. Levine 52 Executive Vice President, APS
Generation and COO, Pinnacle West
Energy
Nancy C. Loftin 48 Vice President & General Counsel
Michael V. Palmeri 43 Vice President, Finance
Donald G. Robinson 48 Vice President, Regulation and
Planning
Martin L. Shultz 57 Vice President, Government Affairs
William L. Stewart 58 President, APS Generation and
President, Pinnacle West Energy (1)
Steven M. Wheeler 53 Senior Vice President, Transmission,
Regulation and Planning
Faye Widenmann 53 Vice President and Secretary
----------
(1) member of the Board of Directors
The executive officers of Pinnacle West are elected no less often than
annually and may be removed by the Board of Directors at any time. The terms
served by the named officers in their current positions and the principal
occupations (in addition to those stated in the table) of such officers for the
past five years have been as follows:
Mr. Post was elected Chairman of the Board effective February 2001, and
Chief Executive Officer effective February 1999. He has served as an officer of
Pinnacle West since 1995 in the following capacities: from August 1999 to
February 2001 as President; from February 1997 to February 1999 as President;
and from June 1995 to February 1997 as Executive Vice President. Mr. Post is
also Chairman of the Board (since February 2001) and Chief Executive Officer
25
(since February 1997) of APS. He was President of APS from February 1997 until
October 1998. In October 1998, he resigned as President and maintained the
position of Chief Executive Officer of APS. He was APS' Chief Operating Officer
(September 1994-February 1997). Mr. Post is also a director of APS, Pinnacle
West Energy, Blue Cross-Blue Shield of Arizona, Nuclear Electric Insurance, Ltd.
(NEIL), and Phelps Dodge Corporation.
Mr. Davis was elected to his present position effective February 2001.
Prior to that time he was Chief Operating Officer and Executive Vice President
of Pinnacle West (April 2000-February 2001), Executive Vice President,
Commercial Operations of APS (September 1996-October 1998) and Vice President,
Energy Delivery and Sales, Generation and Transmission of APS (June
1993-September 1996). Mr. Davis is President of APS (since October 1998) and a
director of APS and Pinnacle West Energy.
Mr. Aiken was elected to his present position in July 1999. Prior to that
time he was Pinnacle West's Manager, Federal Affairs (November 1986-July 1999).
Mr. Bohon was elected to his present position in July 1999. Prior to that
time he was Vice President, Corporate Services and Human Resources of APS
(October 1998-July 1999), Vice President, Procurement of APS (April 1997-October
1998) and Director, Corporate Services of APS (December 1989-April 1997).
Mr. Brown was elected to his present position in June 2001. Prior to that
time he was Director, Information Technology of Pinnacle West (October 1999 -
June 2001) and Global Solution Executive for IBM Utilities and Energy Services
of IBM prior to that time.
Mr. Flores was elected to his present position in July 1999. Prior to that
time, he was Executive Vice President, Corporate Business Services of APS
(October 1998-July 1999), Senior Vice President, Corporate Business Services of
APS (September 1996-October 1998) and Vice President, Human Resources of APS
(December 1991-September 1996).
Mr. Fox was elected to his present position in July 1999. Prior to that
time he was Vice President, Environmental/Health/Safety and New Technology
Ventures of APS (October 1995-July 1999).
Mr. Froggatt was elected Controller in July 1999 and Vice President in
August 1999. Prior to that time he was Controller of APS (July 1997-July 1999)
and Director, Accounting Services of APS (December 1992-July 1997).
Ms. Gomez was elected to her present position in August 1999. Prior to that
time, she was Manager, Treasury Operations of APS (1997-1999) and Manager,
Financial Planning of APS (1994-1997). She was also elected Treasurer of APS in
October 1999.
Mr. Hansen was elected to his present position in June 2001. Prior to that
time he was Director, Pinnacle West Marketing and Trading for Pinnacle West and
APS (since 1996).
Mr. Levine was elected to his present position in July 1999. Prior to that
time he was Senior Vice President, Nuclear Generation of APS (September
1996-July 1999) and Vice President, Nuclear Production of APS (September
1989-September 1996). Mr. Levine is also Chief Operating Officer of Pinnacle
West Energy.
Ms. Loftin was elected to her present position in July 1999. She was
elected to the positions of Vice President and Chief Legal Counsel of APS in
September 1996. Prior to that time, she was Secretary of APS (since April 1987)
and Corporate Counsel of APS (since February 1989). She was also elected Vice
President and General Counsel of APS in July 1999.
26
Mr. Palmeri was elected to his present position in August 1999. Prior to
that time he was Treasurer of APS and Pinnacle West (July 1997-September 1999)
and Assistant Treasurer of Pinnacle West (February 1994-July 1997). He also was
elected Vice President, Finance of APS in October 1999.
Mr. Robinson was elected to his present position in June 2001. Prior to
that time he was Director, Accounting, Planning and Regulation (January 2001 -
June 2001); Director, Accounting and Planning (August 1999 - January 2001); and
Director, Strategic Planning (October 1998 - August 1999) of Pinnacle West.
Prior to that time he was Director, Regulatory Services (November 1997 - October
1998), and Director, Regulatory (December 1996 - November 1997) of APS.
Mr. Shultz was elected to his current position in July 1999. Prior to that
time he held the position of Director of Government Relations for APS (1988-July
1999).
Mr. Stewart was elected to his present position in October 1998. Prior to
that time he was Executive Vice President, Generation of APS (September
1996-October 1998) and Executive Vice President, Nuclear of APS (May
1994-September 1996). Mr. Stewart is also a director of APS and Pinnacle West,
and a director and President of Pinnacle West Energy.
Mr. Wheeler was elected to his present position in June 2001. Prior to that
time he was a partner with Snell & Wilmer L.L.P. Mr. Wheeler was also elected
Senior Vice President, Transmission, Regulation and Planning of APS in June
2001.
Ms. Widenmann was elected to her current position in July 1999. Prior to
that time, she held the position of Secretary (since 1985) and Vice President of
Corporate Relations and Administration (since November 1986). She was also
elected Vice President and Secretary of APS in July 1999.
27
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
STOCK AND RELATED STOCKHOLDER MATTERS
Our common stock is publicly held and is traded on the New York and Pacific
Stock Exchanges. At the close of business on March 25, 2002, our common stock
was held of record by approximately 38,021 shareholders.
See "Quarterly Stock Prices and Dividends" in Item 6 for a description of
the common stock price ranges on the composite tape, as reported in the Wall
Street Journal for 2001 and 2000, and the dividends declared during each of the
four quarters for 2001 and 2000.
28
ITEM 6. SELECTED CONSOLIDATED DATA
2001 2000 1999 1998 1997
------------ ------------ ------------ ------------ ------------
OPERATING RESULTS (dollars in thousands, except per share amounts)
Operating revenues
Electric $ 4,382,465 $ 3,531,810 $ 2,293,184 $ 2,006,398 $ 1,878,553
Real estate 168,908 158,365 130,169 124,188 116,473
Income from continuing
operations $ 327,367 $ 302,332 $ 269,772 $ 242,892 $ 235,856
Discontinued operations (a) -- -- 38,000 -- --
Extraordinary charge - net of
income taxes (b) -- -- (139,885) -- --
Cumulative effect of change
in accounting-net of income
taxes (c) (15,201) -- -- -- --
------------ ------------ ------------ ------------ ------------
Net income $ 312,166 $ 302,332 $ 167,887 $ 242,892 $ 235,856
============ ============ ============ ============ ============
COMMON STOCK DATA
Book value per share - year-end $ 29.46 $ 28.09 $ 26.00 $ 25.50 $ 23.90
Earnings (loss) per weighted
average common share outstanding
Continuing operations - basic $ 3.86 $ 3.57 $ 3.18 $ 2.87 $ 2.76
Discontinued operations -- -- 0.45 -- --
Extraordinary charge -- -- (1.65) -- --
Cumulative effect of change
in accounting (0.18) -- -- -- --
------------ ------------ ------------ ------------ ------------
Net income - basic $ 3.68 $ 3.57 $ 1.98 $ 2.87 $ 2.76
============ ============ ============ ============ ============
Continuing operations -
diluted $ 3.85 $ 3.56 $ 3.17 $ 2.85 $ 2.74
Net income - diluted $ 3.68 $ 3.56 $ 1.97 $ 2.85 $ 2.74
Dividends declared per share $ 1.525 $ 1.425 $ 1.325 $ 1.225 $ 1.125
Indicated annual dividend rate
per share - year-end $ 1.60 $ 1.50 $ 1.40 $ 1.30 $ 1.20
Weighted-average common
shares outstanding - basic 84,717,649 84,732,544 84,717,135 84,774,218 85,502,909
Weighted-average common
shares outstanding - diluted 84,930,140 84,935,282 85,008,527 85,345,946 86,022,709
BALANCE SHEET DATA
Total assets $ 7,981,748 $ 7,162,985 $ 6,608,506 $ 6,824,546 $ 6,850,417
============ ============ ============ ============ ============
Liabilities and equity:
Long-term debt less current
maturities $ 2,673,078 $ 1,955,083 $ 2,206,052 $ 2,048,961 $ 2,244,248
Other liabilities 2,809,347 2,825,188 2,196,721 2,516,993 2,407,572
------------ ------------ ------------ ------------ ------------
Total liabilities 5,482,425 4,780,271 4,402,773 4,565,954 4,651,820
Minority interests
Non-redeemable preferred
stock of APS -- -- -- 85,840 142,051
Redeemable preferred stock of
APS -- -- -- 9,401 29,110
Common stock equity 2,499,323 2,382,714 2,205,733 2,163,351 2,027,436
------------ ------------ ------------ ------------ ------------
Total liabilities and equity $ 7,981,748 $ 7,162,985 $ 6,608,506 $ 6,824,546 $ 6,850,417
============ ============ ============ ============ ============
----------
(a) Tax benefit stemming from the resolution of income tax matters related to a
former subsidiary MeraBank, A Federal Savings Bank. See Note 4.
(b) Charges associated with a regulatory disallowance. See Note 3.
(c) Change in accounting standards related to derivatives. See Note 17.
29
ELECTRIC OPERATING
REVENUES 2001 2000 1999 1998 1997
------------ ------------ ------------ ------------ ------------
(dollars in thousands)
Retail
Residential $ 914,711 $ 880,468 $ 805,173 $ 766,378 $ 746,937
Business 952,627 935,214 911,449 889,244 873,232
------------ ------------ ------------ ------------ ------------
Total retail 1,867,338 1,815,682 1,716,622 1,655,622 1,620,169
------------ ------------ ------------ ------------ ------------
Wholesale revenue on
delivered electricity:
Traditional contracts 73,305 120,618 60,486 58,184 63,027
Retail load hedge management 577,784 560,493 108,153 -- --
Marketing and trading -
delivered:
Generation other than
native load (a) 148,316 115,476 29,551 -- --
Other delivered electricity (a) 1,560,185 874,619 345,067 258,058 163,801
------------ ------------ ------------ ------------ ------------
Total delivered marketing
and trading 1,708,501 990,095 374,618 258,058 163,801
------------ ------------ ------------ ------------ ------------
Total delivered wholesale
electricity 2,359,590 1,671,206 543,257 316,242 226,828
------------ ------------ ------------ ------------ ------------
Other marketing and trading:
Realized margins on delivered
commodities other than
electricity (13,646) (8,789) 2,483 7,192 3,618
Prior period mark-to-market
(gains) losses on contracts
delivered during current
period (1,059) (2,079) -- -- --
Change in mark-to-market for
future period deliveries 126,580 13,831 975 -- --
------------ ------------ ------------ ------------ ------------
Total other marketing and
trading 111,875 2,963 3,458 7,192 3,618
------------ ------------ ------------ ------------ ------------
Transmission for others 25,971 14,765 11,348 11,058 10,295
Other miscellaneous services 17,691 27,194 18,499 16,284 17,643
------------ ------------ ------------ ------------ ------------
Total electric operating revenues $ 4,382,465 $ 3,531,810 $ 2,293,184 $ 2,006,398 $ 1,878,553
============ ============ ============ ============ ============
(a) The break-out of generation other than native load is not available for
1997 through 1998.
30
2001 2000 1999 1998 1997
------------ ------------ ------------ ------------ ------------
ELECTRIC SALES (MWH)
Retail:
Residential 10,334,860 9,780,680 8,774,822 8,310,689 7,970,309
Business 13,064,152 12,753,844 12,299,748 12,152,394 11,846,618
------------ ------------ ------------ ------------ ------------
Total retail 23,399,012 22,534,524 21,074,570 20,463,083 19,816,927
------------ ------------ ------------ ------------ ------------
Wholesale electricity delivered:
Traditional contracts 1,213,704 1,610,032 1,421,522 1,410,392 1,486,439
Retail load hedge management 3,039,905 6,673,658 630,945 -- --
Marketing and trading -
delivered:
Generation other than
native load (a) 1,387,860 1,494,299 1,267,349 -- --
Other delivered electricity (a) 14,612,997 12,219,368 12,374,018 8,906,999 7,747,134
------------ ------------ ------------ ------------ ------------
Total delivered marketing
and trading 16,000,857 13,713,667 13,641,367 8,906,999 7,747,134
------------ ------------ ------------ ------------ ------------
Total delivered wholesale
electricity 20,254,466 21,997,357 15,693,834 10,317,391 9,233,573
------------ ------------ ------------ ------------ ------------
Total electric sales 43,653,478 44,531,881 36,768,404 30,780,474 29,050,500
============ ============ ============ ============ ============
ELECTRIC CUSTOMERS -
AVERAGE
Retail:
Residential 776,339 749,285 719,774 689,871 663,493
Business 98,198 94,128 90,496 87,831 84,576
------------ ------------ ------------ ------------ ------------
Total retail 874,537 843,413 810,270 777,702 748,069
Wholesale 66 67 69 60 59
------------ ------------ ------------ ------------ ------------
Total customers 874,603 843,480 810,339 777,762 748,128
============ ============ ============ ============ ============
(a) The break-out of generation other than native load is not available for
1997 through 1998.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Item 7 for a discussion of certain information in the tables
above.
31
QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE
STOCK SYMBOL: PNW
Dividends
Per
2001 High Low Close Share
---- ---- --- ----- -----
1st Quarter $47.96 $39.06 $45.87 $0.375
2nd Quarter 50.70 45.20 47.40 0.375
3rd Quarter 49.93 37.65 39.70 0.375
4th Quarter 43.50 38.00 41.85 0.400
Dividends
Per
2000 High Low Close Share
---- ---- --- ----- -----
1st Quarter $32.31 $26.25 $28.19 $0.350
2nd Quarter 35.88 27.88 33.88 0.350
3rd Quarter 51.31 33.81 50.89 0.350
4th Quarter 52.22 40.89 47.63 0.375
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In this section, we explain the results of operations, general financial
condition, and outlook for Pinnacle West Capital Corporation and our
subsidiaries: Arizona Public Service Company (APS), Pinnacle West Energy
Corporation (Pinnacle West Energy), APS Energy Services Company, Inc. (APSES),
SunCor Development Company (SunCor), and El Dorado Investment Company (El
Dorado), including:
* the changes in our earnings from 2000 to 2001 and from 1999 to 2000;
* our capital needs, liquidity and capital resources;
* our marketing and trading activities;
* our financial outlook;
* our critical accounting policies;
* major factors that affect our financial outlook; and
* our management of market risks.
OVERVIEW OF OUR BUSINESS
Pinnacle West owns all of the outstanding common stock of APS. APS is
Arizona's largest electric utility and provides either retail or wholesale
electric service to substantially all of the state, with the major exceptions of
the Tucson metropolitan area and about one-half of the Phoenix metropolitan
area. APS also generates and, through our marketing and trading division, sells
and delivers electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our unregulated
electricity generation operations;
* APSES, which provides commodity energy and energy-related products to
key customers in competitive markets in the western United States;
* SunCor, a developer of residential, commercial, and industrial real
estate projects in Arizona, New Mexico, and Utah; and
* El Dorado, an investment firm.
Pinnacle West's marketing and trading division sells in the wholesale
market APS and Pinnacle West Energy generation production output that is not
needed for APS' native load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. Subject to specified risk
33
parameters established by our Board of Directors, the marketing and trading
division also engages in activities to hedge purchases and sales of electricity,
fuels, and emissions allowance and credits and to profit from market price
movements. We explain in detail below the historical and prospective
contribution of marketing and trading activities to our financial results.
APS is required to transfer its competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, APS has been addressing the legal and regulatory
requirements necessary to complete the transfer of its generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail below
under "Business Outlook - Other Factors Affecting Our Financial Outlook," recent
Arizona regulatory developments have raised uncertainty about the status and
pace of retail electric competition in Arizona, including APS' transfer of
generation assets to Pinnacle West Energy.
BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and regulatory environment), which consist of regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
currently includes activities related to electricity transmission and
distribution, as well as electricity generation. Our marketing and trading
segment currently includes activities related to wholesale marketing and trading
and APSES' competitive energy services.
These reportable segments reflect a change in the reporting of our segment
information. Before the fourth quarter of 2001, we had two segments (generation
and delivery). The "generation segment" information combined our marketing and
trading activities with our generation of electricity activities. The "delivery
segment" included transmission and distribution activities.
In the fourth quarter, APS filed with the ACC a request for a proposed rule
variance and approval of a purchase power agreement (see Note 3) that inherently
views our business in the new reportable segments described as presented herein.
Internal management reporting has been changed to reflect this alignment. See
"Business Segments" in Note 16 for more information about our business segments.
The following is a summary of net income by business segment for 2001,
2000, and 1999 (dollars in millions):
2001 2000 1999
----- ----- -----
Retail $ 152 $ 225 $ 246
Marketing and trading 172 63 5
Other 3 14 19
----- ----- -----
Income from continuing operations 327 302 270
Income tax benefit from discontinued operations -- -- 38
Extraordinary charge - net of income taxes -- -- (140)
Cumulative effect of change in accounting -
net of income taxes (15) -- --
----- ----- -----
Net income $ 312 $ 302 $ 168
===== ===== =====
Throughout this section, we refer to specific "Notes" in the Notes to
Consolidated Financial Statements that begin on page 66. These Notes add further
details to the discussion.
34
RESULTS OF OPERATIONS
The following is a summary of our net income by legal entity for 2001, 2000
and 1999 (dollars in millions):
2001 2000 1999
----- ----- -----
APS $ 281 $ 307 $ 267
Pinnacle West Energy 18 (2) --
APSES (10) (13) (9)
SunCor 3 11 6
El Dorado -- 2 11
Parent company (a) 35 (3) (5)
----- ----- -----
Income from continuing operations 327 302 270
Income tax benefit from discontinued operations -- -- 38
Extraordinary charge - net of income taxes -- -- (140)
Cumulative effect of change in accounting - net of
income taxes (15) -- --
----- ----- -----
Net income $ 312 $ 302 $ 168
===== ===== =====
----------
(a) The 2001 amount primarily includes marketing and trading activities. APS
also includes some marketing and trading activities. (See Note 16 for
further discussion of our business segments.)
2001 COMPARED WITH 2000
Our consolidated net income for the year ended December 31, 2001 was $312
million compared with $302 million for the year ended December 31, 2000. In
2001, we recognized a $15 million after-tax loss in net income as a cumulative
effect of a change in accounting for derivatives. See Note 17 for further
discussion on accounting for derivatives.
Income from continuing operations for the year ended December 31, 2001 was
$327 million compared with $302 million for the year ended December 31, 2000.
The year-to-year comparison benefited from strong marketing and trading results,
including significant benefits in the 2001 third quarter from structured trading
activities, 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. The major
factors that increased (decreased) income from continuing operations were as
follows (dollars in millions):
35
Increase
(Decrease)
----------
Increases (decreases) in electric revenues, net of purchased
power and fuel expense due to:
Marketing and trading activities:
Increase from generation sales other than
native load due to higher market prices $ 25
Increase in other realized marketing and trading
in current period primarily due to more transactions 45
Change in prior period mark-to-market value for losses
transferred to realized margin in current period 16 (a)
Change in prior period mark-to-market value related to
trading with Enron and its affiliates (8)(b)
Increase in mark-to-market value related to future periods 113 (a)
----
Net increase in marketing and trading 191
Higher replacement power costs for plant outages related
to higher market prices (70)
Retail price reductions (see Note 3) (27)
Charges related to purchased power contracts with Enron
and its affiliates (13)(b)
Higher retail sales primarily related to customer growth 35
Miscellaneous revenues 3
----
Total increase in revenues, net of purchased power and fuel expense 119
Decrease in real estate contributions (8)
Higher operations and maintenance expense related to 2001
generation reliability program (42)
Higher operations and maintenance expense related primarily to
employee benefits, plant outage and maintenance; and other costs (38)
Lower net interest expense primarily due to higher capitalized
interest 17
Higher other net expense (5)
Miscellaneous items, net 1
----
Net increase in income from continuing operations before
income taxes 44
Higher income taxes primarily due to higher income (19)
----
Net increase in income from continuing operations $ 25
====
----------
(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
(b) We recorded charges totaling $21 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001.
Electric operating revenues increased approximately $850 million because
of:
* changes in marketing and trading revenues ($827 million, net
increase):
- increased revenues related to generation sales other than native
load as a result of higher average market prices ($32 million);
- increased realized revenues related to other marketing and
trading in current period primarily due to more transactions
($681 million);
36
- decreased prior period mark-to-market value related to trading
with Enron and its affiliates ($8 million);
- increased prior period mark-to-market value for losses
transferred to realized margin in current period ($9 million);
- increased mark-to-market value for future periods primarily as a
result of more forward sales volumes ($113 million);
* decreased revenues related to other wholesale sales and miscellaneous
revenues as a result of sales volumes ($28 million);
* increased retail revenues primarily related to higher sales volumes
primarily due to customer growth ($78 million); and
* decreased retail revenues related to reductions in retail electricity
prices ($27 million).
Purchased power and fuel expenses increased approximately $731 million
primarily because of:
* changes in marketing and trading purchased power and fuel costs ($636
million, net increase) due to:
- increased fuel costs related to generation sales other than
native load as a result of higher fuel prices ($7 million);
- increased fuel and purchased power costs related to other
realized marketing and trading in current period primarily due to
more transactions ($636 million);
- decreased mark-to-market fuel costs related to accounting for
derivatives ($7 million) (see Note 17);
* decreased costs related to other wholesale sales as a result of lower
volumes ($31 million);
* higher replacement power costs primarily due to higher market prices
and increased plant outages ($70 million), including costs of $12
million related to a Palo Verde outage extension to replace fuel
control element assemblies;
* higher costs related to retail sales volumes due to customer growth
($43 million); and
* charges related to purchased power contracts with Enron and its
affiliates ($13 million).
