Document/Exhibit Description Pages Size
1: 10-K Annual Report for Year Ended 12/31/2000 115 489K
2: EX-10.1.A 2000 Management Variable Incentive Plan 3 10K
3: EX-10.2.A 2000 Senior Management Variable Incentive Plan 1 6K
4: EX-10.3.A 2000 Officer Variable Incentive Plan 1 6K
5: EX-10.4.A 2000 Management Variable Incentive Plan (Aps) 1 5K
6: EX-10.5.A 2000 Senior Mgmt Variable Incentive Plan (Aps) 1 5K
7: EX-10.6.A 2000 Officers Variable Incentive Plan (Aps) 1 5K
8: EX-10.7 Amendment No. 6 to Co-Tenancy Agreement 17 32K
9: EX-10.8.A Amendment No. 6 to Deferred Compensation Plan 2 10K
10: EX-12.1 Ratio of Earnings to Fixed Charges 1 8K
11: EX-21.1 Subsidiaries of the Company 2 8K
12: EX-23.1 Consent of Deloitte and Touche LLP 1 7K
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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, 2000
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
(State or other jurisdiction 86-0512431
of incorporation or organization) (I.R.S. Employer Identification No.)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(Address of principal executive (602) 250-1000
offices, (Registrant's telephone number,
including zip code) including area code)
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 8, 2001 March 8, 2001
--------------------------------------------------------------------------------
Common Stock, No Par Value 84,727,490 $3,944,064,660(a)
----------
(a) Computed by reference to the closing price on the composite tape on
March 8, 2001, 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. [ ]
================================================================================
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 23, 2001 are incorporated by reference
into Part III hereof.
================================================================================
TABLE OF CONTENTS
PAGE
----
GLOSSARY.................................................................... 1
PART I
Item 1. Business....................................................... 3
Item 2. Properties..................................................... 18
Item 3. Legal Proceedings.............................................. 22
Item 4. Submission of Matters to a Vote of Security Holders............ 22
Supplemental Item.
Executive Officers of the Registrant........................... 23
PART II
Item 5. Market for Registrant's Common Stock and Related Security
Holder Matters............................................... 25
Item 6. Selected Consolidated Data..................................... 26
Item 7. Financial Review............................................... 29
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..... 45
Item 8. Financial Statements and Supplementary Data.................... 46
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 86
PART III
Item 10. Directors and Executive Officers of the Registrant............. 86
Item 11. Executive Compensation......................................... 86
Item 12. Security Ownership of Certain Beneficial Owners and Management. 86
Item 13. Certain Relationships and Related Transactions................. 86
PART IV
Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
and Reports on Form 8-K..................................... 87
SIGNATURES.................................................................. 112
i
GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
AFUDC -allowance for funds used during construction
AISA - Arizona Independent Scheduling Administrator
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
Cholla - Cholla Power Plant
Cholla 4 - Unit 4 of the Cholla Power Plant
Citizens - Citizens Communications Company
Company - Pinnacle West Capital Corporation
CPUC - California Public Utility Commission
DIG - Derivatives Implementation Group
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
1992 Energy Act - National Energy Policy Act of 1992
NPC - Nevada Power Company
NPUC - Nevada Public Utility Commission
NRC - United States Nuclear Regulatory Commission
1
Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended
Palo Verde - Palo Verde Nuclear Generating Station
PG&E - PG&E Corp.
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the
Company
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
SunCor - SunCor Development Company, a subsidiary of the Company
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 common stock of APS. APS is Arizona's largest electric
utility and provides retail and wholesale electric service to the entire state
with the exception of Tucson and about one-half of the Phoenix area. APS also
generates and, directly or through our power marketing division, sells and
delivers electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we intend to conduct our
unregulated generation operations;
* APS Energy Services, which sells energy and energy-related products
and services in competitive retail markets in the western United
States;
* SunCor, which is a developer of residential, commercial, and
industrial real estate projects in Arizona, New Mexico, and Utah; and
* El Dorado, which is primarily a venture capital and investment firm.
We discuss each of these subsidiaries in greater detail below.
At December 31, 2000, we employed about 7,200 people, including the
employees of our subsidiaries. Of these employees, 5,300 were employees of our
major subsidiary, APS, and employees assigned to joint projects of APS where APS
serves as project manager. About 1,900 people were employed by the parent
company and our other subsidiaries. Our principal executive offices are located
at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
See "Financial Review - Business Segments" in Item 7 and Note 18 of Notes
to Consolidated Financial Statements in Item 8 for a discussion of our business
segments.