The decrease in real estate profits of $8 million resulted primarily from
decreases in sales of land and homes by SunCor.
The increase in operations and maintenance expenses of $80 million
primarily related to the 2001 generation summer reliability program (the
addition of generating capability to enhance reliability for the summer of 2001
($42 million)) and increased employee benefit costs, plant outage and
maintenance, and other costs ($38 million). The comparison reflects Pinnacle
West's $10 million provision for our credit exposure related to the California
energy situation, $5 million of which was recorded in the fourth quarter of 2000
and $5 million of which was recorded in the first quarter of 2001.
Net other expense increased $5 million primarily because of a change in the
market value of El Dorado's investment in a technology-related venture capital
partnership in 2000 (see Note 1) and other nonoperating costs partially offset
by an insurance recovery of environmental remediation costs.
Interest expense decreased by $17 million primarily because of increased
capitalized interest resulting from our generation expansion plan partially
offset with higher interest expense due to higher debt balances.
37
2000 COMPARED WITH 1999
Our consolidated net income for the year ended December 31, 2000 was $302
million compared with $168 million for the year ended December 31, 1999. Our
2000 net income increased $134 million over 1999 primarily because of a $140
million after-tax extraordinary charge that we recorded in 1999. This charge
reflected a regulatory disallowance resulting from an ACC-approved Settlement
Agreement related to the implementation of retail electric competition. The
resulting increase in our 2000 net income was partially offset by the absence of
a $38 million income tax benefit from discontinued operations that we also
recorded in 1999. See "Regulatory Agreements" below and Notes 1 and 3 for
additional information about the 1999 Settlement Agreement and the resulting
regulatory disallowance. See Note 4 for additional information about the income
tax benefit from discontinued operations.
Income from continuing operations for the year ended December 31, 2000 was
$302 million compared with $270 million for the year ended December 31, 1999.
The year-to-year comparison benefited from strong wholesale and retail electric
sales and real estate profits. These positive factors more than offset decreases
resulting from the completion of ITC amortization in 1999, reductions in retail
electricity prices, lower earnings from El Dorado, and miscellaneous factors.
See "Regulatory Agreements" below and Note 3 for information on the price
reductions. See "Regulatory Agreements" below and Note 4 for additional
information about ITC amortization. The major factors that increased (decreased)
income from continuing operations were as follows (dollars in millions):
Increase
(Decrease)
----------
Increases (decreases) in electric revenues, net of purchased
power and fuel expense due to:
Marketing and trading activities:
Increase from generation sales other than native load due
to higher market prices $ 47
Increase in other realized marketing and trading in current
period primarily due to more transactions 51
Change in prior period mark-to-market value for gains
transferred to realized margin in current period (2)(a)
Increase in mark-to-market value related to future periods 13 (a)
----
Net increase in marketing and trading 109
Retail price reductions (see Note 3) (28)
Higher retail sales primarily related to customer growth 9
Miscellaneous revenues 10
----
Total increase in revenues, net of purchased power and fuel expense 100
Increase in real estate contributions 13
Higher operations and maintenance expense related primarily to
customer growth substantially offset by $20 million of other
items recorded in 1999 (4)
Higher other net expense primarily related to El Dorado (10)
Higher depreciation and amortization expense (11)
Miscellaneous items, net (3)
----
Net increase in income from continuing operations before
income taxes 85
Higher income taxes due to higher income in 2000 and higher ITC
amortization in 1999 (53)
----
Net increase in income from continuing operations $ 32
====
38
----------
(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
Electric operating revenues increased approximately $1.24 billion because
of:
* changes in marketing and trading revenues ($616 million, net
increase):
- increased revenues related to generation sales other than native
load as a result of higher market prices ($86 million);
- increased realized revenues related to other marketing and
trading in current period primarily due to more transactions and
higher market prices ($519 million);
- decreased prior period mark-to-market value for gains transferred
to realized margin in current period ($2 million);
- increased mark-to-market value for future periods primarily as a
result of more forward sales volumes ($13 million);
* increased revenues related to increased volumes and higher market
prices for other wholesale sales resulting from retail load hedging
activities and miscellaneous revenues ($523 million);
* increased retail revenues primarily related to higher sales volumes
due to customer growth ($127 million); and
* decreased retail revenues related to reductions in retail electricity
prices ($28 million).
Purchased power and fuel expenses increased approximately $1.14 billion
primarily due to:
* changes in marketing and trading purchased power and fuel costs ($507
million, increase) due to:
- increased fuel costs related to generation sales other than
native load as a result of higher fuel prices ($39 million);
- increased fuel and purchased power costs related to other
realized marketing and trading in current period primarily due to
more transactions ($468 million);
* increased costs related to increased volumes and higher market prices
for wholesale sales resulting from retail hedging activities ($513
million); and
* higher costs related to retail sales volumes due to customer growth
and increased fuel and purchased power prices ($118 million).
The increase in real estate profits of $13 million resulted primarily from
increases in sales of land and homes by SunCor.
The increase in operations and maintenance expenses of $4 million primarily
related to customer growth was substantially offset by $20 million of other
items recorded in 1999.
The increase in depreciation and amortization of $11 million primarily
related to higher plant in service balances offset by lower regulatory asset
amortization.
39
Net other expense decreased $10 million primarily because of changes in
2000 in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 1 for additional information about the
valuation of El Dorado's investments.
REGULATORY AGREEMENTS
Regulatory agreements approved by the ACC affect the results of APS'
operations. The following discussion focuses on three agreements approved by the
ACC, each of which included retail electricity price reductions:
* The 1999 Settlement Agreement to implement retail electric
competition;
* A 1996 agreement that accelerated the amortization of APS' regulatory
assets; and
* A 1994 settlement that accelerated the amortization of APS' deferred
ITCs.
1999 SETTLEMENT AGREEMENT
As part of the 1999 Settlement Agreement, APS agreed to reduce retail
electricity prices for standard-offer, full-service customers with loads less
than three megawatts in a series of annual decreases of 1.5% on July 1, 1999
through July 1, 2003, for a total of 7.5%. The first reduction of approximately
$24 million ($14 million after income taxes) included the July 1, 1999 retail
price decrease required by the 1996 regulatory agreement (see below). For
customers having loads three megawatts or greater, standard-offer rates will be
reduced in annual increments that total 5% in the years 1999 through 2002.
The 1999 Settlement Agreement also removed, as a regulatory disallowance,
$234 million before income taxes ($183 million net present value) from ongoing
regulatory cash flows. APS recorded this regulatory disallowance as a net
reduction of regulatory assets and reported it as a $140 million after-tax
extraordinary charge on the 1999 income statement.
Under the 1996 regulatory agreement, APS was recovering substantially all
of its regulatory assets through accelerated amortization over an eight-year
period that would have ended June 30, 2004. For more details, see Note 1. The
regulatory assets to be recovered under the 1999 Settlement Agreement are
currently being amortized as follows (dollars in millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
See Note 3 and "Business Outlook - Electric Competition (Retail)" below for
additional information regarding the 1999 Settlement Agreement.
1996 REGULATORY AGREEMENT
As part of the 1996 regulatory agreement, APS reduced its retail
electricity prices by 3.4% effective July 1, 1996. This reduction decreased
electric revenue by about $49 million annually ($29 million after income taxes).
40
APS also agreed to share future cost savings with its customers during the term
of this agreement, which resulted in the following additional retail price
reductions:
* $18 million annually ($11 million after income taxes), or 1.2%,
effective July 1, 1997;
* $17 million annually ($10 million after income taxes), or 1.1%,
effective July 1, 1998; and
* $11 million annually ($7 million after income taxes), or 0.7%,
effective July 1, 1999 (as noted above, this reduction was included in
the July 1, 1999 price reduction under the 1999 Settlement Agreement).
1994 RATE SETTLEMENT
As part of a 1994 rate settlement, APS accelerated amortization of
substantially all of its ITCs over a five-year period that ended on December 31,
1999. The amortization of ITCs decreased annual consolidated income tax expense
by about $24 million. Beginning in 2000, no further benefits were reflected in
income tax expense related to the acceleration of the ITCs (see Note 4).
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, 2001 and estimated capital expenditures for the next three
years.
CAPITAL EXPENDITURES
(dollars in millions)
(actual) (estimated)
------ ----------------------------
2001 2002 2003 2004
------ ------ ------ ------
APS
Delivery $ 354 $ 349 $ 271 $ 280
Existing generation (a) 117 149 -- --
------ ------ ------ ------
Subtotal 471 498 271 280
------ ------ ------ ------
Pinnacle West Energy (b)
Generation expansion 533 411 255 113(e)
Existing generation (a) -- -- 107 99
------ ------ ------ ------
Subtotal 533 411 362 212
------ ------ ------ ------
SunCor (c) 80 79 48 52
Other (d) 45 35 15 16
------ ------ ------ ------
Total $1,129 $1,023 $ 696 $ 560
====== ====== ====== ======
----------
(a) Pursuant to the 1999 Settlement Agreement, APS is required to transfer its
competitive electric assets and services no later than December 31, 2002.
41
(b) See Note 10 for further discussion of Pinnacle West Energy's generation
expansion program and "Capital Resources and Cash Requirements - Pinnacle
West Energy" below.
(c) Consists primarily of capital expenditures for land development and retail
and office building construction reflected in the "Increase in real estate
investments" in the consolidated statements of cash flows.
(d) Primarily Pinnacle West and APSES.
(e) This amount does not include an expected reimbursement by Southern Nevada
Water Authority (SNWA) of $100 million of these costs in 2004 in exchange
for SNWA's purchase of a 25% interest in the Silverhawk project at that
time.
APS and the other Palo Verde participants are currently considering issues
related to replacement of the steam generators in Units 1 and 3. Although a
final determination of whether Units 1 and 3 will require steam generator
replacement to operate over their current full licensed lives has not yet been
made, APS and the other participants have approved an expenditure in 2002 to
procure long lead-time materials for fabrication of a spare set of steam
generators for either Unit 1 or 3. APS' portion of this expenditure is
approximately $7 million and is included in the estimated expenditures above.
This action will provide the Palo Verde participants an option to replace the
steam generators at either Unit 1 or 3 as early as fall 2005 should they
ultimately choose to do so. If the participants decide to proceed with steam
generator replacement at both Units 1 and 3, APS has estimated that its portion
of the fabrication and installation costs and associated power uprate
modifications would be approximately $130 million over the next seven years,
which would be funded with internally-generated cash or external financings.
Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants. 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. The increase in this category in 2002 is due primarily
to Four Corners and various gas-fired units. The increased work on equipment is
due to higher use of the units and also a stack replacement project for Four
Corners Units 1 and 2. The existing generation also contains nuclear fuel
expenditures of approximately $30 million annually in 2002, 2003, and 2004.
Delivery capital expenditures are comprised of transmission and
distribution (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 $150 million
on major transmission projects during the 2002-2004 time frame.
42
CAPITAL RESOURCES AND CASH REQUIREMENTS
The following table summarizes cash commitments for the year ended December
31, 2001 and estimated commitments for the next three years (dollars in
millions):
(actual) (estimated)
------ --------------------------
2001 2002 2003 2004
------ ------ ------ ------
Long-term debt payments (see Note 6)
APS $ 384 $ 247 $ -- $ 205
Pinnacle West 213 -- 276 216
SunCor 24 -- 42 86
------ ------ ------ ------
Total long-term debt payments 621 247 318 507
Operating leases payments (see Note 8) 67 68 66 65
Fuel and purchase power commitments
(see Note 10) 374 270 124 80
------ ------ ------ ------
Total cash commitments $1,062 $ 585 $ 508 $ 652
====== ====== ====== ======
Pinnacle West had available lines of credit in the amount of $250 million
at December 31, 2001. APS had lines of credit available in the amount of $250
million at December 31, 2001. There was no outstanding balance on either the
Pinnacle West or APS lines of credit at December 31, 2001. Pinnacle West and APS
project that these lines of credit will be available over the next three years.
The lines of credit are anticipated to be renewed at their expiration dates. See
Note 5 for further information on Pinnacle West's and APS' lines of credit.
SunCor had an available line of credit at December 31, 2001 in the amount
of $140 million. This line of credit had an outstanding balance at December 31,
2001 of $128 million. SunCor projects that this line of credit will be available
over the next three years. SunCor also anticipates renewing the line of credit
at its expiration date. See Note 5 for further details on SunCor's line of
credit.
The parent company has issued parental guarantees and obtained surety bonds
on behalf of its unregulated subsidiaries, primarily for Pinnacle West Energy's
expansion plans, which are reflected in the capital expenditure table above, and
APSES' retail and energy business.
APS has obtained approximately $500 million in letters of credit primarily
to provide credit support for its variable rate tax-exempt bonds and its Palo
Verde sale-leaseback transactions. Pinnacle West has obtained approximately $40
million in letters of credit to provide credit support for Pinnacle West
Energy's generation expansion plans.
Pinnacle West and APS do not have ratings triggers in any of their debt
agreements. Rating triggers are provisions that would result in the acceleration
of repayment obligations based upon a credit rating agency downgrade. Although
those ratings triggers appear in certain power marketing and trading agreements,
their financial impacts are not expected to be significant.
APS' first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel, transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
43
stock dividends under certain conditions. These conditions did not exist at
December 31, 2001.
See the Company's consolidated debt structure in Note 6. The parent company
and our subsidiaries' capital needs and resources are described as follows.
PINNACLE WEST (PARENT COMPANY)
During the past three years, our primary cash needs were for:
* dividends to our shareholders;
* equity infusions into our subsidiaries;
* interest payments; and
* optional and mandatory repayment of principal on our long-term debt.
The equity infusions into our subsidiaries during the past three years
included $50 million invested in APS in 1999. This investment completed the
funding of Pinnacle West's commitment under the 1996 regulatory agreement (see
Note 3) to infuse $50 million a year into APS ($200 million total) from 1996
through 1999. The investments into Pinnacle West Energy were $484 million in
2001 and $193 million in 2000 to fund portions of its capital expenditures for
its generation expansion program.
Over the next three years, we anticipate that our cash needs will fall into
these same categories. We expect our equity infusions into Pinnacle West Energy
to continue as it invests in additional generating facilities (see Note 10)
until it begins to finance its own construction needs.
Our primary sources of cash are dividends from APS, our marketing and
trading operations, and external financing. For the years 1999 through 2001,
total dividends from APS were $510 million.
Our long-term debt at December 31, 2001 was $576 million compared with $238
million at December 31, 2000. We had $235 million of borrowings outstanding on
our commercial paper at December 31, 2001. Our debt repayment requirements for
the parent company for the next three years are approximately: zero in 2002,
$276 million in 2003, and $216 million in 2004.
On February 8, 2002, we issued $215 million of our 4.5% Notes due 2004.
APS
APS' capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. APS pays for its capital
requirements with cash from operations and, to the extent necessary, external
financing. APS pays for its dividends to Pinnacle West with cash from
operations.
During the period from 1999 through 2001, APS paid for substantially all of
its capital expenditures with cash from operations. APS expects to do so in 2002
through 2004 with cash from operations and its own debt issuances.
44
See the capital expenditure table above for additional information
regarding actual capital expenditures in 2001 and projected capital expenditures
for the next three years.
During 2001, APS redeemed approximately $384 million of long-term debt,
including premiums, with cash from operations and from the issuance of long- and
short-term debt. APS' long-term debt redemption requirements for the next three
years are approximately: $247 million in 2002; zero in 2003; and $205 million in
2004. Based on market conditions and call provisions, APS may make optional
redemptions of long-term debt from time to time.
As of December 31, 2001, APS had credit commitments from various banks
totaling about $250 million, which were available either to support the issuance
of commercial paper or to be used as bank borrowings. At the end of 2001, APS
had about $171 million of commercial paper outstanding and no bank borrowings.
APS' long-term debt was approximately $2.1 billion at December 31, 2001 and
2000 (see Note 6).
Although ACC financing orders establish maximum amounts of additional debt
that APS may issue, APS does not expect these orders to limit its ability to
meet its capital requirements.
On March 1, 2002, APS issued $375 million of 6.50% Notes due 2012. On March
15, 2002, APS announced the redemption on April 15, 2002 of approximately $125
million of its First Mortgage Bonds, 8.75% Series due 2024.
PINNACLE WEST ENERGY
See Note 10 for a discussion of Pinnacle West Energy's generation expansion
plans. Pinnacle West Energy is currently funding its capital requirements
through capital infusions from the parent. We finance those infusions through
debt financing and internally generated cash, as Pinnacle West Energy develops
and obtains additional generation assets. Pinnacle West Energy also expects to
fund its capital requirements through internally generated cash and its own debt
issuances. See the Capital Expenditures Table above for actual capital
expenditures in 2001 and projected capital expenditures for the next three
years.
OTHER SUBSIDIARIES
During the past three years, both SunCor and El Dorado funded all of their
cash requirements with cash from operations and, in the case of SunCor, its own
external financings. APSES funded its cash requirements with cash infusions from
Pinnacle West.
SunCor's capital needs consist primarily of capital expenditures for land
development and retail and office building construction. See the Capital
Expenditures Table above for actual capital expenditures in 2001 and projected
capital expenditures for the next three years. SunCor expects to fund its
capital requirements with cash from operations and external financings.
As of December 31, 2001, SunCor had a $140 million line of credit, under
which $128 million of borrowings were outstanding. SunCor's debt repayment
obligations for the next three years are approximately: zero in 2002; $42
million in 2003; and $86 million in 2004.
45
El Dorado does not have any capital requirements over the next three years.
El Dorado intends to focus on prudently realizing the value of its existing
investments. El Dorado's future investments are expected to be related to the
energy sector.
APSES capital expenditures and other cash requirements are increasingly
funded by operations, with some funding from cash infused by Pinnacle West. See
the Capital Expenditures Table above regarding APSES' capital expenditures.
See Notes 5 and 6 for additional information about outstanding lines of
credit and long-term debt obligations.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with generally accepted
accounting principles (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. Our most critical
accounting policies include the determination of the appropriate accounting for
our derivative instruments, mark-to-market accounting and the impacts of
regulatory accounting on our financial statements. See Note 1 for a discussion
of these critical accounting policies.
OTHER ACCOUNTING MATTERS
We prepare our financial statements in accordance with Statement of
Financial Accounting Standards (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 of the 1999 Settlement Agreement (see "Regulatory
Agreements" above and Note 3), we discontinued the application of SFAS No. 71
for our generation operations. As a result, we tested the generation assets for
impairment and determined that the generation assets were not impaired. Pursuant
to the 1999 Settlement Agreement, we reported a regulatory disallowance ($140
million after income taxes) as an extraordinary charge on the 1999 consolidated
income statement. See Note 1 for additional information on regulatory accounting
and Note 3 for additional information on the 1999 Settlement Agreement.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or stockholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. Hedge effectiveness is measured based on the relative changes in fair
value between the derivative contract and the hedged commodity over time. Any
change in the fair value resulting from ineffectiveness is recognized
immediately in net income. This new standard may result in additional volatility
in our net income and other comprehensive income.
As a result of adopting SFAS No. 133 in 2001, we recorded a $15 million
after-tax loss in consolidated net income and a $72 million after-tax gain in
equity (as a component of other comprehensive income), both as a cumulative
effect of a change in accounting principle. The loss primarily resulted from
electricity options contracts. The gain resulted from unrealized gains on cash
46
flow hedges. See Note 17 for further information on accounting for derivatives
under SFAS No. 133, including discussions on new guidance effective on April 1,
2002.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This Statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17, "Intangible Assets." This standard is effective
for the year beginning January 1, 2002. We have no goodwill recorded in our
consolidated balance sheets. The impacts of this new standard are not material
to our consolidated financial statements.
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations"
in August 2001. The standard requires the estimated present value of the cost of
decommissioning and certain other removal costs to be recorded as a liability,
along with an offsetting plant asset, when a decommissioning or other removal
obligation is incurred. We are currently evaluating the impacts of the new
standard, which is effective for the year beginning January 1, 2003.
In October 2001, the FASB issued 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. SFAS No. 144 is effective for the year
beginning January 1, 2002. This standard does 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 (PP&E)." This
proposed SOP would create a project timeline framework for capitalizing costs
related to PP&E construction, require that PP&E assets be accounted for at the
component level and require administrative and general cost incurred in support
of capital projects to be expensed in the current period. The AICPA plans to
issue the final SOP in the fourth quarter of 2002. We are currently evaluating
the impacts of the proposed SOP.
In 1986, APS entered into agreements with three separate special purpose
entity (SPE) lessors in order to sell and lease back interests in Palo Verde
Unit 2 (see Note 8). The leases are accounted for as operating leases in
accordance with GAAP. In February 2002, the FASB discussed issues related to
special purpose entities. It is expected that FASB will issue additional
guidance on accounting for SPEs later this year. As a result of future FASB
actions, we may be required to consolidate the Palo Verde SPEs in our financial
statements. If consolidation is required, the assets and liabilities of the SPEs
that relate to the sale-leaseback transactions would be reflected on our
consolidated balance sheets. The SPE debt that is not reflected on our
consolidated balance sheets is approximately $300 million at December 31, 2001.
Rating agencies have already considered this debt when evaluating our credit
ratings.
BUSINESS OUTLOOK
FINANCIAL OUTLOOK
We currently believe that it will be a challenge for us in 2002 to repeat
our 2001 earnings. For 2001, our reported income from continuing operations was
$327 million, or $3.85 per diluted share of common stock, and included charges
totaling $21 million before income taxes, or $0.15 per diluted share, that we do
not expect to recur related to our exposure to Enron and its affiliates. Our
earnings in 2002 are expected to be negatively affected by a significant
47
decrease in the earnings contribution from our marketing and trading activities
and retail electricity price decreases. These negative factors are expected to
be substantially offset in 2002 by the absence of significant expenses for
reliability and power plant outages that we incurred in 2001 that we do not
expect to recur in 2002 and by retail customer growth, although the pace of
growth is expected to be slower than in the past. These factors are described in
more detail below.
In 2001, our marketing and trading activities contributed about one-half of
our income from continuing operations before the Enron-related charges. These
activities are currently expected to provide about one-fourth of our earnings in
2002. The drivers of such reduced earnings contributions from our marketing and
trading activities in 2002 are significant reductions in wholesale market prices
for electricity that occurred during 2001; wholesale market liquidity, which
affects our ability to buy and resell electricity; and market volatility, which
affects our ability to capture profitable structured trading activities. These
reductions in regional market factors were due, in large part, to conservation
measures in California and throughout the West; more generating plants in
service in the West; lower natural gas prices; and the price mitigation plan
that took effect in June 2001 as mandated by the FERC.