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; the outcome of regulatory and
legislative proceedings relating to the restructuring; regional economic and
market conditions, including the California energy situation, 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; the successful completion of our generation expansion
program; regulatory issues associated with generation
3
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
stock market (particularly the technology sector in which El Dorado is currently
invested) and the real estate market in SunCor's market areas, which include
Arizona, New Mexico and Utah.
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 850,000 customers. APS provides
wholesale or retail electric service to the entire state of Arizona, with the
exception of Tucson and about one-half of the Phoenix area. APS also generates
and, directly or through our power marketing division, sells and delivers
electricity to wholesale customers in the western United States. During 2000, no
single purchaser or user of energy accounted for more than 3.5% of total
electric revenues.
At December 31, 2000, APS employed 5,300 people, which includes employees
assigned to joint projects where APS is project manager. APS' principal
executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004
(telephone 602-250-1000).
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 "Financial Review -
Business Outlook - Competition and Industry Restructuring" in Item 7 and Note 3
of Notes to Consolidated Financial Statements in Item 8 for a discussion of
electric industry restructuring in Arizona, including APS' 1999 Settlement
Agreement, the ACC retail electric competition rules, and the legal challenges
to both the 1999 Settlement Agreement and 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 customers under rates that have been approved by the ACC.
These rates are fixed 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 year, have been volatile. At various times,
prices in the spot wholesale market have significantly exceeded the amount
included in APS' current retail rates. APS expects these market conditions to
continue in 2001. We believe we have adequately supplemented our current
generation portfolio with power purchased through contracts and hedging
techniques that limit exposure to the volatile spot wholesale power market.
However, in the event of shortfalls due to unforeseen increases in load demand
or generation outages, we may need to purchase additional supplemental power in
the wholesale spot market. Unless APS is able to obtain
4
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.
As discussed in "Financial Review - Electric Competition (Retail)" in Item
7 and in Note 3 of Notes to Financial Statements in Item 8, the 1999 Settlement
Agreement authorizes APS to transfer its competitive generation assets and
services to one or more corporate affiliates no later than December 31, 2002.
APS intends to move its generation assets to Pinnacle West Energy within that
timeframe. Following its receipt of these generation assets, Pinnacle West
Energy expects to sell its power at wholesale to our power marketing division
(Power Marketing). Power Marketing, in turn, is expected to sell power to APS
and to non-affiliated power purchasers. APS is expected to meet fifty percent of
its energy needs under a power purchase agreement with Power Marketing. As
required by the Rules, APS will acquire the remaining fifty percent of its
energy needs through a competitive bid process in which Power Marketing may
participate. We believe these arrangements will allow us to manage APS' exposure
to the wholesale power market during the period within which APS' rates are
fixed, as discussed in the preceding paragraph.
In addition to the introduction of competition pursuant to the 1999
Settlement Agreement and the Rules, 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
preferential low-priced 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
We compete with other utilities, power marketers, and independent power
producers in the sale of electric capacity and energy in the wholesale market.
We expect competition in the wholesale market will remain vigorous. The FERC
regulates rates for wholesale power sales and transmission services. During
2000, approximately 46% of our electric operating revenues resulted from such
sales and services. APS transferred the wholesale power marketing function to
the parent company during 2000.
See "Financial Review - Capital Resources and Cash Requirements - Pinnacle
West Energy" and Note 12 of Notes to Consolidated Financial Statements for
information regarding generation expansion plans.
The 1992 Energy Act and the FERC's rulemaking activities have established
the regulatory framework to open the wholesale energy market to competition. The
1992 Energy Act permits utilities to develop independent electric generating
plants for sales to wholesale customers, and authorizes the FERC to order
transmission access for third parties to transmission facilities owned by
another entity. The 1992 Energy Act does not, however, permit the FERC to
require transmission access to retail customers. Open-access transmission for
wholesale customers provides energy suppliers, including us, with opportunities
to sell and deliver electricity at market-based prices.
On December 20, 1999, the FERC issued its Order No. 2000 regarding Regional
Transmission Organizations (RTO). In its order, the FERC stressed the voluntary
nature of RTO participation by utilities and 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.