During 2001, in order to meet the highest customer demand in APS' history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts
cost approximately $140 million before income taxes, which is not expected to be
repeated in 2002. See "Results of Operations - 2001 Compared with 2000" above.
We estimate our retail customer growth in 2002 to be 3.2%, which is slower
than the pace of growth in recent years, although still about three times the
national average. Our customer growth in 2001 was 3.7%. We expect the customer
growth rate to be weak in the first two quarters of 2002, then begin a rebound.
Our current estimate for customer growth in 2003 and 2004 is between 3.5% and
4.0% annually.
The retail price decreases are described above in "Results of Operations -
Regulatory Agreements."
As of December 31, 2001, the indicated annual dividend rate on our common
stock was $1.60 per share. Since 1994, we have increased the dividend on our
common stock ten cents per share per year. We currently plan to continue annual
dividend increases of relatively consistent amounts, which would continue
dividend growth at a pace above the industry average.
The foregoing discussion of future expectations is forward-looking
information. Actual results may differ materially from expectations. See
"Forward-Looking Statements" below.
48
OTHER FACTORS AFFECTING OUR FINANCIAL OUTLOOK
COMPETITION AND INDUSTRY RESTRUCTURING
ELECTRIC COMPETITION (WHOLESALE)
The FERC regulates rates for wholesale power sales and transmission
services. Our marketing and trading division sells in the wholesale market APS
and Pinnacle West Energy generation production output that is not needed for
APS' native load and, in doing so, competes with other utilities, power
marketers, and independent power producers. Wholesale market prices
significantly fell during 2001 and remain low for the reasons discussed under
"Financial Outlook" above. We cannot predict whether these lower prices will
continue, or whether changes in various factors that affect demand and capacity,
including regulatory actions, will cause the market prices to rise during 2002
or thereafter.
ELECTRIC COMPETITION (RETAIL)
On September 21, 1999, the ACC approved Rules that provide a framework for
the introduction of retail electric competition in Arizona. A Maricopa County,
Arizona, Superior Court later found the Rules unlawful and unconstitutional;
however, the Rules remain in effect pending the outcome of appeals. See "Retail
Electric Competition Rules" in Note 3 for additional information about the Rules
and the outstanding legal challenges to the Rules.
Although the Rules allow retail customers to have access to competitive
providers of energy and energy services, APS is the "provider of last resort"
for standard-offer, full service customers under rates that have been approved
by the ACC. These rates are established until July 1, 2004. The 1999 Settlement
Agreement allows APS to seek adjustment of these rates in the event of emergency
conditions or circumstances, such as the inability to secure financing on
reasonable terms, or material changes in APS' cost of service for ACC-regulated
services resulting from federal, tribal, state or local laws, regulatory
requirements, judicial decisions, actions or orders. Energy prices in the
western U.S. wholesale market vary and, during the course of the last two years,
have been volatile. At various times, prices in the spot wholesale market have
significantly exceeded the amount included in APS' current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation
outages, APS may need to purchase additional supplemental power in the wholesale
spot market. Unless APS is able to obtain an adjustment of its rates under the
1999 Settlement Agreement, there can be no assurance that APS would be able to
fully recover the costs of this power.
On September 23, 1999, the ACC approved a comprehensive 1999 Settlement
Agreement among APS and various parties related to the implementation of retail
electric competition in Arizona. See "1999 Settlement Agreement" in Note 3 for
additional information about the 1999 Settlement Agreement, including the recent
resolution of legal challenges to the 1999 Settlement Agreement.
Under the Rules, as modified by the 1999 Settlement Agreement, APS is
required to transfer all of its competitive electric assets and services either
to an unaffiliated party or to a separate corporate affiliate no later than
December 31, 2002. Consistent with that requirement, APS has been addressing the
legal and regulatory requirements necessary to complete the transfer of its
generation assets to Pinnacle West Energy on or before that date. In
anticipation of APS' transfer of generation assets, Pinnacle West Energy has
completed, and is in the process of developing and planning, various generation
49
expansion projects so that APS can reliably meet the energy requirements of its
Arizona customers.
Following APS' transfer of its fossil-fueled generation assets and the
receipt of certain regulatory approvals, Pinnacle West Energy expects to sell
its power at wholesale to our marketing and trading division, which, in turn, is
expected to sell power to APS and to non-affiliated power purchasers. In a
filing with the ACC on October 18, 2001, APS requested the ACC to:
* grant APS a partial variance from an ACC Rule that would obligate APS
to acquire all of its customers' standard-offer generation
requirements from the competitive market (with at least 50% of those
requirements coming from a "competitive bidding" process) starting in
2003; and
* approve as just and reasonable a long-term purchase power agreement
between APS and Pinnacle West.
APS requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load. See
"Proposed Rule Variance and Purchase Power Agreement" in Note 3 for additional
information about APS' October 2001 ACC filing.
On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to APS' October 2001 filing with several
other pending ACC dockets, including a "generic" docket request by the ACC
Chairman to "determine if changed circumstances require the [ACC] to take
another look at restructuring in Arizona." Although the order consolidates
several dockets, it states that a hearing on the APS matter will commence on
April 29, 2002. The order went on to state that, contrary to APS' position, the
ALJ was construing the October 2001 filing as a request by APS to amend the 1999
ACC order that approved the 1999 Settlement Agreement.
On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:
* The extent and manner of the ACC's involvement in monitoring market
conditions and/or mitigating the development of market power for
generation and transmission;
* The lack of guidance in the Rules regarding the mechanics of the
"competitive bidding process" referenced above;
* The consideration of alternatives to the transfer of generation assets
required by the Rules (the ACC Staff stated that such transfers would
be "unwise" at the present time and recommended that "all transfer and
separation of utilities' assets be stayed pending the completion of
the generic docket");
* The consideration of transmission constraints that could impact the
development of the wholesale power market;
* The reassessment of adjustor mechanisms for standard-offer rates in
light of problems with the development of a wholesale power market;
and
50
* The adequacy of customer "shopping credits" in the context of the
development of a competitive retail market (a shopping credit is the
cost a customer does not pay to a utility distribution company if the
customer obtains generation from another party).
Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between APS and
Pinnacle West.
A modification to the Rules or the 1999 Settlement Agreement as a result of
the consolidated docket could, among other things, adversely affect APS' ability
to transfer its generation assets to Pinnacle West Energy by December 31, 2002.
We cannot predict the outcome of the consolidated docket or its effect on the
specific requests in APS' October 2001 filing, the existing Arizona electric
competition rules, or the 1999 Settlement Agreement.
As a result of the foregoing matters, as well as energy market
developments, including those relating to California's failed deregulation
efforts and to Enron's recent bankruptcy filing, electric utility restructuring
is in a state of flux in the western United States, including Arizona, and
around the country.
GENERATION EXPANSION
See Note 10 for information regarding our generation expansion plans. The
planned additional generation is expected to increase revenues, fuel expenses,
operating expenses, and financing costs.
CALIFORNIA ENERGY MARKET ISSUES
See Note 10 for information regarding California energy market issues.
FACTORS AFFECTING OPERATING REVENUES
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.
In APS' regulated retail market area, APS will provide electricity services
to standard-offer, full service customers and to energy delivery customers who
have chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in APS' service territory averaged about 4% a year
for the three years 1999 through 2001; we currently expect customer growth to be
about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We
currently estimate that retail electricity sales in kilowatt-hours will grow
3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather
variations. The customer growth and sales growth referred to in this paragraph
apply to energy delivery customers. As industry restructuring evolves in the
regulated market area, we cannot predict the number of APS' standard-offer
customers that will switch to unbundled service. As previously noted, under the
1999 Settlement Agreement, we have annual retail electricity price reductions of
1.5% through July 1, 2003 (see Note 3).
51
Competitive sales of energy and energy-related products and services are
made by APSES in western states that have opened to competitive supply. Such
activities currently are not material to our consolidated financial results.
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, new generating plants being placed
in service and our hedging program for managing such costs. See "Generating Fuel
and Purchased Power - Natural Gas Supply" in Part I for additional information
on a pending dispute related to a natural gas-fired transportation contract with
El Paso Natural Gas Company.
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, outages and other factors.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, changes in regulatory
asset amortization, and our generation expansion program. See Note 1 for the
regulatory asset amortization that is being recorded in 1999 through 2004
pursuant to the 1999 Settlement Agreement. Also, see Note 1 regarding current
depreciation rates.
Taxes other than income taxes consist primarily of property taxes, which
are affected by tax rates and the value of property in service and under
construction. The average property tax rate for APS, which currently owns the
majority of our property, was 9.32% for 2001 and 9.16% for 2000. We expect
property taxes to increase primarily due to our generation expansion program and
our additions to existing facilities.
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 generation expansion program and
our internally-generated cash flow.
The annual earnings contribution from APSES is expected to be modest, yet
positive, over the next several years due primarily to a number of retail
electricity contracts in California. APSES' pretax losses were $10 million in
2001 and $13 million in 2000.
The annual earnings contribution from SunCor is expected to remain modest
over the next several years. SunCor's earnings were $3 million in 2001, $11
million in 2000 and $6 million in 1999.
El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. El Dorado's strategies focus on prudently realizing
the value of its existing investments. Any future investments are expected to be
related to the energy sector. See Note 1 for additional information regarding El
Dorado.
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. 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.
52
Our financial results may be affected by the application of SFAS No. 133.
See "Critical Accounting Policies" above and Note 17 for further information.
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.
INTEREST RATE AND EQUITY RISK
Our major financial market risk exposure is changing interest rates.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our nuclear decommissioning trust fund (see Note 11). Our
policy is to manage interest rates through the use of a combination of
fixed-rate and floating-rate debt. The nuclear decommissioning fund also has
risks associated with changing market values of equity investments. Nuclear
decommissioning costs are recovered in regulated electricity prices.
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, 2001 and 2000. The interest rates presented in
the tables below represent the weighted average interest rates for the years
ended December 31, 2001 and 2000.
Expected Maturity/Principal Repayment
December 31, 2001
(dollars in thousands)
Variable-Rate Fixed-Rate
Short-Term Debt Long-Term Debt Long-Term Debt
--------------------- ---------------------- ----------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
-------- ---------- -------- ----------- -------- -----------
2002 4.01% $ 405,762 7.76% $ 207 8.10% $ 125,933
2003 -- 4.75% 292,912 6.87% 25,829
2004 -- 5.32% 85,601 6.08% 205,677
2005 -- 7.70% 294 7.59% 400,380
2006 -- 7.30% 3,018 6.48% 384,085
Years thereafter -- 2.63% 480,740 6.73% 799,808
---------- ----------- -----------
Total $ 405,762 $ 862,772 $ 1,941,712
========== =========== ===========
Fair value $ 405,762 $ 862,772 $ 1,963,389
========== =========== ===========
53
Expected Maturity/Principal Repayment
December 31, 2000
(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
-------- ---------- -------- ----------- -------- -----------
2001 6.64% $ 82,775 7.23% $ 438,203 6.63% $ 25,266
2002 -- 8.62% 36,890 8.13% 125,000
2003 -- 8.61% 73,578 6.89% 25,443
2004 -- 8.87% 268 6.17% 205,000
2005 -- 8.89% 294 7.28% 400,000
Years thereafter -- 4.13% 483,790 7.47% 610,813
---------- ----------- -----------
Total $ 82,775 $ 1,033,023 $ 1,391,522
========== =========== ===========
Fair value $ 82,775 $ 1,033,023 $ 1,422,014
========== =========== ===========
COMMODITY PRICE RISK
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to 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 commodity.
In addition, subject to specified risk parameters established by the Board
of Directors and monitored by the Energy Risk Management Committee, we engage in
trading activities intended to profit from market price movements. In accordance
with Emerging Issues Task Force (EITF) 98-10, "Accounting For Contracts Involved
in Energy Trading and Risk Management Activities," such trading positions are
marked-to-market. These trading activities are part of our marketing and trading
activities and are reflected in the marketing and trading revenues and expenses.
The following schedule shows the changes in mark-to-market of our trading
positions during the years ended December 31, 2001 and 2000 (dollars in
millions):
2001 2000
---- ----
Mark-to-market of net trading positions
at beginning of year $ 12 $ --
Prior period mark-to-market gains
realized during the year (1) (2)
Change in mark-to-market gains for
future period deliveries 127 14
-------- --------
Mark-to-market of net trading positions
at end of year $ 138 $ 12
======== ========
54
Net gains at inception include a reasonable marketing margin and were
approximately $3 million in 2001 and $2 million in 2000. See Note 17 for
disclosure of risk management activities recorded on the consolidated balance
sheets.
The table below shows the maturities of our trading positions as of
December 31, 2001 in millions of dollars by the type of valuation that is
performed to calculate the fair value of the contract. In addition, see Note 1
for more discussion on our valuation methods.
2003- 2005- Years Total fair
Source of Fair Value 2002 2004 2006 thereafter value
-------------------- ----- ----- ----- ----- -----
Prices actively quoted $ (13) $ 4 $ 2 $ -- $ (7)
Prices provided by other external
sources (12) (8) (4) -- (24)
Prices based on models and other
valuation methods 68 50 39 12 169
----- ----- ----- ----- -----
Total by maturity $ 43 $ 46 $ 37 $ 12 $ 138
===== ===== ===== ===== =====
The table below shows the impact that hypothetical price movements of 10%
would have on the market value of our risk management and trading assets and
liabilities included on the consolidated balance sheets at December 31, 2001 and
2000 (dollars in millions):
December 31, 2001 December 31, 2000
Gain (Loss) Gain (Loss)
----------------------------- -----------------------------
Commodity Price Up 10% Price Down 10% Price Up 10% Price Down 10%
--------- ------------ -------------- ------------ --------------
Trading (a):
Electric $ (3) $ 3 $ 2 $ (2)
Natural gas (1) 1 (1) 1
Other -- 2 -- --
System (b):
Natural gas
hedges 23 (23) 28 (28)
------- ------- ------- -------
Total $ 19 $ (17) $ 29 $ (29)
======= ======= ======= =======
----------
(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
(b) These contracts are hedges of our forecasted purchases of natural gas. 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.
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including one counterparty for which a worst case exposure
represents approximately 50% of our $267 million of risk management and trading
assets as of December 31, 2001. We use a risk management process to assess and
monitor the financial exposure of this and all other counterparties. Despite the
fact that the great majority of trading counterparties are rated as investment
grade by the credit rating agencies,
55
including the counterparty noted above, there is still a possibility that one or
more of these companies could default, resulting in a material impact on
consolidated earnings for a given period. Counterparties in the portfolio
consist principally of major energy companies, municipalities, and local
distribution companies. We maintain credit policies that we believe minimize
overall credit risk to within acceptable limits. Determination of the credit
quality of our counterparties is based upon a number of factors, including
credit ratings and our evaluation of their financial condition. In many
contracts, we employ collateral requirements and standardized agreements that
allow for the netting of positive and negative exposures associated with a
single counterparty. Credit reserves are established representing our estimated
credit losses on our overall exposure to counterparties. See Note 1 for a
discussion of our credit reserve policy.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. 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 APS' October 2001 ACC filing; the outcome of
regulatory and legislative proceedings relating to the restructuring; state and
federal regulatory and legislative decisions and actions, including the price
mitigation plan adopted by the FERC in June 2001; 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; weather
variations affecting local and regional customer energy usage; conservation
programs; power plant performance; the successful completion of our generation
expansion program; regulatory issues associated with generation expansion, such
as permitting and licensing; our ability to compete successfully outside
traditional regulated markets (including the wholesale market); technological
developments in the electric industry; and the strength of the real estate
market in SunCor's market areas, which include Arizona, New Mexico and Utah.
These factors and the other matters discussed above may cause future
results to differ materially from historical results, or from results or
outcomes we currently expect or seek.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See "Market Risks" in Item 7 for a discussion of quantitative and
qualitative disclosures about market risk.
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
Report of Management....................................................... 58
Independent Auditors' Report............................................... 59
Consolidated Statements of Income for 2001, 2000 and 1999.................. 60
Consolidated Balance Sheets as of December 31, 2001 and 2000............... 62
Consolidated Statements of Cash Flows for 2001, 2000 and 1999.............. 64
Consolidated Statements of Changes in Common Stock Equity
for 2001, 2000 and 1999.................................................. 65
Notes to Consolidated Financial Statements................................. 66
Financial Statement Schedule for 2001, 2000 and 1999
Schedule II - Valuation and Qualifying Accounts for 2001, 2000
and 1999................................................................. 108
See Note 12 of Notes to Consolidated Financial Statements for the selected
quarterly financial data required to be presented in this Item.
57
REPORT OF MANAGEMENT
The responsibility for the integrity of our financial information rests
with management, which has prepared the accompanying financial statements and
related information. This information was prepared in accordance with generally
accepted accounting principles as appropriate in the circumstances, and based on
management's best estimates and judgments. These financial statements have been
audited by independent auditors and their report is included on the following
page.
Management maintains and relies upon systems of internal control. A
limiting factor in all systems of internal control is that the cost of the
system should not exceed the benefits to be derived. Management believes that
our system provides the appropriate balance between such costs and benefits.
Periodically the internal control system is reviewed by both our internal
auditors to test for compliance and our independent auditors in conjunction with
their audit of our financial statements. Reports issued by the internal auditors
are released to management, and such reports or summaries thereof are
transmitted to the Audit Committee of the Board of Directors and the independent
auditors on a timely basis. By letter dated February 8, 2002, to the Audit
Committee, our independent auditors confirmed that they are independent
accountants with respect to us within the meaning of the Securities Act and the
requirements of the Independence Standards Board.
The Audit Committee, composed solely of outside directors, meets
periodically with the internal auditors and independent auditors (as well as
management) to review the work of each. The internal auditors and independent
auditors have free access to the Audit Committee, without management present, to
discuss the results of their audit work.
Management believes that our systems, policies and procedures provide
reasonable assurance that operations are conducted in conformity with the law
and with management's commitment to a high standard of business conduct.
William J. Post Chris N. Froggatt
William J. Post Chris N. Froggatt
Chairman and Vice President and Controller
Chief Executive Officer
58
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle
West Capital Corporation and subsidiaries as of December 31, 2001 and 2000, and
the related consolidated statements of income, changes in common stock equity,
and cash flows for each of the three years in the period ended December 31,
2001. Our audits also included the financial statement schedule listed in the
Index at Item 14. These financial statements and the financial statement
schedule are the responsibility of the Corporation's management. Our
responsibility is to express an opinion on the financial statements and the
financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Pinnacle West Capital
Corporation and subsidiaries at December 31, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.
As discussed in Note 17 to the financial statements, in 2001 Pinnacle West
Capital Corporation changed its method of accounting for derivatives and hedging
activities in order to comply with the provisions of Statement of Financial
Accounting Standards No. 133.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 8, 2002 (March 22, 2002, as to Note 18)
59
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands, except per share amounts)
Year Ended December 31,
--------------------------------------
2001 2000 1999
---------- ---------- ----------
OPERATING REVENUES
Electric $4,382,465 $3,531,810 $2,293,184
Real estate 168,908 158,365 130,169
---------- ---------- ----------
Total 4,551,373 3,690,175 2,423,353
---------- ---------- ----------
OPERATING EXPENSES
Purchased power and fuel 2,664,218 1,932,792 793,931
Operations and maintenance 530,095 450,205 446,173
Real estate operations 153,462 134,422 119,516
Depreciation and amortization 427,903 431,229 419,842
Taxes other than income taxes 101,068 99,780 96,606
---------- ---------- ----------
Total 3,876,746 3,048,428 1,876,068
---------- ---------- ----------
OPERATING INCOME 674,627 641,747 547,285
---------- ---------- ----------
OTHER INCOME (EXPENSE)
Preferred stock dividend requirements
of APS -- -- (1,016)
Net other income and expense (5,765) (406) 10,573
---------- ---------- ----------
Total (5,765) (406) 9,557
---------- ---------- ----------
INTEREST EXPENSE
Interest charges 175,822 166,447 157,142
Capitalized interest (47,862) (21,638) (11,664)
---------- ---------- ----------
Total 127,960 144,809 145,478
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES 540,902 496,532 411,364
INCOME TAXES 213,535 194,200 141,592
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS 327,367 302,332 269,772
Income tax benefit from
discontinued operations -- -- 38,000
Extraordinary charge - net of income
taxes of $94,115
-- -- (139,885)
Cumulative effect of a change in
accounting for derivatives -
net of income taxes of $9,892 (15,201) -- --
---------- ---------- ----------
NET INCOME $ 312,166 $ 302,332 $ 167,887
========== ========== ==========
WEIGHTED-AVERAGE COMMON
SHARES OUTSTANDING - BASIC
84,718 84,733 84,717
WEIGHTED-AVERAGE COMMON
SHARES OUTSTANDING - DILUTED 84,930 84,935 85,009
EARNINGS PER WEIGHTED-
AVERAGE COMMON SHARE
OUTSTANDING
Continuing operations - basic $ 3.86 $ 3.57 $ 3.18
Net income - basic 3.68 3.57 1.98
Continuing operations - diluted 3.85 3.56 3.17
Net income - diluted 3.68 3.56 1.97
DIVIDENDS DECLARED PER
SHARE $ 1.525 $ 1.425 $ 1.325
========== ========== ==========
See Notes to Consolidated Financial Statements.
60
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61
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
------------------------
2001 2000
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 28,619 $ 10,363
Customer and other receivables - net 367,241 513,822
Accrued utility revenues 76,131 74,566
Materials and supplies (at average cost) 81,215 71,966
Fossil fuel (at average cost) 27,023 19,405
Deferred income taxes (Note 4) -- 5,793
Assets from risk management and trading
activities (Note 17) 66,973 17,506
Other current assets 80,203 80,492
---------- ----------
Total current assets 727,405 793,913
---------- ----------
INVESTMENTS AND OTHER ASSETS
Real estate investments - net (Note 1 and 6) 418,673 371,323
Assets from risk management and trading
activities- long term (Note 17) 200,351 32,955
Other assets 321,024 299,128
---------- ----------
Total investments and other assets 940,048 703,406
---------- ----------
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 8 and 9)
Plant in service and held for future use 8,203,888 7,809,566
Less accumulated depreciation and amortization 3,378,089 3,188,302
---------- ----------
Total 4,825,799 4,621,264
Construction work in progress 1,032,234 464,540
Nuclear fuel, net of accumulated amortization
of $56,836 and $61,256 49,282 47,389
---------- ----------
Net property, plant and equipment 5,907,315 5,133,193
---------- ----------
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4) 342,383 469,867
Other deferred debits 64,597 62,606
---------- ----------
Total deferred debits 406,980 532,473
---------- ----------
TOTAL ASSETS $7,981,748 $7,162,985
========== ==========
See Notes to Consolidated Financial Statements.