5
The characteristics for an acceptable RTO include independence from market
participants, operational control over a region large enough to support
efficient and nondiscriminatory markets, and exclusive authority to maintain
short-term reliability. As required by the FERC order, APS, along with several
neighboring transmission owners located in the southwestern United States, filed
a report with the FERC on October 16, 2000 that detailed the progress in
establishing an RTO that would be responsible for ensuring transmission
reliability and nondiscriminatory access to the regional transmission grid. APS
expects that Desert STAR, the non-profit corporation named in the filing, will
make additional filings with the FERC in the near future to establish itself as
an RTO for the region.
See "Financial Review - Business Outlook - California Energy Market Issues"
in Item 7 for a discussion of the energy situation in California.
The ACC retail electric competition rules require the formation and
implementation of an Arizona Independent Scheduling Administrator Association.
The AISA is anticipated to be a temporary organization until the formation and
implementation of an independent system operator or RTO. APS, as an "Affected
Utility" under the Rules, participated in the creation of the AISA. Recently,
the board of AISA approved a set of operating protocols that have been filed
with the FERC. The operating protocols were partially rejected and the remainder
are currently under review.
See "Financial Review - Business Outlook - Competition and Industry
Restructuring" in Item 7 and Note 3 of Notes to Consolidated Financial
Statements in Item 8 for additional information about the ACC Rules and the
legal challenges to the Rules.
REGULATORY ASSETS
Our major regulatory assets are deferred income taxes and rate
synchronization cost deferrals. As a result of our 1999 Settlement Agreement, we
discontinued the application of SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation," 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 income statement. Prior to the 1999 Settlement Agreement,
under a 1996 regulatory agreement, the ACC accelerated the amortization of
substantially all of our regulatory assets to an eight-year period that would
have ended June 30, 2004. The regulatory assets to be recovered under the 1999
Settlement Agreement are being amortized pursuant to a revised amortization
schedule. See Notes 1, 3, and 10 of Notes to Consolidated Financial Statements
in Item 8 for additional information.
GENERATING FUEL AND PURCHASED POWER
2000 ENERGY MIX
APS' sources of energy during 2000 were: purchased power - 46.0%
(approximately 88% of which was for wholesale power operations); coal - 27.9%;
nuclear - 19.8%; gas - 6.0%; and other (includes oil, hydro and solar) - 0.3%.
6
COAL SUPPLY
CHOLLA APS purchases most of Cholla's coal requirements from a coal
supplier who 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. We expect 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 APS purchases all of Four Corners' coal requirements from a
coal supplier with a long-term lease of coal reserves owned by the Navajo
Nation. Four Corners is under contract for coal through 2004, with options to
extend the contract through the plant site lease expiration in 2017. The Four
Corners lease waives, until July 2001, the requirement that APS and its fuel
supplier pay certain taxes to the Navajo Nation. The coal supplier currently
pays a possessory interest tax to the Navajo Nation, which is reimbursed by the
Four Corners participants. The coal supplier, the Navajo Nation, and the Four
Corners participants agreed to investigate alternative contractual arrangements
and business relationships before the expiration of tax waivers in an effort to
permit the electricity generated at Four Corners to be priced competitively. APS
anticipates that the Navajo Nation will levy additional taxes upon the
expiration of the tax waivers; however, APS cannot currently predict the outcome
of this matter or the amount of any additional taxes.
NAVAJO GENERATING STATION 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 12 of Notes to 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 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. We anticipate that the natural gas requirements for our generation
expansion plans (see Note 12) 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.
NUCLEAR FUEL SUPPLY
The fuel cycle for Palo Verde is comprised of the following stages:
7
* 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 made contractual arrangements to obtain
quantities of uranium concentrates anticipated to be sufficient 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:
* 77% of requirements in 2003;
* 77% of requirements in 2004;
* 44% of requirements in 2005 through 2007; and
* 16% of requirements in 2008 and beyond.
The Palo Verde participants have contracts and options for uranium
conversion services that could be utilized to meet approximately:
* 75% of requirements in 2001; and
* 80% of requirements in 2002.
The Palo Verde 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. In addition, existing
contracts will provide fuel assembly fabrication services until at least 2015
for each Palo Verde unit.
APS is currently pursuing several offers to procure the uranium, conversion
services and the enrichment services components of nuclear fuel to meet all of
Palo Verde's requirements through 2008.
SPENT NUCLEAR FUEL AND WASTE DISPOSAL Pursuant to the Nuclear Waste Act,
the DOE must accept and dispose of all spent nuclear fuel and other high-level
radioactive wastes generated by domestic power reactors. The NRC requires
operators of nuclear power reactors to enter into spent fuel disposal contracts
with the DOE. Under the Nuclear Waste Act, the DOE was to develop a permanent
repository for the storage and disposal of spent nuclear fuel by 1998. The DOE
has announced that such a permanent 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 precluding the DOE from
excusing its own delay, but refused to order the DOE to begin accepting spent
nuclear fuel. Based on this decision, a number of utilities filed damages
lawsuits against DOE in the Court of Federal Claims. In decisions that became
final in December 2000, the United States Court of Appeals for the Federal
Circuit held that utilities do not
8
have to exhaust the DOE administrative claims before filing lawsuits for damages
against the DOE in the Court of Federal Claims.
Bills have been introduced in prior sessions of the U.S. Congress
contemplating the construction of a central interim storage facility, but no
bill has been enacted into law. We cannot currently predict what steps will be
taken in this area by the current Congress and the Administration.
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).
According to DOE spokespersons, the fund may now be at a level less than needed
to achieve a 2010
operational date for a permanent repository. No funding will be available for a
central interim facility until one is authorized by Congress.
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 12 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 also acknowledges that their ultimate resolution in a timely
fashion will require political resolve and action on national and regional
scales which APS is less able to predict. APS expects to vigorously protect and
pursue its rights related to this matter.
PURCHASED POWER AGREEMENTS
In addition to that available from its own generating capacity (see
"Properties" in Item 2), APS purchases electricity under various arrangements.
One of the most important of these is a long-term contract with Salt River
Project. The amount of electricity available to APS is based in large part on
customer demand within certain areas now served by APS pursuant to a related
territorial agreement. The generating capacity available to APS pursuant to the
contract was 322 MW from January through May 2000, and starting June 2000, it
changed to 329 MW. In 2000, APS received approximately 1,422,000 MWh of energy
under the contract and paid about $76.7 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
9
winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp
each has 480 MW per hour of capacity and a related amount of energy available to
it under the agreement for their respective seasons. In 2000, APS received
approximately 396,000 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 2000, PacifiCorp received offers of
865,800 MWh and purchased about 218,000 MWh.
CONSTRUCTION PROGRAM
During the years 1998 through 2000, APS incurred approximately $1.2 billion
in capital expenditures. APS' capital expenditures for the years 2001 through
2003 are expected to be primarily for expanding transmission and distribution
capabilities to meet growing customer needs, upgrading existing utility
property, and for environmental purposes. APS' capital expenditures, including
expenditures for environmental control facilities, for the years 2001 through
2003 have been estimated as follows:
(dollars in millions)
BY YEAR BY MAJOR FACILITIES
------- -------------------
2001 $ 455 Production $ 226
2002 401 Transmission and Distribution 924
2003 294 ------
------ Total $1,150
Total $1,150 ======
======
The amounts for 2001 through 2003 exclude capitalized interest costs and
include capitalized property taxes and about $30-$35 million annually (except
2003) for nuclear fuel. APS conducts a continuing review of its construction
program. See "Financial Review - Capital Needs and Resources" in Item 7 for
additional information.
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
2000, the replacement fund requirement amounted to approximately $149 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 so redeemed.
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:
10
* "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 establishes 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 within 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 requires the EPA to establish a Grand Canyon Visibility
Transport Commission to complete a study on visibility impairment in sixteen
"Class I Areas" (large national parks and wilderness areas) on the Colorado
Plateau. The Navajo Generating Station, Cholla, and Four Corners are located
near several Class I Areas on the Colorado Plateau. The Visibility Commission
completed its study and on June 10, 1996 submitted its final recommendations to
the EPA.
On April 22, 1999, the EPA announced final regional haze rules. These new
regulations require states to submit, by 2008, implementation plans to eliminate
all man-made emissions causing visibility impairment in certain specified areas,
including Class I Areas in the Colorado Plateau. The 2008 implementation plans
must also include consideration and potential application of best available
retrofit technology for major stationary sources which came into operation
between August 1962 and August 1977, such as the Navajo Generating Station,
Cholla, and Four Corners.
The rules allow the nine western states and tribes that participated in the
Visibility Commission process to follow an alternate implementation plan and
schedule for the Class I Areas considered by the Visibility Commission. Under
this option, those states and tribes would submit implementation plans by 2003,
which would incorporate certain regional sulfur dioxide emissions milestones for
the years 2003, 2008, 2013, and 2018 (which includes 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.
11
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 Court further held that the EPA could not consider the cost
of reducing harmful emissions when setting air quality standards. However, the
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.