62
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
--------------------------
2001 2000
----------- -----------
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable $ 269,124 $ 375,805
Accrued taxes 96,729 89,246
Accrued interest 48,806 42,954
Short-term borrowings (Note 5) 405,762 82,775
Current maturities of long-term debt (Note 6) 126,140 463,469
Customer deposits 30,232 26,189
Deferred income taxes (Note 4) 3,244 --
Liabilities from risk management and trading
activities (Note 17) 35,994 37,179
Other current liabilities 74,898 73,681
----------- -----------
Total current liabilities 1,090,929 1,191,298
----------- -----------
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 2,673,078 1,955,083
----------- -----------
DEFERRED CREDITS AND OTHER
Liabilities from risk management and trading
activities-long term (Note 17) 207,576 14,711
Deferred income taxes (Note 4) 1,064,993 1,143,040
Unamortized gain - sale of utility plant (Note 8) 64,060 68,636
Other 381,789 407,503
----------- -----------
Total deferred credits and other 1,718,418 1,633,890
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES 3, 10 AND 11)
COMMON STOCK EQUITY
Common stock, no par value; authorized
150,000,000 shares; issued and outstanding
84,824,947 at end of 2001 and 2000 1,531,038 1,532,831
Retained earnings 1,032,850 849,883
Accumulated other comprehensive loss (64,565) --
----------- -----------
Total common stock equity 2,499,323 2,382,714
----------- -----------
TOTAL LIABILITIES AND EQUITY $ 7,981,748 $ 7,162,985
=========== ===========
See Notes to Consolidated Financial Statements.
63
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
Year Ended December 31,
-----------------------------------------
2001 2000 1999
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 327,367 $ 302,332 $ 269,772
Items not requiring cash
Depreciation and amortization 427,903 431,229 419,842
Nuclear fuel amortization 28,362 30,083 31,371
Deferred income taxes - net (16,939) (38,625) (43,886)
Deferred investment tax credit (264) 740 (23,514)
Mark-to-market gains - trading (125,521) (11,752) (975)
Mark-to-market gains - system (8,052) -- --
Changes in current assets and liabilities
Customer and other receivables - net 146,581 (269,223) (10,723)
Accrued utility revenues (1,565) (1,647) (5,179)
Materials, supplies and fossil fuel (16,867) 475 (8,794)
Other current assets 289 (37,436) (12,968)
Accounts payable (127,782) 193,502 28,193
Accrued taxes 7,483 18,736 12,591
Accrued interest 5,852 9,701 1,387
Other current liabilities 5,260 98,493 14,047
Change in El Dorado partnership investment 1,671 (3,773) (25,786)
Increase in real estate investments (44,173) (25,937) (12,542)
Increase in regulatory assets (17,516) (14,138) (12,262)
Other - net (21,159) 30,634 15,026
----------- ----------- -----------
Net cash flow provided by operating
activities 570,930 713,394 635,600
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (1,040,585) (658,608) (343,448)
Capitalized interest (47,862) (21,638) (11,664)
Other - net (31,357) (55,595) (16,143)
----------- ----------- -----------
Net cash flow used for investing activities (1,119,804) (735,841) (371,255)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 995,447 651,000 607,791
Short-term borrowings - net 322,987 44,475 (140,530)
Dividends paid on common stock (129,199) (120,733) (112,311)
Repayment of long-term debt (621,057) (558,019) (510,693)
Redemption of preferred stock -- -- (96,499)
Other - net (1,048) (4,618) (11,936)
----------- ----------- -----------
Net cash flow provided by (used for) financing
activities 567,130 12,105 (264,178)
----------- ----------- -----------
NET CASH FLOW 18,256 (10,342) 167
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 10,363 20,705 20,538
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT
END OF YEAR $ 28,619 $ 10,363 $ 20,705
=========== =========== ===========
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes $ 223,037 $ 219,411 $ 199,799
Interest paid, net of amounts capitalized $ 115,276 $ 132,434 $ 141,138
See Notes to Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
For the Years Ended December 31, 2001, 2000 and 1999
(dollars in thousands)
ACCUMULATED
OTHER
RETAINED COMPREHENSIVE
COMMON STOCK EARNINGS INCOME (LOSS) TOTAL
----------- ----------- ----------- -----------
Balance at December 31, 1998 $ 1,550,643 $ 612,708 $ -- $ 2,163,351
Net income 167,887 167,887
Dividends on common stock (112,311) (112,311)
Common stock expense (13,194) (13,194)
----------- ----------- ----------- -----------
Balance at December 31, 1999 1,537,449 668,284 -- 2,205,733
Net income 302,332 302,332
Dividends on common stock (120,733) (120,733)
Common stock expense (4,618) (4,618)
----------- ----------- ----------- -----------
Balance at December 31, 2000 1,532,831 849,883 -- 2,382,714
----------- ----------- ----------- -----------
Net income 312,166 312,166
Minimum pension liability, net of
$634 tax effect (966) (966)
Cumulative effect of change
in accounting for
derivatives, net of $47,404
tax effect 72,274 72,274
Unrealized loss on
derivative instruments, net
of $54,028 tax effect (82,373) (82,373)
Reclassification of net realized
gain to income, net of
$35,091 tax effect (53,500) (53,500)
----------- ----------- -----------
Comprehensive income (loss) 312,166 (64,565) 247,601
----------- ----------- -----------
Dividends on common stock (129,199) (129,199)
Common stock expense (1,793) (1,793)
----------- ----------- ----------- -----------
Balance at December 31, 2001 $ 1,531,038 $ 1,032,850 $ (64,565) $ 2,499,323
=========== =========== =========== ===========
See Notes to Consolidated Financial Statements.
65
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION AND NATURE OF OPERATIONS
The consolidated financial statements include the accounts of Pinnacle West
and our subsidiaries: APS, Pinnacle West Energy, APSES, SunCor, and El Dorado.
Significant intercompany accounts and transactions between the consolidated
companies have been eliminated.
APS, our major subsidiary and Arizona's largest electric utility, provides
either retail or wholesale electric service to substantially all of the state,
with the major exceptions of the Tucson metropolitan area and about one-half of
the Phoenix metropolitan area. APS also generates and, directly or through our
marketing and trading division, sells and delivers electricity to wholesale
customers in the western United States. During 2001, APS transferred most of its
marketing and trading activities to the parent company. Pinnacle West Energy,
which was formed in 1999, is the subsidiary through which we conduct our
unregulated generation operations. APSES was formed in 1998 and provides
commodity energy and energy-related products to key customers in competitive
markets in the western United States. SunCor is a developer of residential,
commercial, and industrial real estate projects in Arizona, New Mexico, and
Utah. El Dorado is an investment firm.
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 and 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 current year presentation.
DERIVATIVE INSTRUMENTS
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to 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 commodity.
In addition, subject to specified risk parameters established by the Board
of Directors and monitored by the ERMC, we engage in trading activities intended
to profit from market price movements. If a contract was entered into for
trading purposes, we account for it in accordance with EITF 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities." EITF
98-10 requires energy trading contracts to be measured at fair value as of the
balance sheet date, with unrealized gains and losses included in earnings on a
current basis (the mark-to-market method). See "Mark-to-Market Method" below and
Note 17 for further information about our trading contracts.
66
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We examine contracts at inception to determine the appropriate accounting
treatment. If a contract is not considered energy trading we must determine if
it is a derivative as defined in SFAS No. 133 (see Note 17 for further
information on SFAS No. 133). 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 using accrual accounting (this means that costs and revenues are
recorded when physical delivery occurs). 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. 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
(mark-to-market). If it does qualify for hedge accounting, changes in the fair
value are recognized as either an asset or liability or in stockholders' equity
(as a component of accumulated other comprehensive income) depending on the
nature of the hedge.
Gains and losses related to derivatives that qualify as cash flow hedges of
expected transactions are recognized in revenue or fuel and purchased power
expense as an offset to the related item being hedged when the underlying hedged
physical transaction impacts earnings (deferral method). See Note 17 for further
discussion on derivative accounting.
MARK-TO-MARKET METHOD
Under mark-to-market accounting the purchase or sale of energy commodities
are reflected at fair market value, net of reserves, with resulting unrealized
gains and losses recorded as assets and liabilities from risk management and
trading activities in the consolidated balance sheets.
We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. We shape quarterly and calendar year quotes into monthly
prices based on historical relationships.
For options, long-term contracts and other contracts where price quotes are
not available, we use models and other valuation methods. For illiquid or
unquoted market locations, we consider the historical relationship to
readily-available market quotations. The valuation models we employ utilize spot
prices, forward prices, historical market data and other factors to forecast
future prices.
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 reserves for a number of risks associated with the
valuation of future commitments. These include reserves for liquidity and credit
risks based on the financial condition of counterparties. The liquidity reserve
represents the cost that would be incurred if all unmatched positions were
closed-out or hedged. As we mark positions to a mid-market value this reserve
adjusts the mid-market valuation to the bid or offer, after taking into
consideration offsetting positions, to reflect the true cash flow that would be
realized upon exiting the net position.
67
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A credit reserve 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.
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. However,
essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is substantially
hedged with a portfolio of forward purchases that protects the economic value of
the sales transactions. Our practice is to hedge within timeframes established
by the ERMC.
REGULATORY ACCOUNTING
APS is regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.
During 1997, the EITF of the FASB issued EITF 97-4. EITF 97-4 requires that
SFAS No. 71 be discontinued no later than when 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, which could result in write-downs or
write-offs of physical and/or regulatory assets. Additionally, the EITF
determined that regulatory assets should not be written off if they are to be
recovered from a portion of the entity which continues to apply SFAS No. 71.
The 1999 Settlement Agreement was approved by the ACC in September 1999
(see Note 3 for a discussion of the agreement). Consequently, we have
discontinued the application of SFAS No. 71 for our generation operations. As a
result, we tested the generation assets for impairment and determined that 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 income statement during the third quarter of
1999. Prior to the 1999 Settlement Agreement, under the 1996 regulatory
agreement (see Note 3), the ACC accelerated the amortization of substantially
all of our regulatory assets to an eight-year period that would have ended June
30, 2004.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The regulatory assets to be recovered under the 1999 Settlement Agreement
are currently being amortized as follows (dollars in millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
Regulatory assets are reported as deferred debits on the consolidated balance
sheets. As of December 31, 2001 and 2000, they are comprised of the following
(dollars in millions):
December 31,
-----------------
2001 2000
------ ------
Remaining balance recoverable under the 1999
Settlement Agreement (a) $ 219 $ 364
Spent fuel storage (Note 10) 43 40
Electric industry restructuring transition costs (Note 3) 34 24
Other 46 42
------ ------
Total regulatory assets $ 342 $ 470
====== ======
----------
(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
consolidated balance sheets. As of December 31, 2001 and 2000, they are
comprised of the following (dollars in millions):
December 31,
-----------------
2001 2000
------ ------
Deferred gains on utility property $ 20 $ 20
Other 7 8
------ ------
Total regulatory liabilities $ 27 $ 28
====== ======
69
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The consolidated balance sheets include the amounts listed below for
generation assets not subject to SFAS No. 71 (dollars in millions):
December 31,
--------------------
2001 2000
------- -------
Electric plant in service and held for future use .... $ 3,954 $ 3,854
Accumulated depreciation and amortization ............ (1,990) (1,902)
Construction work in progress ........................ 824 304
Nuclear fuel, net of amortization .................... 49 47
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 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. For
the years 1999 through 2001 the rates, as prescribed by our regulators, ranged
from a low of 1.49% to a high of 20%. The weighted-average rate was 3.40% for
2001, 3.40% for 2000, and 3.34% for 1999. We depreciate non-utility property and
equipment over the estimated useful lives of the related assets, ranging from 3
to 30 years. We expense the costs of plant outages, major maintenance and
routine maintenance as incurred.
EL DORADO INVESTMENTS
El Dorado accounts for its investments using the equity method. Net other
income has consisted primarily of El Dorado's share of the earnings of a venture
capital partnership. We record our share of the earnings from the partnership as
the partnership adjusts the value of its investments. In 2001, El Dorado
received a distribution of securities representing substantially all of El
Dorado's investment in the partnership. The securities were sold in the first
quarter of 2001 and a gain was recognized in other income. The book value of El
Dorado's investment in the partnership was approximately $1 million at December
31, 2001, and $7 million at December 31, 2000. El Dorado's net investment book
value was approximately $10 million at December 31, 2001 and $21 million at
December 31, 2000.
70
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CAPITALIZED INTEREST
Capitalized interest represents the cost of debt funds used to finance
construction of utility plants. Plant construction costs, including capitalized
interest, are expensed through depreciation when completed projects are placed
into commercial operation. Capitalized interest does not represent current cash
earnings. The rate used to calculate capitalized interest was a composite rate
of 6.13% for 2001, 6.62% for 2000, and 6.65% for 1999.
REVENUES
We record electric operating revenues on the accrual basis, which includes
estimated amounts for service rendered but unbilled at the end of each
accounting period. We exclude sales taxes on electric revenues from both revenue
and taxes other than income taxes. Electric revenues are recorded gross on the
statements of income, with the exception of unrealized gains and losses recorded
under the mark-to-market method (see discussion above). Unrealized gains and
losses are recorded net in electric revenues. When the gain or loss is realized,
the gross amount is recorded as electric revenue and fuel or purchased power
expense in the consolidated statements of income.
CASH AND CASH EQUIVALENTS
For purposes of the statement of cash flows, we consider all highly liquid
debt instruments purchased with an initial maturity of three months or less to
be cash equivalents.
RATE SYNCHRONIZATION COST DEFERRALS
As authorized by the ACC, operating costs (excluding fuel) and financing
costs of Palo Verde Units 2 and 3 were deferred from the commercial operation
dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the
units were included in a rate order (April 1988 for Unit 2 and December 1991 for
Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate the amortization of the deferrals over an eight-year period that will
end June 30, 2004. Amortization of the deferrals is included in depreciation and
amortization expense in the consolidated statements of income.
NUCLEAR FUEL
APS charges nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method that is based on
actual physical usage. APS divides the cost of the fuel by the estimated number
of thermal units that it expects to produce with that fuel. APS then multiplies
that rate by the number of thermal units that it produces within the current
period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The United States Department of Energy (DOE) is responsible for
the permanent disposal of spent nuclear fuel, and it charges APS $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.
71
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INCOME TAXES
Income taxes are provided using the asset and liability approach prescribed
by SFAS No. 109. We file our federal income tax return on a consolidated basis
and we file our state income tax returns on a consolidated or unitary basis. In
accordance with our intercompany tax sharing agreement, federal and state income
taxes are allocated to each subsidiary as though each subsidiary filed a
separate income tax return. Any difference between the aforementioned
allocations and the consolidated (and unitary) income tax liability is
attributed to the parent company.
REACQUIRED DEBT COSTS
For debt related to the regulated portion of APS' business, APS amortizes
those gains and losses incurred upon early retirement over the remaining life of
the debt. In accordance with the 1999 Settlement Agreement, APS is continuing to
accelerate reacquired debt costs over an eight-year period that will end June
30, 2004. All regulatory asset amortization is included in depreciation and
amortization expense in the consolidated statements of income.
REAL ESTATE INVESTMENTS
Real estate investments primarily include SunCor's land, home inventory and
investments in joint ventures. Land includes acquisition costs, infrastructure
costs, property taxes and capitalized interest directly associated with the
acquisition and development of each project. Land under development and land
held for future development are stated at accumulated cost, except to the extent
that such land is believed to be impaired, it is written down to fair value.
Land held for sale is stated at the lower of accumulated cost or estimated fair
value less costs to sell. Home inventory consists of construction costs,
improved lot costs, capitalized interest and property taxes on homes under
construction. Home inventory is stated at the lower of accumulated cost or
estimated fair value less costs to sell. Investments in joint ventures for which
SunCor does not have a controlling financial interest are not consolidated but
are accounted for using the equity method of accounting.
2. ACCOUNTING MATTERS
In July 2001, the FASB issued 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." This standard is effective for the year beginning January
1, 2002. We have no goodwill recorded in our consolidated balance sheets. The
impacts of this new standard are not material to our financial statements.
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." The standard requires the estimated present value of
the cost of decommissioning and certain other removal costs to be recorded as a
liability, along with an offsetting plant asset, when a decommissioning or other
removal obligation is incurred. We are currently evaluating the impacts of the
new standard, which is effective for the year beginning January 1, 2003.
In October 2001, the FASB issued 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. SFAS No. 144 is effective for the year
72
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
beginning January 1, 2002. This standard does 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 (PP&E) construction, which require that PP&E
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. The AICPA plans to issue the final SOP in the fourth quarter of
2002.
In 1986, APS entered into agreements with three separate special purpose
entity (SPE) lessors in order to sell and lease back interests in Palo Verde
Unit 2 (see Note 8). The leases are accounted for as operating leases in
accordance with GAAP. In February 2002, the FASB discussed issues related to
special purpose entities. It is expected that FASB will issue additional
guidance on accounting for SPEs later this year. As a result of future FASB
actions, we may be required to consolidate the Palo Verde SPEs in our financial
statements. If consolidation is required, the assets and liabilities of the SPEs
that relate to the sale-leaseback transactions would be reflected on our
consolidated balance sheets. The SPE debt that is not reflected on our
consolidated balance sheets is approximately $300 million at December 31, 2001.
Rating agencies have already considered this debt when evaluating our credit
ratings.
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE
1999 SETTLEMENT AGREEMENT. On May 14, 1999, APS entered into a
comprehensive 1999 Settlement Agreement with various parties, including
representatives of major consumer groups, related to the implementation of
retail electric competition. On September 23, 1999, the ACC voted to approve the
1999 Settlement Agreement, with some modifications.
On December 13, 1999, two parties filed lawsuits challenging the ACC's
approval of the 1999 Settlement Agreement. Each party bringing the lawsuits
appealed the ACC's order approving the 1999 Settlement Agreement directly to the
Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on
December 26, 2000, the Arizona Court of Appeals affirmed the ACC's approval of
the 1999 Settlement Agreement. This decision was not appealed and has become
final. In the other appeal, on April 5, 2001, the Arizona Court of Appeals again
affirmed the ACC's approval of the 1999 Settlement Agreement. The Arizona
Consumers Council, which filed that appeal, petitioned the Arizona Supreme Court
for review of the Court of Appeals' decision. On October 5, 2001, the Arizona
Supreme Court agreed to hear the appeal on the single issue of whether the ACC
could itself become a party to the 1999 Settlement Agreement by virtue of its
approval of the 1999 Settlement Agreement. On December 14, 2001, the Arizona
Supreme Court vacated its own October 5, 2001 order accepting jurisdiction and
decided to dismiss the appeal. As a result, the judicial challenges to the 1999
Settlement Agreement have terminated. Consistent with its obligations under the
1999 Settlement Agreement, on January 7, 2002, APS and the ACC filed in Maricopa
County, Arizona Superior Court a stipulation to dismiss all of APS' litigation
73
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
pending against the ACC. On January 15, 2002, a Maricopa County Superior Court
judge issued an order dismissing such litigation.
The following are the major provisions of the 1999 Settlement Agreement, as
approved:
* APS has reduced, and will reduce, rates for standard-offer service for
customers with loads less than three MW in a series of annual retail
electricity price reductions of 1.5% beginning July 1, 1999 through
July 1, 2003, for a total of 7.5%. The first reduction of
approximately $24 million ($14 million after income taxes) included
the July 1, 1999 retail price decrease of approximately $11 million
($7 million after income taxes) related to the 1996 regulatory
agreement. See "1996 Regulatory Agreement" below. Based on the price
reductions authorized in the 1999 Settlement Agreement, there were
also retail price decreases of approximately $28 million ($17 million
after taxes), or 1.5%, effective July 1, 2000, and approximately $27
million ($16 million after taxes), or 1.5%, effective July 1, 2001.
For customers having loads three MW or greater, standard-offer rates
will be reduced in varying annual increments that total 5% in the
years 1999 through 2002.
* Unbundled rates being charged by APS for competitive direct access
service (for example, distribution services) became effective upon
approval of the 1999 Settlement Agreement, retroactive to July 1,
1999, and also became subject to annual reductions beginning January
1, 2000, that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard-offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
limited circumstances. Neither the ACC nor APS will be prevented from
seeking or authorizing rate changes prior to July 1, 2004 in the event
of conditions or circumstances that constitute an emergency, such as
an inability to finance on reasonable terms, or material changes in
APS' cost of service for ACC-regulated services resulting from
federal, tribal, state or local laws, regulatory requirements,
judicial decisions, actions or orders.
* APS will be permitted to defer for later recovery prudent and
reasonable costs of complying with the ACC electric competition rules,
system benefits costs in excess of the levels included in then-current
(1999) rates, and costs associated with the "provider of last resort"
and standard-offer obligations for service after July 1, 2004. These
costs are to be recovered through an adjustment clause or clauses
commencing on July 1, 2004.
* APS' distribution system opened for retail access effective September
24, 1999. Customers were eligible for retail access in accordance with
the phase-in adopted by the ACC under the electric competition rules
(see "Retail Electric Competition Rules" below), including an
additional 140 MW being made available to eligible non-residential
customers. APS opened its distribution system to retail access for all
customers on January 1, 2001.
74
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* Prior to the 1999 Settlement Agreement, APS was recovering
substantially all of its regulatory assets through July 1, 2004,
pursuant to the 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that APS has demonstrated that its
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value. APS will not be
allowed to recover $183 million net present value of the above
amounts. The 1999 Settlement Agreement provides that APS will have the
opportunity to recover $350 million net present value through a
competitive transition charge that will remain in effect through
December 31, 2004, at which time it will terminate. The costs subject
to recovery under the adjustment clause described above will be
decreased or increased by any over/under-recovery due to sales volume
variances.
* APS will form, or cause to be formed, a separate corporate affiliate
or affiliates and transfer to such affiliate(s) its competitive
electric assets and services at book value as of the date of transfer,
and will complete the transfer no later than December 31, 2002.
Accordingly, APS plans to complete the move of such assets and
services from APS to the parent company or to Pinnacle West Energy by
the end of 2002, as required, although the ACC's recent establishment
of a "generic" docket to consider electric industry restructuring in
Arizona and the consolidation of that docket with APS' request for
approval of a PPA between Pinnacle West and APS could affect APS'
ability to transfer assets to Pinnacle West Energy. APS will be
allowed to defer and later collect, beginning July 1, 2004,
sixty-seven percent of its costs to accomplish the required transfer
of generation assets to an affiliate.
As discussed in Note 1 above, we have discontinued the application of SFAS
No. 71 for our generation operations.
PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. As authorized by the
1999 Settlement Agreement, APS intends to move substantially all of its
generation assets to Pinnacle West Energy no later than December 31, 2002.
Commencing upon the transfer of the fossil-fueled generating assets and the
receipt of certain regulatory approvals, Pinnacle West Energy expects to sell
its power at wholesale to Pinnacle West's marketing and trading division, which,
in turn, is expected to sell power to APS and to non-affiliated power
purchasers. In a filing with the ACC on October 18, 2001, APS requested the ACC
to:
* grant APS a partial variance from an ACC rule that would obligate APS
to acquire all of its customers' standard-offer, full-service
generation requirements from the competitive market (with at least 50%
of those requirements coming from a "competitive bidding" process)
starting in 2003; and
* approve as just and reasonable a long-term purchase power agreement
(PPA) between APS and Pinnacle West.
APS has requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load. The
following are the major provisions of the PPA:
75
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* The PPA would run through 2015, with three optional five-year renewal
terms, which renewals would occur automatically unless notice is given
by either APS or Pinnacle West.
* The PPA would provide for all of APS' anticipated standard-offer
generation needs, including any necessary reserves, except for (a)
those provided by APS itself through renewable resources or other
generation assets retained by APS; (b) amounts that APS is obligated
by law to purchase from "qualified facilities" and other forms of
distributed generation; and (c) any purchased power agreements that
APS cannot transfer to Pinnacle West Energy.
* Pinnacle West would assume contractual responsibility for reliability
and would supplement any potential shortfall even after full
utilization of Pinnacle West Energy's dedicated generating resources.
* Pinnacle West would supply APS standard-offer requirements through a
combination of (a) APS generation assets transferred to Pinnacle West
Energy; (b) certain of Pinnacle West Energy's new Arizona generation
projects to be constructed during the 2001-2004 period to reliably
serve APS load requirements; (c) power procured by Pinnacle West under
certain "dedicated contracts"; and (d) power procured on the open
market, including a competitively-bid component described below.
* Beginning in 2003, Pinnacle West would acquire 270 MW of APS
standard-offer requirements on the open market through a competitive
bidding process. This competitive bid obligation would be increased by
an additional 270 MW each year through 2008 (representing
approximately 23% of estimated 2008 peak load).
* Pinnacle West would charge APS based on (a) a combination of fixed and
variable price components for the Pinnacle West Energy assets, subject
to periodic adjustment, and (b) a pass-through of Pinnacle West's
costs to procure power from the remaining sources.
* The PPA would take effect on the latest of the following events: (a)
transfer of non-nuclear generating assets from APS to Pinnacle West
Energy; (b) ACC approval of the rule variance and the PPA; and (c) the
FERC's acceptance of the PPA and the companion agreement between
Pinnacle West and Pinnacle West Energy.
APS is required to transfer its competitive electric assets and services to
one or more corporate affiliates on or before December 31, 2002. Consistent with
that requirement, APS has been addressing the legal and regulatory requirements
necessary to complete the transfer of its generation assets to Pinnacle West
Energy, on or before that date. In anticipation of APS' transfer of generation
assets, Pinnacle West Energy has completed, and is the process of developing and
planning, various generation expansion projects so that APS can reliably meet
the energy requirements of its Arizona customers.
76
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
By letter dated January 14, 2002, the Chairman of the ACC stated that "the
[ACC's] Electric Competition Rules, along with the Settlement Agreements
approved for APS and [Tucson Electric Company], establish the framework for the
transition to a retail generation competitive market." The ACC Chairman then
recommended that the ACC establish a new "generic" docket to "determine if
changed circumstances require the [ACC] to take another look at electric
restructuring in Arizona." Matters that would be addressed by the ACC in the new
docket would include:
* whether the ACC should continue implementation of the retail electric
competition Rules adopted by the ACC in 1999 in their current form or
with modifications;
* whether the ACC should "slow the pace of the implementation of the
[Rules] to provide an opportunity to consider the extent to which
[Rule] modification and variance is in the public interest, including
changing the direction to retail electric competition"; and
* whether the ACC should "step back from electric industry restructuring
until the [ACC] is convinced that there exists a viable competitive
wholesale electric market to support retail electric competition in
Arizona."
On January 22, 2002 the ACC's Chief ALJ issued a procedural order by which
a generic docket was opened. On February 8, 2002, the ACC's ALJ issued a
procedural order which consolidated the ACC docket relating to APS' October 2001
filing with several other pending ACC dockets, including the generic docket.
Although the order consolidates several dockets, it states that a hearing on the
APS matter will commence on April 29, 2002. The order went on to state that,
contrary to APS' position, the ALJ was construing the October 2001 filing as a
request by APS to amend the ACC order that approved the 1999 Settlement
Agreement.
On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:
* The extent and manner of the ACC's involvement in monitoring market
conditions and/or mitigating the development of market power for
generation and transmission;
* The lack of guidance in the Rules regarding the mechanics of the
"competitive bidding process" referenced above;
* The consideration of alternatives to the transfer of generation assets
required by the Rules (the ACC Staff stated that such transfers would
be "unwise" at the present time and recommended that "all transfer and
separation of utilities' assets be stayed pending the completion of
the generic docket");
* The reassessment of adjustor mechanisms for standard-offer rates in
light of problems with the development of a wholesale power market;
and
77
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* The adequacy of customer "shopping credits" in the context of the
development of a competitive retail market (a shopping credit is the
cost a customer does not pay to a utility distribution company if the
customer obtains generation from another party).
Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between APS and
Pinnacle West.
A modification to the competition Rules or the 1999 Settlement Agreement
could, among other things, adversely affect APS' ability to transfer its
generation assets to Pinnacle West Energy by December 31, 2002. Pinnacle West
cannot predict the outcome of the consolidated docket or its effect on the
specific requests in APS' October 2001 filing, the existing Arizona electric
competition rules, or the 1999 Settlement Agreement.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve Rules that provide a framework for the introduction of retail electric
competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be
interpreted and applied, to the greatest extent possible, in a manner consistent
with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must
seek, and the other parties to the 1999 Settlement Agreement must support, a
waiver of the Rules in favor of the 1999 Settlement Agreement. On December 8,
1999, APS filed a lawsuit to protect its legal rights regarding the Rules. This
lawsuit has been dismissed.
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 APSES, to operate in Arizona. We do not believe the ruling affects the
1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the
consolidated cases before the judge. Further, the ACC made findings related to
the fair value of APS' property in the order approving the 1999 Settlement
Agreement. The ACC and other parties aligned with the ACC have 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. 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
case has been appealed to the Arizona Supreme Court, where a decision is
pending.
The Rules approved by the ACC include the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by
the ACC, including APS.
* Effective January 1, 2001, retail access became available to all APS
retail electricity customers.
* Electric service providers that get CC&N's from the ACC can supply
only competitive services, including electric generation, but not
electric transmission and distribution.
78
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* 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 either to an unaffiliated party or to a
separate corporate affiliate. Under the 1999 Settlement Agreement, APS
received a waiver to allow transfer of its competitive electric assets
and services to affiliates no later than December 31, 2002. APS plans
to complete the move of such assets by the end of 2002, as required,
although the ACC's recent establishment of a "generic" docket to
consider electric industry restructuring in Arizona and the
consolidation of that docket with APS' request for approval of a PPA
between Pinnacle West and APS could affect APS' ability to transfer
assets to Pinnacle West Energy (see "Proposed Rule Variance and
Purchase Power Agreement" above).
PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail
customers to have access to competitive providers of energy and energy services
(see "Retail Electric Competition Rules" below), APS is the "provider of last
resort" for standard-offer, full-service customers under rates that have been
approved by the ACC. These rates are established until July 1, 2004. The 1999
Settlement Agreement allows APS to seek adjustment of these rates in the event
of emergency conditions or circumstances, such as the inability to secure
financing on reasonable terms, or material changes in APS' cost of service for
ACC-regulated services resulting from federal, tribal, state or local laws,
regulatory requirements, judicial decisions, actions or orders. Energy prices in
the western wholesale market vary and, during the course of the last two years,
have been volatile. At various times, prices in the spot wholesale market have
significantly exceeded the amount included in APS' current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation
outages, APS may need to purchase additional supplemental power in the wholesale
spot market. Unless APS is able to obtain an adjustment of its rates under the
emergency provisions of the 1999 Settlement Agreement, there can be no assurance
that APS would be able to fully recover the costs of this power.
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and APS. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (dollars in millions):
79
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Annual Electric Percentage
Revenue Decrease Decrease Effective Date
---------------- -------- --------------
$49 3.4% July 1, 1996
$18 1.2% July 1, 1997
$17 1.1% July 1, 1998
$11 0.7% July 1, 1999 (a)
----------
(a) Included in the first rate reduction under the 1999 Settlement Agreement
(see above).
The regulatory agreement also required that we infuse $200 million of
common equity into APS in annual payments of $50 million from 1996 through 1999.
All of these equity infusions were made by December 31, 1999.
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River
Project) and, at their option, smaller municipal electric systems must
(i) make at least 20% of their 1995 retail peak demand available to
electric service providers by December 31, 1998 and for all retail
customers by December 31, 2000; (ii) decrease rates by at least 10%
over a ten-year period beginning as early as January 1, 1991; (iii)
implement procedures and public processes comparable to those already
applicable to public service corporations for establishing the terms,
conditions, and pricing of electric services as well as certain other
decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt
River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive
basis during the first two years of competition only for customers
having demands in excess of one MW (and that are eligible for
competitive generation services), and thereafter for all customers
receiving competitive electric generation.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. 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.
FEDERAL
In June 2001, 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 plan remains in effect until September 30, 2002. We cannot
accurately predict the overall financial impact of the plan on the various
aspects of our business, including our wholesale and purchased power activities.
80
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. INCOME TAXES
INCOME TAXES
Certain assets and liabilities are reported differently for income tax
purposes than they are for financial statements. The tax effect of these
differences is recorded as deferred taxes. We calculate deferred taxes using the
current income tax rates.
APS has recorded a regulatory asset related to income taxes on its balance
sheets in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. APS amortizes this amount as the differences reverse. In
accordance with the 1999 Settlement Agreement, APS is continuing to accelerate
its amortization of the regulatory asset for income taxes over an eight-year
period that will end June 30, 2004 (see Note 1). We are including all regulatory
asset amortization in depreciation and amortization expense on our consolidated
statements of income. The components of income tax expense for continuing
operations are (dollars in thousands):
Year Ended December 31,
-------------------------------------
2001 2000 1999
--------- --------- ---------
Current
Federal $ 184,893 $ 189,779 $ 171,491
State 45,845 42,306 37,501
--------- --------- ---------
Total current 230,738 232,085 208,992
Deferred (16,939) (38,625) (43,886)
ITC amortization (264) 740 (23,514)
--------- --------- ---------
Total expense $ 213,535 $ 194,200 $ 141,592
========= ========= =========
The following chart compares pretax income at the 35% federal income tax rate to
income tax expense (dollars in thousands):
81
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31,
-----------------------------------
2001 2000 1999
--------- --------- ---------
Federal income tax expense at 35%
statutory rate $ 189,316 $ 173,786 $ 143,977
Increases (reductions) in tax expense
resulting from:
Preferred stock dividends of APS -- -- 356
ITC amortization (264) 740 (23,514)
State income tax net of federal income
tax benefit 23,353 19,848 19,595
Other 1,130 (174) 1,178
--------- --------- ---------
Income tax expense $ 213,535 $ 194,200 $ 141,592
========= ========= =========
The components of the net deferred income tax liability were as follows (dollars
in thousands):
December 31,
-------------------------
2001 2000
---------- ----------
DEFERRED TAX ASSETS
Deferred gain on Palo Verde Unit 2 sale-leaseback $ 25,374 $ 27,056
Risk management and trading activities 73,043 15,002
Other 110,002 94,306
---------- ----------
Total deferred tax assets 208,419 136,364
---------- ----------
DEFERRED TAX LIABILITIES
Plant-related 1,069,207 1,081,637
Regulatory asset for income taxes 121,757 172,082
Risk management and trading activities 85,692 19,892
---------- ----------
Total deferred tax liabilities 1,276,656 1,273,611
---------- ----------
Accumulated deferred income taxes - net $1,068,237 $1,137,247
========== ==========
INVESTMENT TAX CREDIT
Because of a 1994 rate settlement agreement, we accelerated amortization of
substantially all of our ITCs over a five-year period that ended December 31,
1999.
INCOME TAX BENEFIT FROM DISCONTINUED OPERATIONS
In 1999, the income tax benefit from discontinued operations for $38
million resulted from resolution of tax issues related to a former subsidiary,
MeraBank, A Federal Savings Bank.
82
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. LINES OF CREDIT
APS had committed lines of credit with various banks of $250 million at
December 31, 2001 and 2000, which were available either to support the issuance
of commercial paper or to be used for bank borrowings. The commitment fees at
December 31, 2001 and 2000 for these lines of credit were 0.09% per annum. APS
had no bank borrowings outstanding under these lines of credit at December 31,
2001 and 2000.
APS' commercial paper borrowings outstanding were $171 million at December
31, 2001 and $82 million at December 31, 2000. The weighted average interest
rate on commercial paper borrowings was 4.72% for the year ended December 31,
2001 and 6.64% for the year ended December 31, 2000. By Arizona statute, APS'
short-term borrowings cannot exceed 7% of its total capitalization unless
approved by the ACC.
Pinnacle West had committed lines of credit with various banks of $250
million at December 31, 2001 and 2000, which were available either to support
the issuance of commercial paper or to be used for bank borrowings. The
commercial paper program was launched in May 2001. The commitment fees ranged
from 0.10% to 0.15% in 2001 and 2000. There were no short-term bank borrowings
outstanding at December 31, 2001 and $188 million outstanding at December 31,
2000. Pinnacle West commercial paper borrowings were $235 million at December
31, 2001. The weighted average interest rate on commercial paper borrowings was
3.50% for the year ended December 31, 2001.
SunCor had revolving lines of credit totaling $140 million at December 31,
2001 and $120 million at December 31, 2000. The commitment fees were 0.125% in
2001 and 2000. SunCor had $128 million outstanding at December 31, 2001 and $110
million outstanding at December 31, 2000. The balance is included in long-term
debt on the consolidated balance sheets (see Note 6).
6. LONG-TERM DEBT
Borrowings under the APS mortgage bond indenture are secured by
substantially all utility plant. APS also has unsecured debt. SunCor's debt is
collateralized by interests in certain real property and Pinnacle West's debt is
unsecured. The following table presents the components of consolidated long-term
debt outstanding at December 31, 2001 and 2000:
83
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
December 31,
Maturity Interest --------------------------
Dates (a) Rates 2001 2000
--------- ----- ----------- -----------
APS
First mortgage bonds 2002 8.125% $ 125,000 $ 125,000
2004 6.625% 80,000 80,000
2021 9.5% -- 45,140
2021 9.0% -- 72,370
2023 7.25% 54,150 70,650
2024 8.75% 121,668 121,668
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 (5,266) (5,993)
Adjustable
Pollution control bonds 2024-2034 rate(b) 386,860 476,860
Pollution control bonds 2029 3.30%(c) 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 --
Adjustable
Floating rate notes 2001 rate(d) -- 250,000
Senior notes (e) 2006 6.75% 83,695 83,695
Capitalized lease obligation 2001-2003 7.75% 417 709
Capitalized lease obligation 2006 5.89% 926 --
----------- -----------
Subtotal 2,074,525 2,057,174
----------- -----------
SUNCOR
Revolving credit 2003-2004 (f) 128,000 110,000
Notes payable 2001-2008 (g) 7,912 8,163
Bonds payable 2024 5.95% 5,215 5,215
Bonds payable 2026 6.75% 7,500 --
----------- -----------
Subtotal 148,627 123,378
----------- -----------
PINNACLE WEST
Revolving credit 2001 (h) -- 188,000
Senior notes 2003-2006 (i) 325,000 50,000
Adjustable
Floating rate notes 2003 rate (j) 250,000 --
Capitalized lease obligation 2004 7.75% 1,066 --
----------- -----------
Subtotal 576,066 238,000
----------- -----------
Total long-term debt 2,799,218 2,418,552
Less current maturities 126,140 463,469
----------- -----------
TOTAL LONG-TERM DEBT
LESS CURRENT
MATURITIES $ 2,673,078 $ 1,955,083
=========== ===========
84
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
----------
(a) This schedule does not reflect the timing of redemptions that may occur
prior to maturity.
(b) The weighted-average rate for the year ended December 31, 2001 was 2.55%
and for December 31, 2000 was 4.06%. Changes in short-term interest rates
would affect the costs associated with this debt.
(c) 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%.
(d) The weighted-average rate for the year ended December 31, 2000 was 7.33%.
Interest for 2000 was based on LIBOR plus 0.72%.
(e) APS currently has outstanding $84 million of first mortgage bonds (senior
note mortgage bonds) issued to the senior note trustee as collateral for
the senior notes. The senior note mortgage bonds have the same interest
rate, interest payment dates, maturity, and redemption provisions as the
senior notes. APS' payments of principal, premium, and/or interest on the
senior notes satisfy its corresponding payment obligations on the senior
note mortgage bonds. As long as the senior note mortgage bonds secure the
senior notes, the senior notes will effectively rank equally with the first
mortgage bonds. When APS repays all of its first mortgage bonds, other than
those that secure senior notes, the senior note mortgage bonds will no
longer secure the senior notes and will cease to be outstanding.
(f) The weighted-average rate at December 31, 2001 was 5.31% and at December
31, 2000 was 8.61%. Interest for 2001 and 2000 was based on LIBOR plus 2%
or prime plus 0.5%.
(g) Multiple notes primarily with variable interest rates based mostly on the
lenders' prime plus 1.75% and lenders' prime plus .25%.
(h) The weighted-average rate at December 31, 2000 was 7.51%. Interest for 2000
was based on LIBOR plus 0.75%.
(i) Includes two series of notes: $25 million at 6.87% due in 2003 and $300
million at 6.4% due in 2006.
(j) The weighted average rate for the year ended December 31, 2001 was 4.65%.
Interest for 2001 was based on LIBOR plus 0.98%.
The Pinnacle West and APS bank agreements have financial covenants,
including an interest coverage test and a debt ratio. We anticipate that we will
be able to meet the covenant requirement levels.
The following is a list of principal payments due on total long-term debt
and sinking fund requirements through 2006:
* $125 million in 2002;
* $318 million in 2003;
* $507 million in 2004;
* $401 million in 2005; and
* $387 million in 2006.
APS' first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. These conditions did not exist at
December 31, 2001.
85
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The parent company has issued parental guarantees and obtained surety bonds
on behalf of its unregulated subsidiaries, primarily for Pinnacle West Energy's
expansion plans and APSES' retail and energy business.
7. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLAN
Through 1999, Pinnacle West and its subsidiaries each sponsored defined
benefit pension plans for their own employees. As of January 1, 2000, these
plans were consolidated and now a single pension plan is sponsored by Pinnacle
West for the employees of Pinnacle West and its subsidiaries. A defined benefit
plan specifies the amount of benefits a plan participant is to receive using
information about the participant. The plan covers nearly all of our employees.
Our employees do not contribute to this plan. Generally, we calculate the
benefits under this plan based on age, years of service, and pay. We fund the
plan by contributing at least the minimum amount required under Internal Revenue
Service regulations but no more than the maximum tax-deductible amount. The
assets in the plan at December 31, 2001 were mostly domestic and international
common stocks and bonds and real estate.
Pension expense, including administrative costs and after consideration of
amounts capitalized or billed to electric plant participants, was:
* $7 million in 2001;
* $2 million in 2000; and
* $4 million in 1999.
The following table shows the components of net periodic pension cost
before consideration of amounts capitalized or billed to electric plant
participants (dollars in thousands):
2001 2000 1999
-------- -------- --------
Service cost - benefits earned during the period $ 26,640 $ 24,955 $ 24,982
Interest cost on projected benefit obligation 62,920 58,361 52,905
Expected return on plan assets (77,340) (77,231) (68,335)
Amortization of:
Transition asset (3,227) (3,227) (3,226)
Prior service cost 2,716 2,078 2,078
Net actuarial gain -- (1,633) --
-------- -------- --------
Net periodic pension cost $ 11,709 $ 3,303 $ 8,404
======== ======== ========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the consolidated balance sheets (dollars in
thousands):
86
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2001 2000
--------- ---------
Funded status - pension plan assets less than
projected benefit obligation $(116,213) $ (20,730)
Unrecognized net transition asset (13,554) (16,781)
Unrecognized prior service cost 24,465 18,558
Unrecognized net actuarial (gains)/losses 94,952 (23,816)
--------- ---------
Net pension liability recognized in the consolidated
balance sheets $ (10,350) $ (42,769)
========= =========
The following table sets forth the defined benefit pension plan's change in
projected benefit obligation for the plan years 2001 and 2000 (dollars in
thousands):
2001 2000
--------- ---------
Projected pension benefit obligation at
beginning of year $ 795,926 $ 742,638
Service cost 26,640 24,955
Interest cost 62,920 58,361
Benefit payments (31,647) (30,568)
Actuarial losses 18,625 540
Plan amendments 8,622 --
--------- ---------
Projected pension benefit obligation at end of year $ 881,086 $ 795,926
========= =========
The following table sets forth the defined benefit pension plan's change in
the fair value of plan assets for the plan years 2001 and 2000 (dollars in
thousands):
2001 2000
--------- ---------
Fair value of pension plan assets at beginning of year $ 775,196 $ 779,913
Actual gain/(loss) on plan assets (22,876) 1,851
Employer contributions 44,200 24,000
Benefit payments (31,647) (30,568)
--------- ---------
Fair value of pension plan assets at end of year $ 764,873 $ 775,196
========= =========
We made the assumptions below to calculate the pension liability:
2001 2000
---- ----
Discount rate 7.50% 7.75%
Rate of increase in compensation levels 4.00% 4.25%
Expected long-term rate of return on assets 10.00% 10.00%
87
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EMPLOYEE SAVINGS PLAN BENEFITS
Through 1999, Pinnacle West and its subsidiaries each sponsored defined
contribution savings plans for their own employees. As of January 1, 2000, these
plans were consolidated and now a single defined contribution savings plan is
sponsored by Pinnacle West for the employees of Pinnacle West and its
subsidiaries. In a defined contribution plan, the benefits a participant will
receive result from regular contributions they make to a participant account.
Under this plan, we make matching contributions in Pinnacle West stock to
participant accounts. At December 31, 2001 approximately 30% of total plan
assets were in Pinnacle West stock. We recorded expenses for this plan of
approximately $5 million for 2001 and $4 million for 2000 and 1999.