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 the cost of any necessary remediation of
the substances. 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. APS is in the process of conducting an
investigation to determine the extent and scope of contamination at the plant
site. 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.
12
MANUFACTURED GAS PLANT SITES APS is currently investigating properties
which it now owns or which were at one time 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 remediation 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.
PURPORTED NAVAJO ENVIRONMENTAL REGULATION
Four Corners and the Navajo Generating Station are located on the Navajo
Reservation and are held under easements granted by the federal government as
well as leases from the Navajo Nation. APS is the Four Corners operating agent.
APS owns a 100% interest in Four Corners Units 1, 2, and 3, and a 15% interest
in Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating
Station Units 1, 2, and 3.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the
Navajo Nation Pesticide Act (collectively, the Acts). Pursuant to the Acts, the
Navajo Nation Environmental Protection Agency is authorized to promulgate
regulations covering air quality, drinking water, and pesticide activities,
including those that occur at Four Corners and the Navajo Generating Station. 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 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 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 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 promulgated regulations specifying those
provisions of the Clean Air Act for which it is appropriate to treat Indian
tribes in the same manner as states. The EPA indicated that it believes that the
Clean Air Act generally would supersede pre-existing binding agreements that may
limit the scope of tribal authority over reservations. On April 10, 1998, APS
13
filed a Petition for Review in the United States Court of Appeals for the
District of Columbia. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 98-1196. On February 19, 1999, the EPA
promulgated regulations setting forth the EPA's approach to issuing Federal
operating permits to covered stationary sources on Indian reservations. On April
15, 1999, APS filed a Petition for Review in the United States Court of Appeals
for the District of Columbia. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 99-1146. After the litigation was filed,
the EPA indicated it had not determined whether the Clean Air Act would
supersede pre-existing binding agreements involving Four Corners and the Navajo
Generating Station. On May 5, 2000, the United States Court of Appeals for the
District of Columbia upheld the EPA's regulations on treatment of Indian tribes
in the same manner as states. However, the Court determined that the impact of
this ruling on the pre-existing binding agreements involving Four Corners and
the Navajo Generating Station was not ripe for adjudication because the EPA had
not made a determination that the Clean Air Act superseded those agreements. On
June 29, 2000, at the request of the Court, APS filed a motion to dismiss Four
Corners from this petition on the grounds that the impact of the regulations on
pre-existing binding agreements was not "ripe" for judicial resolution based on
the EPA's issuance of an official notice indicating that it had not yet
determined whether the pre-existing binding agreements with Four Corners and
Navajo Generating Station were abrogated by the Clean Air Act. The Court
ultimately dismissed Four Corners on these grounds.
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 Tribe 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 in recent years.
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 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
14
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 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. The Arizona Supreme Court
issued a decision confirming that certain groundwater rights may be available to
the federal government and Indian tribes. APS and other parties petitioned the
U.S. Supreme Court for review of this decision and the petition was denied. In
addition, the Arizona Supreme Court issued a decision affirming the lower
court's criteria for solving groundwater claims. APS and other parties filed
motions for reconsideration on one aspect of that decision. Those motions have
been denied by the Arizona Supreme Court. 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 Superior Court. (IN RE THE
GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE LITTLE COLORADO RIVER
SYSTEM AND SOURCE, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417).
APS' groundwater resource utilized at Cholla is within the geographic area
subject to the adjudication and is therefore potentially at issue in the case.
APS' claims dispute the court's jurisdiction over its groundwater rights.
Alternatively, APS seeks confirmation of such rights. The parties are in the
process of settlement negotiations with respect to this matter. No trial date
concerning our 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 Corporation was incorporated in 1999 under the laws of
the State of Arizona and is engaged principally in the business of the
development and production of wholesale energy. Pinnacle West Energy is the
subsidiary through which we intend to conduct our future unregulated generation
operations. Pinnacle West Energy's principal offices are located at 400 North
Fifth Street, Station 8987, Phoenix, Arizona 85004 (telephone (602) 250-4145).
Pinnacle West Energy's capital expenditures in 2000 were $193 million.
Projected capital expenditures are $659 million in 2001; $129 million in 2002;
and $254 million in 2003. The amounts include about $122 million in 2003 for
capital improvements to existing generating facilities. At December 31, 2000,
Pinnacle West Energy had total assets of $229 million.