POSTRETIREMENT PLAN
Through 1999, Pinnacle West and its subsidiaries each sponsored
postretirement plans for their own employees. As of January 1, 2000, these plans
were consolidated and now a single postretirement plan is sponsored by Pinnacle
West for the employees of Pinnacle West and its subsidiaries. We provide medical
and life insurance benefits to retired employees. Employees must retire to
become eligible for these retirement benefits, which are based on years of
service and age. For the medical insurance plans, retirees make contributions to
cover a portion of the plan costs. For the life insurance plan, retirees do not
make contributions to cover a portion of the plan costs. 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 postretirement benefit expense after consideration of amounts
capitalized or billed to electric plant participants, was:
* $6 million for 2001;
* $3 million for 2000; and
* $7 million for 1999.
The following table shows the components of net periodic postretirement
benefit costs before consideration of amounts capitalized or billed to electric
plant participants (dollars in thousands):
2001 2000 1999
-------- -------- --------
Service cost - benefits earned during the period $ 9,438 $ 8,613 $ 8,939
Interest cost on accumulated benefit obligation 21,585 19,315 17,366
Expected return on plan assets (21,985) (22,381) (18,454)
Amortization of:
Transition obligation 7,698 7,698 7,698
Net actuarial gains (4,066) (7,983) (5,117)
-------- -------- --------
Net periodic postretirement benefit cost $ 12,670 $ 5,262 $ 10,432
======== ======== ========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the consolidated balance sheets (dollars in
thousands):
88
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2001 2000
-------- --------
Funded status - postretirement plan assets less
than projected benefit obligation $(80,544) $(14,851)
Unrecognized net obligation at transition 84,748 92,446
Unrecognized net actuarial gains (8,606) (81,280)
-------- --------
Net postretirement amount recognized in the balance
sheets $ (4,402) $ (3,685)
======== ========
The following table sets forth the postretirement benefit plan's change in
accumulated benefit obligation for the plan years 2001 and 2000 (dollars in
thousands):
2001 2000
-------- --------
Accumulated postretirement benefit obligation at
beginning of year $264,006 $231,989
Service cost 9,438 8,613
Interest cost 21,585 19,315
Benefit payments (10,194) (8,905)
Actuarial losses 33,520 12,994
-------- --------
Accumulated postretirement benefit obligation at
end of year $318,355 $264,006
======== ========
The following table sets forth the postretirement benefit plan's change in
the fair value of plan assets for the plan years 2001 and 2000 (dollars in
thousands):
2001 2000
-------- --------
Fair value of postretirement plan assets at beginning
of year $249,154 $257,538
Actual loss on plan assets (12,550) (4,436)
Employer contributions 11,400 4,958
Benefit payments (10,194) (8,906)
-------- --------
Fair value of postretirement plan assets at the
end of year $237,810 $249,154
======== ========
89
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We made the assumptions below to calculate the postretirement liability:
2001 2000
-------- --------
Discount rate 7.50% 7.75%
Expected long-term rate of return on assets - after tax 8.86% 8.77%
Initial health care cost trend rate - under age 65 7.00% 7.00%
Initial health care cost trend rate - age 65 and over 7.00% 6.00%
Ultimate health care cost trend rate 5.00% 5.00%
Year ultimate health care trend rate is reached 2006 2002
The following table shows the effect of a 1% increase or decrease in the
health care cost trend rate (dollars in millions):
1% increase 1% decrease
----------- -----------
Effect on 2001 cost of postretirement benefits
other than pensions $ 6 $ (5)
Effect on the accumulated postretirement benefit
obligation at December 31, 2001 $ 54 $ (43)
8. LEASES
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. APS accounts
for these leases as operating leases. The gain of approximately $140 million was
deferred and is being amortized to operations 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, an amount equal to
the annual lease payments is included in rent expense. A regulatory asset is
recognized for the difference between lease payments and rent expense calculated
on a straight-line basis. See Note 2 for a discussion of special purpose
entities, including the special purpose entities involved in the Palo Verde
sale-leaseback transactions.
The average amounts to be paid for the Palo Verde Unit 2 leases are
approximately $49 million per year for the years 2002-2015.
In accordance with the 1999 Settlement Agreement, APS is continuing to
accelerate amortization of the regulatory asset for leases over an eight-year
period that will end June 30, 2004 (see Note 1). All regulatory asset
amortization is included in depreciation and amortization expense in the
consolidated statements of income. The balance of this regulatory asset at
December 31, 2001 was $24 million.
In December 2000, APS purchased Units 1, 2, and 3 of West Phoenix Power
Plant, which was previously leased under a capitalized lease obligation.
In addition, we lease certain land, buildings, equipment, and miscellaneous
other items through operating rental agreements with varying terms, provisions,
and expiration dates.
90
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Total lease expense was $56 million in 2001, $58 million in 2000, and $52
million in 1999.
Estimated future minimum lease commitments, are approximately as follows
(dollars in millions):
Year
2002 $ 68
2003 66
2004 65
2005 64
2006 63
Thereafter 543
-----
Total future
commitments $ 869
=====
9. JOINTLY-OWNED FACILITIES
APS shares ownership of some of its generating and transmission facilities
with other companies. The following table shows APS' interest in those
jointly-owned facilities recorded on the consolidated balance sheets at December
31, 2001. APS' share of operating and maintaining these facilities is included
in the income statement in operations and maintenance expense. Each participant
is entitled to its share of power generated.
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% $1,822,369 $(862,880) $10,984
Palo Verde Nuclear Generating Station
Unit 2 (see Note 8) 17.0% 571,217 (278,234) 46,284
Four Corners Steam Generating Station
Units 4 and 5 15.0% 150,298 (78,983) 503
Navajo Steam Generating Station
Units 1, 2, and 3 14.0% 235,409 (104,189) 1,044
Cholla Steam Generating Station
Common Facilities (a) 62.8%(b) 74,356 (41,555) 1,093
Transmission Facilities:
ANPP 500KV System 35.8%(b) 67,911 (24,293) 405
Navajo Southern System 31.4%(b) 27,053 (16,833) 202
Palo Verde-Yuma 500KV System 23.9%(b) 9,685 (4,029) 8
Four Corners Switchyards 27.5%(b) 3,071 (1,945) --
Phoenix-Mead System 17.1%(b) 36,418 (2,766) --
Palo Verde - Estrella 500KV System 50.0%(b) -- -- 2,215
91
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
----------
(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
10. COMMITMENTS AND CONTINGENCIES
ENRON
We recorded charges totaling $21 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. This amount is
comprised of a $15 million reserve for the Company's net exposure to Enron and
its affiliates, and additional expenses of $6 million primarily related to 2002
power contracts with Enron that were canceled.
POWER SERVICE AGREEMENT
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised APS that it believes APS has overcharged Citizens by over $50 million
under a power service agreement. APS believes that its charges under the
agreement were fully in accordance with the terms of the agreement. In addition,
in testimony filed with the ACC on March 13, 2002, Citizens acknowledged that,
based on its review, "if Citizens filed a complaint with FERC, it probably would
lose the central issue in the contract interpretation dispute." APS and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, the Company and Citizens entered into a power
sale agreement under which the Company will supply Citizens with 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.
SUNCOR
On March 15, 2001, a jury returned a verdict against SunCor in the amount
of $28.6 million, $25.7 million of which represented a punitive damage award, in
a lawsuit in Maricopa County, Arizona, Superior Court entitled SunCor
Development Company v. Bergstrom Corporation, CV 98-11472. The verdict was based
on the Bergstrom Corporation's claims that it was defrauded in connection with
the acquisition of approximately ten acres of land in a SunCor commercial
development and a subsequent settlement agreement relating to those claims. On
December 14, 2001, the Court ruled that the jury award was constitutionally
excessive and reduced the punitive damage award to $5 million. Following this
ruling, SunCor settled the matter for an amount that did not have a material
impact on our 2001 results of operations.
PALO VERDE NUCLEAR GENERATING STATION
Nuclear power plant operators are required to enter into spent fuel
disposal contracts with DOE, and 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 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 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 DOE's delay, a number of utilities filed damages
actions against DOE in the Court of Federal Claims.
92
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. A
congressional decision on this issue is expected sometime during mid-summer
2002. We cannot currently predict what further steps will be taken in this area.
APS has existing fuel storage pools at Palo Verde and is in the process of
completing construction of a new facility for on-site dry storage of spent fuel.
With the existing storage pools and the addition of the new facility, APS
believes that spent fuel storage or disposal methods will be available for use
by Palo Verde to allow its continued operation through the term of the operating
license for each Palo Verde unit.
Although some low-level waste has been stored on-site in a low-level waste
facility, APS is currently shipping low-level waste to off-site facilities. APS
currently believes that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
APS currently estimates that it will incur $407 million (in 2001 dollars)
over the life of Palo Verde for its share of the costs related to the on-site
interim storage of spent nuclear fuel. As of December 31, 2001, APS had recorded
a liability and regulatory asset of $43 million for on-site interim 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 and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, APS could be
assessed retrospective premium adjustments. The maximum assessment per reactor
under the program for each nuclear incident is approximately $88 million,
subject to an annual limit of $10 million per incident. Based upon 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. APS has also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
93
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FUEL AND PURCHASED POWER COMMITMENTS
APS and Pinnacle West are parties to various fuel and purchased power
contracts with terms expiring from 2002 through 2021 that include required
purchase provisions. We estimate the contract requirements to be approximately
$270 million in 2002; $124 million in 2003; $80 million in 2004; $65 million in
2005; and $68 million in 2006. However, this amount may vary significantly
pursuant to certain provisions in such contracts that permit us to decrease
required purchases under certain circumstances.
COAL MINE RECLAMATION OBLIGATIONS
APS must reimburse certain coal providers for amounts incurred for coal
mine reclamation. APS estimates its share of the total obligation to be about
$103 million. The portion of the coal mine reclamation obligation related to
coal already burned is about $59 million at December 31, 2001 and is included in
deferred credits-other in the consolidated balance sheets.
A regulatory asset has been established for amounts not yet recovered from
ratepayers related to the coal obligations. In accordance with the 1999
Settlement Agreement with the ACC, APS is continuing to accelerate the
amortization of the regulatory asset for coal mine reclamation over an
eight-year period that will end June 30, 2004. Amortization is included in
depreciation and amortization expense on the statements of income.
CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST
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.
We are closely monitoring developments in the California energy market and
the potential impact of these developments on us and our subsidiaries. We have
evaluated, among other things, SCE's role as a Palo Verde and Four Corners
participant; APS' transactions with the PX and the ISO; contractual
relationships with SCE and PG&E; APSES' retail transactions involving SCE and
PG&E; and marketing and trading exposures. Based on our evaluations, we have
reserved $10 million before income taxes for our credit exposure related to the
California energy situation, $5 million of which was recorded in the fourth
quarter of 2000 and $5 million of which was recorded in first quarter of 2001.
We cannot predict with certainty, however, the impact that any future resolution
or attempted resolution, of the California energy market situation may have on
us or our subsidiaries or the regional energy market in general.
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 California ISO and PX provide necessary historical data. The FERC
also ordered an evidentiary proceeding to discuss and evaluate possible refunds
for the Pacific Northwest. The ALJ at the FERC in charge of that evidentiary
proceeding made an initial finding that no refunds were appropriate. The Pacific
Northwest issues will now be addressed by the FERC Commissioners. Although the
FERC has not yet made a final ruling in the Pacific Northwest matter or
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.
94
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
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." The complaint indicates that Pinnacle West sold
approximately $106 million of power to the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
amount above "just and reasonable levels." We believe that the claims as they
relate to Pinnacle West are without merit.
CONSTRUCTION PROGRAM
Consolidated capital expenditures in 2002 are estimated to be (dollars in
millions):
APS $ 498
Pinnacle West Energy 411
SunCor 79
Other (primarily APSES and
Pinnacle West) 35
-------
Total $ 1,023
=======
GENERATION EXPANSION
Pinnacle West Energy has completed or announced plans to build about 3,420
MW of natural gas-fired generating capacity from 2000 through 2007 at an
estimated cost of about $1.9 billion. This does not reflect an expected
reimbursement in 2004 by SNWA of $100 million of Pinnacle West Energy's
cumulative capital expenditures in the Silverhawk project in exchange for SNWA's
purchase of a 25% interest in the project. Our expansion plan will be sized to
meet native load growth, cash flow and market conditions. Pinnacle West Energy
is currently funding its capital requirements through capital infusions from
Pinnacle West, which finances those infusions through debt financings and
internally-generated cash. As Pinnacle West Energy develops and obtains
additional generation assets, including APS' existing generation assets,
Pinnacle West Energy expects to fund its capital requirements through
internally-generated cash and its own debt issuances.
Pinnacle West Energy has completed or is currently planning the following
projects:
* A 650 MW expansion of the West Phoenix Power Plant in Phoenix. The 120
MW West Phoenix Unit 4 began commercial operation on June 1, 2001.
Construction has begun on the 530 MW West Phoenix Unit 5, with
commercial operation expected to begin in mid-2003.
* The construction of a four-unit combined cycle 2,120 MW generating
station near Palo Verde, called Redhawk. Construction of Units 1 and 2
began in December 2000, and commercial operation is currently
scheduled for the summer of 2002. Although Pinnacle West Energy
currently plans to bring Units 3 and 4 on line in or before the first
95
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
quarter of 2007, equipment procurement, engineering and construction
plans will allow for these units to come on line as early as 2005 if
warranted by market conditions.
* The construction of an 80 MW simple-cycle power plant at Saguaro in
Southern Arizona. Commercial operation is currently scheduled for the
summer of 2002.
* Development of an electric generating station 20 miles north of Las
Vegas, Nevada. Construction of the 570 MW Silverhawk combined-cycle
plant is expected to begin in the spring of 2002, with an expected
commercial operation date of mid-2004. Pinnacle West Energy has signed
a 25% participation agreement with Las Vegas-based SNWA.
* A Pinnacle West Energy affiliate is exploring the possibility of
creating an underground natural gas storage facility on Company-owned
land west of Phoenix. A feasibility study is in progress to determine
if the proposed acreage can support a natural gas storage cavern.
LITIGATION
We are party to various claims, legal actions, and complaints arising in
the ordinary course of business. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial
statements or liquidity.
11. NUCLEAR DECOMMISSIONING COSTS
APS recorded $11 million for nuclear decommissioning expense in each of the
years 2001, 2000, and 1999. APS estimates it will cost about $1.8 billion ($506
million in 2001 dollars) to decommission its share of the three Palo Verde
units. The majority of decommissioning costs are expected to be incurred over a
14-year period beginning in 2024. APS charges decommissioning costs to expense
over each unit's operating license term and includes them in the accumulated
depreciation balance until each unit is retired. Nuclear decommissioning costs
are recovered in rates.
APS' current estimates are based on a 2001 site-specific study for Palo
Verde that assumes the prompt removal/dismantlement method of decommissioning.
An independent consultant prepared this study. APS is required to update the
study every three years.
To fund the costs APS expects to incur to decommission the plant, APS
established external decommissioning trusts in accordance with NRC regulations.
APS invests the trust funds primarily in fixed income securities and domestic
stock and classifies them as available for sale. Realized and unrealized gains
and losses are reflected in accumulated depreciation in accordance with industry
practice. The following table shows the cost and fair value of our nuclear
decommissioning trust fund assets which are reported in investments and other
assets on the consolidated balance sheets at December 31, 2001 and 2000 (dollars
in millions):
96
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2001 2000
------ ------
Trust fund assets - at cost
Fixed income securities $ 103 $ 94
Domestic stock 61 52
------ ------
Total $ 164 $ 146
====== ======
Trust fund assets - fair value
Fixed income securities $ 106 $ 97
Domestic stock 96 100
------ ------
Total $ 202 $ 197
====== ======
See Note 2 for information on a new accounting standard on accounting
for certain liabilities related to closure or removal of long-lived assets.
97
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Consolidated quarterly financial information for 2001 and 2000 is as
follows:
(dollars in thousands, except per share amounts)
2001
-----------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Operating revenues (a)
Electric $ 906,494 $1,261,358 $1,531,005 $ 683,608
Real estate 32,335 32,454 43,024 61,095
Operating income $ 136,063 $ 138,888 $ 298,606 $ 101,070
Income from continuing
operations $ 62,205 $ 66,857 $ 162,499 $ 35,806
Cumulative effect of change in
accounting - net of income tax (2,755) -- (12,446) --
---------- ---------- ---------- ----------
Net income $ 59,450 $ 66,857 $ 150,053 $ 35,806
========== ========== ========== ==========
Earnings (loss) per weighted
average common share
outstanding - basic
Continuing operations - basic $ 0.73 $ 0.79 $ 1.92 $ 0.42
Cumulative effect of change
in accounting - basic (0.03) -- (0.15) --
---------- ---------- ---------- ----------
Earnings per weighted average
common share outstanding-
basic $ 0.70 $ 0.79 $ 1.77 $ 0.42
========== ========== ========== ==========
Continuing operations - diluted $ 0.73 $ 0.79 $ 1.91 $ 0.42
Cumulative effect of change
in accounting - diluted (0.03) -- (0.14) --
---------- ---------- ---------- ----------
Earnings per weighted average
common share outstanding -
diluted $ 0.70 $ 0.79 $ 1.77 $ 0.42
========== ========== ========== ==========
Dividends declared per share $ 0.375 $ 0.375 $ 0.375 $ 0.40
98
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share amounts)
2000
------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
--------- --------- ---------- ---------
Operating revenues (a)
Electric $ 446,228 $ 720,174 $1,567,960 $ 797,448
Real estate 41,889 36,374 39,396 40,706
Operating income $ 91,565 $ 190,942 $ 241,264 $ 117,976
Net income $ 54,070 $ 89,901 $ 116,049 $ 42,312
Earnings per weighted average
common share outstanding
Net income - basic $ 0.64 $ 1.06 $ 1.37 $ 0.50
Net income - diluted $ 0.64 $ 1.06 $ 1.37 $ 0.50
Dividends declared per share $ 0.35 $ 0.35 $ 0.35 $ 0.375
----------
(a) Electric revenues are seasonal in nature, with the peak sales periods
generally occurring during the summer months. Comparisons among quarters of
a year may not represent overall trends and changes in operations.
99
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2001 and
2000 due to their short maturities.
We hold investments in debt and equity securities for purposes other than
trading. The December 31, 2001 and 2000 fair values of such investments, which
we determine by using quoted market values, approximate their carrying amount.
On December 31, 2001, the carrying value of our long-term debt (excluding a
capitalized lease obligation) was $2.80 billion, with an estimated fair value of
$2.82 billion. The carrying value of our long-term debt (excluding a capitalized
lease obligation) was $2.42 billion on December 31, 2000, with an estimated fair
value of $2.48 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.
14. EARNINGS PER SHARE
The following table presents earnings per weighted average common share
outstanding (EPS):
2001 2000 1999
------- ------- -------
Basic EPS:
Continuing operations $ 3.86 $ 3.57 $ 3.18
Discontinued operations -- -- 0.45
Extraordinary charge -- -- (1.65)
Cumulative effect of change in
accounting (0.18) -- --
------- ------- -------
Earnings per share-basic $ 3.68 $ 3.57 $ 1.98
======= ======= =======
Diluted EPS:
Continuing operations $ 3.85 $ 3.56 $ 3.17
Discontinued operations -- -- 0.45
Extraordinary charge -- -- (1.65)
Cumulative effect of change in
accounting (0.17) -- --
------- ------- -------
Earnings per share-diluted $ 3.68 $ 3.56 $ 1.97
======= ======= =======
Dilutive stock options increased average common shares outstanding by
212,491 shares in 2001, 202,738 shares in 2000, and 291,392 shares in 1999.
Total average common shares outstanding for the purposes of calculating diluted
earnings per share were 84,930,140 shares in 2001, 84,935,282 shares in 2000,
and 85,008,527 shares in 1999.
Options to purchase 212,562 shares of common stock were outstanding at
December 31, 2001 but were not included in the computation of diluted EPS
because the options' exercise price was greater than the average market price of
the common shares. Options to purchase shares of common stock that were not
included in the computation of diluted EPS were 517,614 at December 31, 2000 and
506,734 at December 31, 1999.
100
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. STOCK-BASED COMPENSATION
Pinnacle West offers two stock incentive plans for officers and key
employees of our company and our subsidiaries.
One of the plans (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 other plan (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 plan also provides for the
granting of any combination of shares of restricted stock, stock appreciation
rights or dividend equivalents.
The awards outstanding under the incentive plans at December 31, 2001 are
1,832,725 non-qualified stock options, 237,833 shares of restricted stock, and
no incentive stock options, stock appreciation rights or dividend equivalents.
SFAS No. 123, "Accounting for Stock-Based Compensation" encourages, but
does not require, that a company record compensation expense based on the fair
value of options granted (the fair value method). We continue to recognize
expense based on Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees."
If we had recorded compensation expense based on the fair value method, our
net income and earnings per share would have been reduced to the following pro
forma amounts (dollars in thousands):
2001 2000 1999
--------- --------- ---------
Net income
As reported $ 312,166 $ 302,332 $ 167,887
Pro forma (fair value method) $ 309,800 $ 301,102 $ 166,913
Earnings per share - basic
As reported $ 3.68 $ 3.57 $ 1.98
Pro forma (fair value method) $ 3.66 $ 3.55 $ 1.97
In order to present 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:
101
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2001 2000 1999
--------- --------- ---------
Risk-free interest rate 4.08% 5.81% 5.68%
Dividend yield 3.70% 3.48% 3.33%
Volatility 27.66% 32.00% 20.50%
Expected life (months) 60 60 60
The following table is a summary of the status of our stock option plans as
of December 31, 2001, 2000, and 1999 and changes during the years ending on
those dates:
2001 2000 1999
Weighted Weighted Weighted
Average Average Average
2001 Exercise 2000 Exercise 1999 Exercise
Shares Price Shares Price Shares Price
--------- ------ --------- ------ --------- ------
Outstanding at
beginning of year 1,569,171 $37.55 1,441,124 $33.45 1,563,512 $27.95
Granted 444,200 42.55 451,450 43.28 458,450 35.95
Exercised (162,229) 28.53 (283,819) 20.90 (516,838) 18.19
Forfeited (18,417) 41.67 (39,584) 39.86 (64,000) 40.36
--------- --------- ---------
Outstanding at end
of year 1,832,725 39.52 1,569,171 37.55 1,441,124 33.45
--------- --------- ---------
Options exercisable
at year-end 926,315 37.41 831,537 34.37 835,381 29.69
--------- --------- ---------
Weighted average
fair value of
options granted
during the year 8.84 11.81 7.05
The following table summarizes information about our stock option plans at
December 31, 2001:
Weighted
Average Weighted
Weighted Remaining Average
Exercise Options Average Contract Options Exercise
Prices Per Share Outstanding Exercise Price Life (Years) Exercisable Price
---------------- ----------- -------------- ------------ ----------- --------
$14.03-18.71 15,150 $18.09 0.5 15,150 $18.09
18.71-23.39 88,284 20.53 2.3 88,284 20.53
23.39-28.07 78,167 27.39 4.6 64,834 27.44
28.07-32.75 72,250 31.44 4.8 72,250 31.44
32.75-37.42 285,024 34.69 7.7 165,245 34.69
37.42-42.10 217,500 40.15 6.1 175,500 39.95
42.10-46.78 1,076,350 43.96 8.8 345,052 45.70
---------- --------
1,832,725 926,315
========== ========
102
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and regulatory environment) which consist of regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
currently includes activities related to electricity transmission and
distribution, as well as electricity generation. Our marketing and trading
business segment currently includes activities related to wholesale marketing
and trading and APSES' competitive energy services.
These reportable segments reflect a change in the reporting of our segment
information. Before the fourth quarter of 2001, we had two segments (generation
and delivery). The "generation segment" information combined our marketing and
trading activities with our generation of electricity activities. The "delivery
segment" included transmission and distribution activities.
In the fourth quarter of 2001, APS filed with the ACC a proposed rule
variance and purchase power agreement with the ACC (see Note 3) that inherently
views our business in the new reportable segments described above. Internal
management reporting has been changed to reflect this alignment. The
corresponding information for earlier periods has been restated. The other
amounts include activity relating to the parent company and other subsidiaries
including SunCor and El Dorado. Financial data for the business segments is
provided as follows (dollars in millions):
Business Segments for the Year Ended December 31, 2001
------------------------------------------------------
Marketing
and
Retail Trading Other Total
------- ------- ------- -------
Operating revenues $ 2,562 $ 1,820 $ 169 $ 4,551
Purchased power and fuel costs 1,161 1,503 -- 2,664
Other operating expenses 602 32 156 790
------- ------- ------- -------
Operating margin 799 285 13 1,097
Depreciation and amortization 423 1 4 428
Interest and other expenses 124 -- 4 128
------- ------- ------- -------
Pretax margin 252 284 5 541
Income taxes 100 112 2 214
------- ------- ------- -------
Income from continuing operations 152 172 3 327
Cumulative effect of change in
accounting for derivatives - net of
income taxes of $10 (15) -- -- (15)
------- ------- ------- -------
Net income $ 137 $ 172 $ 3 $ 312
======= ======= ======= =======
Total assets $ 6,938 $ 556 $ 488 $ 7,982
======= ======= ======= =======
Capital expenditures $ 1,004 $ 23 $ 102 $ 1,129
======= ======= ======= =======
103
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Business Segments for the Year Ended December 31, 2000
------------------------------------------------------
Marketing
and
Retail Trading Other Total
------- ------- ------- -------
Operating revenues $ 2,539 $ 993 $ 158 $ 3,690
Purchased power and fuel costs 1,066 867 -- 1,933
Other operating expenses 538 21 126 685
------- ------- ------- -------
Operating margin 935 105 32 1,072
Depreciation and amortization 425 1 5 431
Interest and other expenses 141 -- 4 145
------- ------- ------- -------
Pretax margin 369 104 23 496
Income taxes 144 41 9 194
------- ------- ------- -------
Net income $ 225 $ 63 $ 14 $ 302
======= ======= ======= =======
Total assets $ 6,326 $ 386 $ 451 $ 7,163
======= ======= ======= =======
Capital expenditures $ 665 $ -- $ 50 $ 715
======= ======= ======= =======
Business Segments for the Year Ended December 31, 1999
------------------------------------------------------
Marketing
and
Retail Trading Other Total
------- ------- ------- -------
Operating revenues $ 1,916 $ 377 $ 130 $ 2,423
Purchased power and fuel costs 433 360 -- 793
Other operating expenses 549 9 95 653
------- ------- ------- -------
Operating margin 934 8 35 977
Depreciation and amortization 417 -- 3 420
Interest and other expenses 142 -- 3 145
------- ------- ------- -------
Pretax margin 375 8 29 412
Income taxes 129 3 10 142
------- ------- ------- -------
Income from continuing operations 246 5 19 270
Income tax benefit from
discontinued operations 38 -- -- 38
Extraordinary charge - net of
income taxes of $94 (140) -- -- (140)
------- ------- ------- -------
Net income $ 144 $ 5 $ 19 $ 168
======= ======= ======= =======
Capital expenditures $ 353 $ -- $ 126 $ 479
======= ======= ======= =======
104
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. DERIVATIVE INSTRUMENTS
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We employ established procedures to 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 commodity. In addition, subject
to specified risk parameters established by the Board of Directors and monitored
by the Energy Risk Management Committee, we engage in trading activities
intended to profit from market price movements.
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including one counterparty for which a worst case exposure
represents approximately 50% of our $267 million of risk management and trading
assets as of December 31, 2001. We use a risk management process to assess and
monitor the financial exposure of this and all other counterparties. Despite the
fact that the great majority of trading counterparties are rated as investment
grade by the credit rating agencies, including the counterparty noted above,
there is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated earnings for a given period.
Counterparties in the portfolio consist principally of major energy companies,
municipalities, and local distribution companies. We maintain credit policies
that we believe minimize overall credit risk to within acceptable limits.
Determination of the credit quality of our counterparties is based upon a number
of factors, including credit ratings and our evaluation of their financial
condition. In many contracts, we employ collateral requirements and standardized
agreements that allow for the netting of positive and negative exposures
associated with a single counterparty. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties. See Note 1 for a discussion of our credit reserve policy.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. Hedge effectiveness is measured based on the relative changes in fair
value between the derivative contract and the hedged item over time. Any change
in the fair value resulting from ineffectiveness is recognized immediately in
net income. This new standard may result in additional volatility in our net
income and comprehensive income.
As a result of adopting SFAS No. 133, we recognized $118 million of
derivative assets and $16 million of derivative liabilities in our consolidated
balance sheets as of January 1, 2001. Also as of January 1, 2001, we recorded a
$3 million after-tax loss in net income and a $64 million after-tax gain in
equity (as a component of other comprehensive income), both as a cumulative
effect of a change in accounting principle. The gain resulted from unrealized
gains on cash flow hedges.
105
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In June 2001, the FASB issued new guidance related to electricity
contracts. The effective date of this new guidance was July 1, 2001. As of July
1, 2001, we recorded an additional $12 million after-tax loss in net income and
an additional $8 million after-tax gain in equity (as a component of other
comprehensive income), as a result of adopting the new guidance related to
electricity contracts. The loss resulted primarily from electricity options
contracts. The gain resulted from unrealized gains on cash flow hedges. The
impact of the new guidance is reflected in net income and other comprehensive
income as a cumulative effect of change in accounting principle.
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 is April 1, 2002. We are currently
evaluating the new guidance to determine what impact, if any, it will have on
our financial statements.
The change in derivative fair value included in the consolidated statements
of income for the year ending December 31, 2001 is comprised of the following
(dollars in thousands):
December 31,
2001
------------
Ineffective portion of derivatives
qualifying for hedge accounting (a) $ (8,371)
Discontinuance of cash flow hedges for
forecasted transactions that will not
occur (9,525)
Reclassification of mark-to-market losses
to realized 25,948
--------
Total $ 8,052
========
----------
(a) Time value component of options excluded from assessment of hedge
effectiveness.
As of December 31, 2001, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted
transactions is thirty-six months. During the twelve months ended December 31,
2002, we estimate that a net loss of $23 million before income taxes will be
reclassified from accumulated other comprehensive loss as an offset to the
effect on earnings of market price changes for the related hedged transaction.
The following table summarizes our assets and liabilities from risk
management and trading activities related to trading and system (retail and
traditional wholesale activities) as of December 31, 2001 and 2000 (dollars in
thousands):
106
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001
Current Current Other Net
Assets Investments Liabilities Liabilities Asset/(Liability)
--------- ----------- ----------- ----------- -----------------
Mark-to-
market:
Trading $ 56,876 $ 148,457 $ (14,154) $ (53,253) $ 137,926
System 10,097 -- (21,840) (95,159) (106,902)
Trading - at
cost -- 51,894 -- (59,164) (7,270)
--------- --------- --------- --------- ---------
Total $ 66,973 $ 200,351 $ (35,994) $(207,576) $ 23,754
========= ========= ========= ========= =========
December 31, 2000
Current Current Other Net
Assets Investments Liabilities Liabilities Asset/(Liability)
--------- ----------- ----------- ----------- -----------------
Trading - mark-
to-market $ 17,506 $ 32,955 $ (37,179) $ (877) $ 12,405
Trading - at
cost -- -- -- (13,834) (13,834)
--------- --------- --------- --------- ---------
Total $ 17,506 $ 32,955 $ (37,179) $ (14,711) $ (1,429)
========= ========= ========= ========= =========
Net gains and losses on instruments utilized for trading activities are
recognized in marketing and trading revenues on a current basis (the
mark-to-market method). Trading positions are measured at fair value as of the
balance sheet date. The unrealized trading gains recognized in marketing and
trading revenues were $127 million for the year ended December 31, 2001 and $14
million for the year ended December 31, 2000.
18. SUBSEQUENT EVENTS
On February 8, 2002, Pinnacle West issued $215 million of 4.5% Notes due
2004. On March 1, 2002, APS issued $375 million of 6.50% Notes due 2012. On
March 15, 2002, APS announced the redemption on April 15, 2002 of approximately
$125 million of its First Mortgage Bonds, 8.75% Series due 2024.
On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
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." The complaint indicates that Pinnacle West sold
approximately $106 million of power to California Department of Water Resources
from January 17, 2001 to October 31, 2001 and does not allege any amount above
"just and reasonable levels." We believe that the claims as they relate to
Pinnacle West are without merit.
See Note 3 for information relating to the March 22, 2002 ACC Staff report
addressing issues in the generic docket.
107
PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Additions
----------------------
Balance at Charged to Charged Balance
beginning cost and to other at end of
Description of period expenses accounts Deductions Period
----------- ------- ------- ------- ------- -------
(dollars in thousands)
YEAR ENDED DECEMBER 31, 2001
Real Estate Valuation Reserves $ 2,000 $ -- $ -- $ --(a) $ 2,000
YEAR ENDED DECEMBER 31, 2000
Real Estate Valuation Reserves $ 8,000 $ -- $ -- $ 6,000(a) $ 2,000
YEAR ENDED DECEMBER 31, 1999
Real Estate Valuation Reserves $15,000 $ -- $ -- $ 7,000(a) $ 8,000
YEAR ENDED DECEMBER 31, 2001
Reserve for uncollectibles $ 2,580 $ 7,609 $ -- $ 6,640 $ 3,549
YEAR ENDED DECEMBER 31, 2000
Reserve for uncollectibles $ 1,538 $ 5,638 $ -- $ 4,596 $ 2,580
YEAR ENDED DECEMBER 31, 1999
Reserve for uncollectibles $ 1,725 $ 4,778 $ -- $ 4,965 $ 1,538
----------
(a) Represents pro-rata allocations for sale of land.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
108
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" and to "Other Matters -
Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's Proxy
Statement relating to the Annual Meeting of Shareholders to be held on May 22,
2002 (the 2002 Proxy Statement) and to the Supplemental Item --- "Executive
Officers of the Registrant" in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to "Director Compensation," "Human Resources Committee
Report on Executive Compensation," "Stock Performance Comparisons," "Executive
Compensation," "Option Grants, Exercises, and Holdings," and "Executive Benefit
Plans" in the 2002 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Reference is hereby made to "Security Ownership of Certain Beneficial
Owners and Management" in the 2002 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to "Executive Benefit Plans - Employment and
Severance Arrangements" and "Other Matters -Business Relationships" in the 2002
Proxy Statement.
109
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements
See the Index to Consolidated Financial Statements and Financial Statement
Schedule in Part II, Item 8.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION
----------- -----------
10.1(a) -- 2002 Management Variable Incentive Plan
10.2(a) -- 2002 Senior Management Variable Incentive Plan
10.3(a) -- 2002 Officer Variable Incentive Plan
10.4(a) -- First Amendment to the Pinnacle West Capital Corporation
Supplemental Excess Benefit Retirement Plan
10.5(a) -- Second Amendment to the Pinnacle West Capital Corporation
Supplemental Excess Benefit Retirement Plan
12.1 -- Ratio of Earnings to Fixed Charges
21.1 -- Subsidiaries of the Company
23.1 -- Consent of Deloitte & Touche LLP
110
In addition to those Exhibits shown above, the Company hereby incorporates
the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation
ss.229.10(d) by reference to the filings set forth below:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
3.1 Articles of Incorporation, 19.1 to the Company's September 1-8962 11-14-88
restated as of July 29, 1988 1988 Form 10-Q Report
3.2 Bylaws, amended as of 4.1 to the Company's Registration 1-8962 1-20-00
December 15, 1999 Statement on Form S-8 No.
333-95035
4.1 Mortgage and Deed of Trust 4.1 to APS' September 1992 Form 1-4473 11-9-92
Relating to APS' First 10-Q Report
Mortgage Bonds, together with
forty-eight indentures
supplemental thereto
4.2 Forty-ninth Supplemental 4.1 to APS' 1992 Form 10-K Report 1-4473 3-30-93
Indenture
4.3 Fiftieth Supplemental 4.2 to APS' 1993 Form 10-K Report 1-4473 3-30-94
Indenture
4.4 Fifty-first Supplemental 4.1 to APS' August 1, 1993 Form 1-4473 9-27-93
Indenture 8-K Report
4.5 Fifty-second Supplemental 4.1 to APS' September 30, 1993 1-4473 11-15-93
Indenture Form 10-Q Report
4.6 Fifty-third Supplemental 4.5 to APS' Registration 1-4473 3-1-94
Indenture Statement No. 33-61228 by means
of February 23, 1994 Form 8-K
Report
4.7 Fifty-fourth Supplemental 4.1 to APS' Registration 1-4473 11-22-96
Indenture Statements Nos. 33-61228,
33-55473, 33-64455 and 333-15379
by means of November 19, 1996
Form 8-K Report
111
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
4.8 Fifty-fifth Supplemental 4.8 to APS' Registration 1-4473 4-9-97
Indenture Statement Nos. 33-55473, 33-64455
and 333-15379 by means of April
7, 1997 Form 8-K Report
4.9 Agreement, dated March 21, 4.1 to APS' 1993 Form 10-K Report 1-4473 3-30-94
1994, relating to the filing
of instruments defining the
rights of holders of APS
long-term debt not in excess
of 10% of APS' total assets
4.10 Indenture dated as of January 4.6 to APS' Registration 1-4473 1-11-95
1, 1995 among APS and The Statement Nos. 33-61228 and
Bank of New York, as Trustee 33-55473 by means of January 1,
1995 Form 8-K Report
4.11 First Supplemental Indenture 4.4 to APS' Registration 1-4473 1-11-95
dated as of January 1, 1995 Statement Nos. 33-61228 and
33-55473 by means of January 1,
1995 Form 8-K Report
4.12 Indenture dated as of 4.5 to APS' Registration 1-4473 11-22-96
November 15, 1996 among APS Statements Nos. 33-61228,
and The Bank of New York, as 33-55473, 33-64455 and 333- 15379
Trustee by means of November 19, 1996
Form 8-K Report
4.13 First Supplemental Indenture 4.6 to APS' Registration 1-4473 11-22-96
Statements Nos. 33-61228,
33-55473, 33-64455 and 333-15379
by means of November 19, 1996
Form 8-K Report
4.14 Second Supplemental Indenture 4.10 to APS' Registration 1-4473 4-9-97
Statement Nos. 33-55473, 33-64455
and 333-15379 by means of April
7, 1997 Form 8-K Report
112
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
4.15 Indenture dated as of 4.1 to the Company's Registration 1-8962 1-25-01
December 1, 2000 between the Statement No. 333-53150
Company and The Bank of New
York, as Trustee, relating to
Senior Debt Securities
4.16 First Supplemental Indenture 4.2 to the Company's Registration 1-8962 3-26-01
dated as of March 15, 2001 Statement No. 333-52476
4.17 Indenture dated as of 4.2 to the Company's Registration 1-8962 1-25-01
December 1, 2000 between the Statement No. 333-53150
Company and The Bank of New
York, as Trustee, relating to
subordinated Debt Securities
4.18 Specimen Certificate of 4.2 to the Company's 1988 Form 1-8962 3-31-89
Pinnacle West Capital 10-K Report
Corporation Common Stock, no
par value
4.19 Agreement, dated March 29, 4.1 to the Company's 1987 Form 1-8962 3-30-88
1988, relating to the filing 10-K Report
of instruments defining the
rights of holders of
long-term debt not in excess
of 10% of the Company's
total assets
4.20 Indenture dated as of January 4.10 to APS' Registration The 1-4473 1-16-98
15, 1998 among APS and Chase Statement Nos. 333-15379 and
Manhattan Bank, as Trustee 333-27551 by means of January 13,
1998 Form 8-K Report
4.21 First Supplemental Indenture 4.3 to APS' Registration 1-4473 1-16-98
dated as of January 15, 1998 Statement Nos. 333-15379 and
333-27551 by means of January 13,
1998 Form 8-K Report
113
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
4.22 Second Supplemental Indenture 4.3 to APS' Registration 1-4473 2-22-99
dated as of February 15, 1999 Statement Nos. 333-27551 and
333-58445 by means of February
18, 1999 Form 8-K Report
4.23 Third Supplemental Indenture 4.5 to APS' 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
4.24 Fourth Supplemental Indenture 4.1 to Registration Statement 1-4473 8-4-00
dated as of August 1, 2000 Nos. 333-58445 and 333-94277
by means of August 2, 2000
Form 8-K Report
4.25 Fifth Supplemental Indenture 4.1 to APS' September 2001 Form 1-4473 11-6-01
dated as of October 1, 2001 10-Q
4.26 Sixth Supplemental Indenture 4.1 to APS' Registration 1-4473 2-28-01
dated as of March 1, 2002 Statement Nos. 333-63994 and
333-83398 by means of February
26, 2002 Form 8-K Report
4.27 Amended and Restated Rights 4.1 to the Company's March 22, 1-8962 4-19-99
Agreement, dated as of March 1999 Form 8-K Report
26, 1999, between Pinnacle
West Capital Corporation and
BankBoston, N.A., as Rights
Agent, including (i) as
Exhibit A thereto the form
of Amended Certificate of
Designation of Series A
Participating Preferred Stock
of Pinnacle West Capital
Corporation, (ii) as Exhibit B
thereto the form of Rights
Certificate and (iii) as
Exhibit C thereto the Summary
of Right to Purchase
Preferred Shares
114
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.6 Two separate Decommissioning 10.2 to APS' September 1991 Form 1-4473 11-14-91
Trust Agreements (relating 10-Q Report
to PVNGS Units 1 and 3,
respectively), each dated
July 1, 1991, between APS and
Mellon Bank, N.A., as
Decommissioning Trustee
10.7 Amendment No. 1 to 10.1 to APS' 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 1),
dated as of December 1, 1994
10.8 Amendment No. 1 to 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 3),
dated as of December 1, 1994
10.9 Amendment No. 2 to APS 10.4 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 1)
dated as of July 1, 1991
10.10 Amendment No. 2 to APS 10.6 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 3)
dated as of July 1, 1991
115
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.11 Amended and Restated 10.1 to the Company's 1991 Form 1-8962 3-26-92
Decommissioning Trust 10-K Report
Agreement (PVNGS Unit 2)
dated as of January 31, 1992,
among APS, Mellon Bank, N.A.,
as Decommissioning Trustee,
and State Street Bank and
Trust Company, as successor
to The First National Bank of
Boston, as Owner Trustee under
two separate Trust Agreements,
each with a separate Equity
Participant, and as Lessor
under two separate Facility
Leases, each relating to an
undivided interest in PVNGS
Unit 2
10.12 First Amendment to Amended 10.2 to APS' 1992 Form 10-K 1-4473 3-30-93
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2), dated as of November 1,
1992
10.13 Amendment No. 2 to Amended 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2), dated as of November 1,
1994
10.14 Amendment No. 3 to Amended 10.1 to APS' June 1996 Form 10-Q 1-4473 8-9-96
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2), dated as of November 1,
1994
116
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.15 Amendment No. 4 to Amended APS 10.5 to APS' 1996 Form 10-K 1-4473 3-28-97
and Restated Decommissioning Report
Trust Agreement (PVNGS Unit
2) dated as of January 31,
1992
10.16 Asset Purchase and Power 10.1 to APS' June 1991 Form 10-Q 1-4473 8-8-91
Exchange Agreement dated Report
September 21, 1990 between
APS and PacifiCorp, as
amended as of October 11,
1990 and as of July 18, 1991
10.17 Long-Term Power Transaction 10.2 to APS' June 1991 Form 10-Q 1-4473 8-8-91
Agreement dated September 21, Report
1990 between APS and
PacifiCorp, as amended as of
October 11, 1990, and as of
July 8, 1991
10.18 Amendment No. 1 dated April 10.3 to APS' 1995 Form 10-K 1-4473 3-29-96
5, 1995 to the Long-Term Report
Power Transaction Agreement
and Asset Purchase and Power
Exchange Agreement between
PacifiCorp and APS
10.19 Restated Transmission 10.4 to APS' 1995 Form 10-K 1-4473 3-29-96
Agreement between PacifiCorp Report
and APS dated April 5, 1995
117
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.20 Contract among PacifiCorp, 10.5 to APS' 1995 Form 10-K 1-4473 3-29-96
APS and United States Report
Department of Energy Western
Area Power Administration,
Salt Lake Area Integrated
Projects for Firm
Transmission Service dated
May 5, 1995
10.21 Reciprocal Transmission 10.6 to APS' 1995 Form 10-K 1-4473 3-29-96
Service Agreement between APS Report
and PacifiCorp dated as of
March 2, 1994
10.22 Contract, dated July 21, 10.31 to the Company's Form S-14 2-96386 3-13-85
1984, with DOE providing for Registration Statement
the disposal of nuclear fuel
and/or high -level
radioactive waste, ANPP
10.23 Indenture of Lease with 5.01 to APS' Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Four Registration Statement
Corners Plant
10.24 Supplemental and Additional 5.02 to APS' Form S-7 2-59644 9-1-77
Indenture of Lease, including Registration Statement
amendments and supplements
to original lease with
Navajo Tribe of Indians,
Four Corners Plant
10.25 Amendment and Supplement No. 10.36 to the Company's 1-8962 7-25-85
1 to Supplemental and Registration Statement on Form
Additional Indenture of Lease 8-B Report
Four Corners, dated April
25, 1985
118
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.26 Application and Grant of 5.04 to APS' Form S-7 2-59644 9-1-77
multi-party rights-of-way and Registration Statement
easements, Four Corners Plant
Site
10.27 Application and Amendment No. 10.37 to the Company's 1-8962 7-25-85
1 to Grant of multi-party Registration Statement on Form
rights-of-way and easements, 8-B
Four Corners Power Plant
Site dated April 25, 1985
10.28 Application and Grant of 5.05 to APS' Form S-7 2-59644 9-1-77
Arizona Public Service Registration Statement
Company rights- of-way and
easements, Four Corners Plant
Site
10.29 Four Corners Project 10.7 to the Company's 2000 Form 1-8962 3-14-01
Co-Tenancy Agreement 10-K Report
Amendment No. 6
10.30 Application and Amendment No. 10.38 to the Company's 1-8962 7-25-85
1 to Grant of Arizona Public Registration Statement on Form
Service Company 8-B
rights-of-way and easements,
Four Corners Power Plant
Site dated April 25, 1985
10.31 Indenture of Lease, Navajo 5(g) to APS' Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.32 Application of Grant of 5(h) to APS Form S-7 Registration 2-36505 3-23-70
rights-of-way and easements, Statement
Navajo Plant
10.33 Water Service Contract 5(l) to APS' Form S-7 2-394442 3-16-71
Assignment with the United Registration Statement
States Department of
Interior, Bureau of
Reclamation, Navajo Plant
119
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.34 Arizona Nuclear Power 10. 1 to APS' 1988 Form 10-K 1-4473 3-8-89
Project Participation
Agreement, dated August 23,
1973, among APS Salt River
Project Agricultural
Improvement and Power
District, Southern
California Edison
Company, Public Service
Company of New Mexico,
El Paso Electric Company,
Southern California Public
Power Authority, and
Department of Water and
Power of the City of Los
Angeles, and amendments
1-12 thereto
10.35 Amendment No. 13, dated 10.1 to APS' March 1991 Form 10-Q 1-4473 5-15-91
as of April 22, 1991, to
Arizona Nuclear Power
Project Participation
Agreement, dated August
23, 1973, among APS, Salt
River Project Agricultural
Improvement and Power
District, Southern California
Edison Company, Public Service
Company of New Mexico, El Paso
Electric Company, Southern
California Public Power
Authority, and Department of
Water and Power of the City
of Los Angeles
120
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.36 Amendment No. 14 to Arizona 99.1 to the Company's June 2000 1-8962 8-14-00
Nuclear Power Project Form 10-Q Report
Participation Agreement,
dated August 23, 1973, among
APS, Salt River Project
Agricultural Improvement and
Power District, Southern
California Edison Company,
Public Service Company of New
Mexico, El Paso Electric
Company, Southern California
Public Power Authority, and
Department of Water and Power
of the City of Los Angeles
10.37(c) Facility Lease, dated as of 4.3 to APS' Form S-3 Registration 33-9480 10-24-86
August 1, 1986, between State Statement
Street Bank and Trust Company,
as successor to The First
National Bank of Boston, in
its capacity as Owner Trustee,
as Lessor, and APS, as Lessee
10.38(c) Amendment No. 1, dated as of 10.5 to APS' September 1986 Form 1-4473 12-4-86
November 1, 1986, to Facility 10-Q Report by means of
Lease, dated as of August 1, Amendment No. on December 3,
1986, between State Street 1986 Form 8
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its capacity as Owner
Trustee, as Lessor, and APS,
as Lessee
121
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.39(c) Amendment No. 2 dated as of 10.3 to APS' 1988 Form 10-K 1-4473 3-8-89
June 1, 1987 to Facility Report
Lease dated as of August 1,
1986 between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and APS, as Lessee
10.40(c) Amendment No. 3, dated as of 10.3 to APS' 1992 Form 10-K Report 1-4473 3-30-93
March 17, 1993, to Facility
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and APS, as Lessee
10.41 Facility Lease, dated as of 10.1 to APS' November 18 1986 1-4473 1-20-87
December 15, 1986, between Form 8-K Report
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and APS, as Lessee
10.42 Amendment No. 1, dated as of 4.13 to APS' Form S-3 1-4473 8-24-87
August 1, 1987, to Facility Registration Statement No.
Lease, dated as of December 33-9480 by means of August 1,
15, 1986, between State 1987 Form 8-K Report
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Lessor, and APS,
as Lessee
122
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.43 Amendment No. 2, dated as of 10.4 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Lessor, and APS,
as Lessee
10.44(a) Pinnacle West Capital 10.13 to the Company's 1999 Form 1-8962 3-30-00
Corporation Supplemental 10-K Report
Excess Benefit Retirement
Plan, as amended and
restated, dated December 7,
1999
10.45(a) Trust for the Pinnacle West 10.14 to the Company's 1999 Form 1-8962 3-30-00
Capital Corporation, Arizona 10-K Report
Public Service Company and
SunCor Development Company
Deferred Compensation Plans
dated August 1, 1996
10.46(a) First Amendment dated 10.15 to the Company's 1999 Form 1-8962 3-30-00
December 7, 1999 to the Trust 10-K Report
for the Pinnacle West Capital
Corporation, Arizona Public
Service Company and SunCor
Development Company Deferred
Compensation Plans
10.47(a) Directors' Deferred 10.1 to APS' June 1986 Form 10-Q 1-4473 8-13-86
Compensation Plan, as Report
restated, effective January
1, 1986
123
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.48(a) Second Amendment to the 10.2 to APS' 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred Compensation
Plan, effective as of
January 1, 1993
10.49(a) Third Amendment to the 10.1 to APS' September 1994 Form 1-4473 11-10-94
Arizona Public Service 10-Q
Company Directors' Deferred
Compensation Plan, effective
as of May 1, 1993
10.50(a) Fourth Amendment dated 10.8 to the Company's 1999 Form 1-8962 3-30-00
December 28, 1999 to the 10-K Report
Arizona Public Service
Company Directors Deferred
Compensation Plan
10.51(a) Arizona Public Service 10.4 to APS' 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
10.52(a) Third Amendment to the 10.3 to APS' 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.53(a) Fourth Amendment to the 10.2 to APS' September 1994 Form 1-4473 11-10-94
Arizona Public Service 10-Q Report
Company Deferred Compensation
Plan effective as of May 1,
1993
124
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.54(a) Fifth Amendment to the 10.3 to APS' 1996 Form 10-K 1-4473 3-28-97
Arizona Public Service Report
Company Deferred
Compensation Plan
10.55(a) Sixth Amendment to Arizona 10.8 to the Company's 2000 Form 1-8962 3-14-01
Public Service Company 10-K Report
Deferred Compensation Plan
10.56(a) First Amendment effective as 10.7 to the Company's 1999 Form 1-8962 3-30-00
of January 1, 1999, to the 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and El
Dorado Investment Company
Deferred Compensation Plan
10.57(a) Second Amendment effective 10.10 to the Company's 1999 Form 1-8962 3-30-00
January 1, 2000 to the 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and El
Dorado Investment Company
Deferred Compensation Plan
10.58(a) Pinnacle West Capital 10.10 to APS' 1995 Form 10-K 1-4473 3-29-96
Corporation, Arizona Public Report
Service Company, SunCor
Development Company and El
Dorado Investment Company
Deferred Compensation Plan as
amended and restated
effective January 1, 1996
125
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.59(a) Pinnacle West Capital Corp- 10.7 to APS' 1994 Form 10-K 1-4473 3-30-95
oration and Arizona Public Report
Service Company Directors'
Retirement Plan, effective
as of January 1, 1995
10.60(a) Letter Agreement dated July 10.16 to the Company's 1999 Form 1-8962 3-30-00
28, 1995 between Arizona 10-K Report
Public Service Company and
Armando B. Flores
10.61(a) Letter Agreement dated 10.17 to the Company's 1999 Form 1-8962 3-30-00
October 3, 1997 between 10-K Report
Arizona Public Service
Company and James M. Levine
10.62(a) Letter Agreement dated as of 10.8 to APS' 1995 Form 10-K 1-4473 3-29-96
January 1, 1996 between APS Report
and Robert G. Matlock &
Associates, Inc. for
consulting services
10.63(a) Letter Agreement dated 10.7 to APS' 1994 Form 10-K Report 1-4473 3-30-96
December 21, 1993, between
APS and William L. Stewart
10.64(a) Letter Agreement dated 10.8 to APS' 1996 Form 10-K 1-4473 3-28-97
August 16, 1996 between APS Report
and William L. Stewart
10.65(a) Letter Agreement between APS 10.2 to APS' September 1997 Form 1-4473 11-12-97
and William L. Stewart 10-Q Report
10.66(a) Letter Agreement dated
December 13, 1999 between APS
and William L. Stewart
126
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.67(a)(d) Key Executive Employment and 10.1 to June 1999 Form 10-Q Report 1-8962 8-16-99
Severance Agreement between
Pinnacle West and certain
executive officers of
Pinnacle West and its
subsidiaries
10.68(a) Pinnacle West Capital 10.1 to APS' 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option and Report
Incentive Plan
10.69(a) First Amendment dated 10.11 to the Company's 1999 Form 1-8962 3-30-00
December 7, 1999 to the 10-K Report
Pinnacle West Capital
Corporation Stock Option and
Incentive Plan
10.70(a) Pinnacle West Capital A to the Proxy Statement for the 1-8962 4-16-94
Corporation 1994 Long- Term Plan Report for the Company's
Incentive Plan, effective as 1994 Annual Meeting of
of March 23, 1994 Shareholders
10.71(a) First Amendment dated 10.12 to the Company's 1999 Form 1-8962 3-30-00
December 7, 1999 to the 10-K Report
Pinnacle West Capital
Corporation 1994 Long-Term
Incentive Plan
10.72(a) Pinnacle West Capital B to the Proxy Statement for the 1-8962 4-16-94
Corporation Director Equity Plan Report for the Company's
Participation Plan 1994 Annual Meeting of
Shareholders
10.73(a) Pinnacle West Capital 99.1 to the Company's 1-8962 7-3-00
Corporation 2000 Director Registration Statement on Form
Equity Plan S-8 (No. 333-40796)
10.74(a) Pinnacle West Capital 99.2 to the Company's 1-8962 7-3-00
Corporation and Arizona Registration Statement on Form
Public Service Company S-8 (No. 333-40796)
Directors' Retirement Plan,
as amended and restated on
June 21, 2000
127
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
10.75 Agreement No. 13904 (Option 10.3 to APS' 1991 Form 10-K 1-4473 3-19-92
and Purchase of Effluent) Report
with Cities of Phoenix,
Glendale, Mesa, Scottsdale,
Tempe, Town of Youngtown, and
Salt River Project
Agricultural Improvement and
Power District, dated April
23, 1973
10.76 Agreement for the Sale and 10.4 to APS' 1991 Form 10-K 1-4473 3-19-92
purchase of Wastewater Report
Effluent with City of
Tolleson and Salt River
Agricultural Improvement
and Power District, dated
June 12, 1981, including
Amendment No. 1 dated as
of November 12, 1981 and
Amendment No. 2 dated as
of June 4, 1986
10.77(a) APS Director Equity Plan 10.1 to September 1997 Form 10-Q 1-4473 11-12-97
Report
10.78 Territorial Agreement between 10.1 to APS' March 1998 Form 10-Q 1-4473 5-15-98
the Company and Salt River Report
Project
10.79 Power Coordination Agreement 10.2 to APS' March 1998 Form 10-Q 1-4473 5-15-98
between the Company and Salt Report
River Project
10.80 Memorandum of Agreement 10.3 to APS' March 1998 Form 10-Q 1-4473 5-15-98
between the Company and Salt Report
River Project
10.81 Addendum to Memorandum of 10.2 to APS' May 19, 1998 Form 1-4473 6-26-98
Agreement between APS and 8-K Report
Salt River Project dated as
of May 19, 1998
128
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.1 Collateral Trust Indenture 4.2 to APS' 1992 Form 10 K Report 1-4473 3-30-93
among PVNGS II Funding
Corp., Inc., APS and
Chemical Bank, as Trustee
99.2 Supplemental Indenture to 4.3 to APS' 1992 Form 10 K Report 1-4473 3-30-93
Collateral Trust Indenture
among PVNGS II Funding
Corp., Inc., APS and
Chemical Bank, as Trustee
99.3(c) Participation Agreement, 28.1 to APS' September 1992 Form 1-4473 11-9-92
dated as of August 1, 1986, 10-Q Report
among PVNGS Funding Corp.,
Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and
as Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Equity
Participant named therein
129
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.4(c) Amendment No. 1 dated as of 10.8 to APS' September 1986 Form 1-4473 12-4-86
November 1, 1986, to 10-Q Report by means of
Participation Agreement, Amendment No. 1, on December 3,
dated as of August 1, 1986, 1986 Form 8
among PVNGS Funding Corp.,
Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and
as Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Equity
Participant named therein
99.5(c) Amendment No. 2, dated as of 28.4 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of August 1, 1986,
among PVNGS Funding Corp.,
Inc., PVNGS II Funding Corp.,
Inc., State Street Bank and
Trust Company, as successor
to The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and
as Indenture Trustee, APS,
and the Equity Participant
named therein
130
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.6(c) Trust Indenture, Mortgage, 4.5 to APS' Form S-3 Registration 33-9480 10-24-86
Security Agreement and Statement
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston,
as Owner Trustee,
and Chemical Bank, as
Indenture Trustee
99.7(c) Supplemental Indenture No. 10.6 to APS' September 1986 Form 1-4473 12-4-86
1, dated as of November 1, 10-Q Report by means of
1986 to Trust Indenture, Amendment No. 1 on December 3,
Mortgage, Security Agreement 1986 Form 8
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
99.8(c) Supplemental Indenture No. 2 28.14 to APS' 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture, Mortgage, Report
Security Agreement and
Assignment of Facility
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Lease Indenture
Trustee
131
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.9(c) Assignment, Assumption and 28.3 to APS' Form S-3 33-9480 10-24-86
Further Agreement, dated Registration Statement
as of August 1, 1986,
between APS and State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Owner Trustee
99.10(c) Amendment No. 1, dated as of 10.10 to APS' September 1986 Form 1-4473 12-4-86
November 1, 1986, to 10-Q Report by means of
Assignment, Assumption and Amendment No. l on December 3,
Further Agreement, dated as 1986 Form 8
of August 1, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.11(c) Amendment No. 2, dated as of 28.6 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
132
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.12 Participation Agreement, 28.2 to APS' September 1992 Form 1-4473 11-9-92
dated as of December 15, 10-Q Report
1986, among PVNGS Funding
Report Corp., Inc., State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and
as Indenture Trustee under
a Trust Indenture, APS, and
the Owner Participant named
therein
99.13 Amendment No. 1, dated as of 28.20 to APS' Form S-3 1-4473 8-10-87
August 1, 1987, to Registration Statement No.
Participation Agreement, 33-9480 by means of a November
dated as of December 15, 6, 1986 Form 8-K Report
1986, among PVNGS Funding
Corp., Inc. as Funding
Corporation, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, Chemical
Bank, as Indenture Trustee,
APS, and the Owner
Participant named therein
133
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.14 Amendment No. 2, dated as of 28.5 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS Funding
Corp., Inc., PVNGS II Funding
Corp., Inc., State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and
as Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Owner
Participant named therein
99.15 Trust Indenture, Mortgage 10.2 to APS' November 18, 1986 1-4473 1-20-87
Security Agreement and Form 10-K Report
Assignment of Facility
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to
The First National Bank
of Boston, as Owner Trustee,
and Chemical Bank, as
Indenture Trustee
134
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.16 Supplemental Indenture 4.13 to APS' Form S-3 1-4473 8-24-87
No. 1, dated as of August Registration Statement No.
1, 1987, to Trust Indenture, 33-9480 by means of August 1,
Mortgage, Security Agreement 1987 Form 8-K Report
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
99.17 Supplemental Indenture No. 2 4.5 to APS' 1992 Form 10-K Report 1-4473 3-30-93
to Trust Indenture Mortgage,
Security Agreement and
Assignment of Facility
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee, and
Chemical Bank, as Lease
Indenture Trustee
99.18 Assignment, Assumption and 10.5 to APS' November 18, 1986 1-4473 1-20-87
Further Agreement, dated as Form 8-K Report
of December 15, 1986,
between APS and State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Owner Trustee
135
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.19 Amendment No. 1, dated as of 28.7 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of December 15, 1986,
between APS and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.20(c) Indemnity Agreement dated as 28.3 to APS' 1992 Form 10-K Report 1-4473 3-30-93
of March 17, 1993 by APS
99.21 Extension Letter, dated as of 28.20 to APS' Form S-3 1-4473 8-10-87
August 13, 1987, from the Registration Statement No.
signatories of the 33-9480 by means of a November
Participation Agreement to 6, 1986 Form 8-K Report
Chemical Bank
99.22 Arizona Corporation 28.1 to APS' 1991 Form 10-K 1-4473 3-19-92
Commission Order dated Report
December 6, 1991
99.23 Arizona Corporation 10.1 to APS' June 1994 form 10-Q 1-4473 8-12-94
Commission Order dated June Report
1, 1994
99.24 Rate Reduction Agreement 10.1 to APS' December 4, 1995 1-4473 12-14-95
dated December 4, 1995 8-K Report
between APS and the ACC Staff
99.25 ACC Order dated April 24, 1996 10.1 to APS' March 1996 1-4473 5-14-96
Form 10-Q Report
136
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- --------- --------------
99.26 Arizona Corporation 99.1 to APS' 1996 Form 10-K 1-4473 3-28-97
Commission Order, Decision Report
No. 59943, dated December 26,
1996, including the Rules
regarding the introduction of
retail competition in Arizona
99.27 Retail Electric Competition 10.1 to APS' June 1998 Form 10-Q 1-4473 8-14-98
Rules Report
99.28 Arizona Corporation 10.1 to APS' September 1999 10-Q 1-4473 11-15-99
Commission Order, Decision Report
No. 61973, dated October 6,
1999, approving APS'
Settlement Agreement
99.29 Addendum to Settlement 10.1 to the Company's September 1-8962 11-14-00
Agreement 2000 Form 10-Q Report
99.30 Arizona Corporation 10.2 to APS' September 1999 10-Q 1-4473 11-15-99
Commission Order, Decision Report
No. 61969, dated September
29, 1999, including the
Retail Electric Competition
Rules
99.31 APS October 18, 2001 filing 99.6 to the Company's October 18, 1-8962 10-19-01
with the ACC 2001 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 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
(c) An additional document, substantially identical in all material respects to
this Exhibit, has been entered into, relating to an additional Equity
Participant. Although such additional document
137
may differ in other respects (such as dollar amounts, percentages, tax
indemnity matters, and dates of execution), there are no material details
in which such document differs from this Exhibit.
(d) Additional agreements, substantially identical in all material respects to
this Exhibit have been entered into with additional persons. Although such
additional documents may differ in other respects (such as dollar amounts
and dates of execution), there are no material details in which such
agreements differ from this Exhibit.
REPORTS ON FORM 8-K
During the quarter ended December 31, 2001, and the period ended March 27,
2002, the Company filed the following Reports on Form 8-K:
Report dated October 18, 2001 regarding (i) exhibits comprised of financial
information and earnings variance explanations for the periods ended September
30, 2001 and 2000; (ii) the Arizona Supreme Court's decision to review a lower
court decision affirming the 1999 Settlement Agreement; and (iii) APS' October
18, 2001 filing with the ACC requesting ACC approval of a rule variance and a
purchase power agreement with the Company.
Report dated October 22, 2002 comprised of an exhibit of a slide
presentation for use at an analyst conference.
Report dated December 14, 2001 regarding the (i) Arizona Supreme Court
dismissal of an appeal related to the 1999 Settlement Agreement and (ii) new ACC
generic docket relating to electric restructuring in Arizona.
Report dated February 8, 2002 regarding the consolidation of pending ACC
dockets.
138
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Date: March 27, 2002 William J. Post
----------------------------------------
(William J. Post, Chairman of the
Board of Directors
and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
William J. Post Principal Executive Officer March 27, 2002
------------------------------ and Director
(William J. Post, Chairman
of the Board of Directors and
Chief Executive Officer)
Jack E. Davis President and Director March 27, 2002
------------------------------
(Jack E. Davis, President)
Michael V. Palmeri Principal Financial Officer March 27, 2002
------------------------------
(Michael V. Palmeri,
Vice President, Finance)
Chris N. Froggatt Principal Accounting Officer March 27, 2002
------------------------------
(Chris N. Froggatt,
Vice President and Controller)
Edward N. Basha, Jr. Director March 27, 2002
------------------------------
(Edward N. Basha, Jr.)
139
SIGNATURE TITLE DATE
--------- ----- ----
Michael L. Gallagher Director March 27, 2002
------------------------------
(Michael L. Gallagher)
Pamela Grant Director March 27, 2002
------------------------------
(Pamela Grant)
Roy A. Herberger, Jr. Director March 27, 2002
------------------------------
(Roy A. Herberger, Jr.)
Martha O. Hesse Director March 27, 2002
------------------------------
(Martha O. Hesse)
William S. Jamieson, Jr. Director March 27, 2002
------------------------------
(William S. Jamieson, Jr.)
Humberto S. Lopez Director March 27, 2002
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(Humberto S. Lopez)
Robert G. Matlock Director March 27, 2002
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(Robert G. Matlock)
Kathryn L. Munro Director March 27, 2002
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(Kathryn L. Munro)
Bruce J. Nordstrom Director March 27, 2002
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(Bruce J. Nordstrom)
William L. Stewart Director March 27, 2002
------------------------------
(William L. Stewart)
140
Commission File Number 1-8962
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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EXHIBITS TO
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
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Pinnacle West Capital Corporation
(Exact name of registrant as specified in charter)
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INDEX TO EXHIBITS
Exhibit No. Description
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10.1(a) -- 2002 Management Variable Incentive Plan
10.2(a) -- 2002 Senior Management Variable Incentive Plan
10.3(a) -- 2002 Officer Variable Incentive Plan
10.4(a) -- First Amendment to the Pinnacle West Capital Corporation
Supplemental Excess Benefit Retirement Plan
10.5(a) -- Second Amendment to the Pinnacle West Capital Corporation
Supplemental Excess Benefit Retirement Plan
12.1 -- Ratio of Earnings to Fixed Charges
21 -- Subsidiaries of the Company
23.1 -- Consent of Deloitte & Touche LLP
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(a) Management contract or compensatory plan or arrangement to be filed as an
exhibit pursuant to Item 14(c) of Form 10-K.
For a description of the Exhibits incorporated in this filing by reference, see
Part IV, Item 14.