See Note 3 of Notes to Consolidated Financial statements for information
regarding the transfer of APS' generation assets to Pinnacle West Energy. See
"Financial Review - Capital Needs and Resources - Capital Resources and Cash
Requirements - Pinnacle West Energy" and Note 12 of Notes to Consolidated
Financial Statements for information regarding Pinnacle West Energy's generation
expansion plans.
15
BUSINESS OF APS ENERGY SERVICES COMPANY, INC.
APS Energy Services was incorporated in 1998 under the laws of the State of
Arizona and is engaged principally in the business of selling unregulated power
and related services. APS Energy Services' principal offices are located at 400
East Van Buren Street, Station 8103, Phoenix, Arizona 85004 (telephone (602)
250-5000).
During the first full two years of operations, APS Energy Services' net
losses were about $9 million in 1999 and $13 million in 2000. At December 31,
2000, APS Energy Services had total assets of $23 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 have approximately 790 full and
part-time employees.
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 5,000 acres
remaining to be developed west of Phoenix at its Palm Valley project in the area
of the towns of 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 and 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 will begin two new
projects in 2001:
* Hayden Ferry Lakeside - an 18-acre, mixed-use commercial/residential
project located in Tempe, Arizona; and
* StoneRidge - an 1,850-acre, master-planned community with golf course
amenities in Prescott Valley, Arizona.
For the past three years, SunCor's operating revenues were about: $158
million in 2000; $130 million in 1999; and $124 million in 1998. For those same
periods, SunCor's net income was about: $11 million in 2000; $6 million in 1999;
and $45 million in 1998. About $40 million of SunCor's 1998 net income
represents income related to the recognition of a deferred tax asset. The
deferred tax asset relates to net operating losses and book/tax basis
differences. SunCor is expected
16
to realize these benefits in subsequent periods pursuant to an intercompany tax
allocation agreement. On a consolidated basis, there was no impact to
consolidated net income.
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. On the basis of projects now under development, SunCor
expects its capital needs over the next three years to be: $75 million in 2001;
$23 million in 2002; and $14 million in 2003.
At December 31, 2000, SunCor had total assets of about $462 million. See
Note 6 of Notes to Consolidated Financial Statements in Item 8 for information
regarding SunCor's long-term debt. SunCor intends to continue its focus on real
estate development in master-planned communities and the development of
mixed-use residential, commercial, office, and industrial projects.
BUSINESS OF EL DORADO INVESTMENT COMPANY
El Dorado was incorporated in 1983 under the laws of the State of Arizona
and is engaged principally in the business of making equity investments in other
companies. El Dorado's short-term goal is to convert its venture capital
portfolio to cash as quickly and as advantageously as possible. On a long-term
basis, we may use El Dorado, when appropriate, as our subsidiary for new
ventures that are strategic to our principal business of generating,
distributing, and marketing electricity. El Dorado's offices are located at 400
North Fifth Street, Station 9988, Phoenix, Arizona 85004 (telephone
602-250-3517).
At December 31, 2000, El Dorado had an investment in a venture capital
partnership, a 54% interest in a privately held company specializing in nuclear
spent fuel technology, limited partnership interests in two professional sports
teams, and an investment in a technology company. See Note 1 of Notes to
Consolidated Financial Statements in Item 8 for information regarding El
Dorado's investments.
For the past three years, El Dorado's net income was about: $2 million in
2000; $11 million in 1999; and $5 million in 1998. At December 31, 2000, El
Dorado had total assets of $21 million.
17
ITEM 2. PROPERTIES
ACCREDITED CAPACITY
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
----------
1,712,000
----------
Gas or Oil:
Two steam units at Ocotillo and two steam units at Saguaro. 435,000(1)
Eleven combustion turbine units............................ 493,000
Three combined cycle units................................. 255,000
----------
1,183,000
----------
Nuclear:
29.1% owned or leased Units 1, 2, and 3 at Palo Verde...... 1,086,300
---------
Hydro and Solar................................................. 6,000
----------
Total 3,987,300
==========
----------
(1) West Phoenix steam units (108,300 kW) are currently mothballed, but are
expected to be back in service by summer 2001.
----------
RESERVE MARGIN
APS' 2000 peak one-hour demand on its electric system was recorded on July
25, 2000 at 5,478,500 kW, compared to the 1999 peak of 4,934,700 kW recorded on
August 24. Taking into account additional capacity then available to APS under
long-term purchase power contracts as well as APS' own generating capacity, APS'
capability of meeting system demand on July 25, 2000, amounted to 4,774,600 kW,
for an installed reserve margin of (15.3%). 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 2000 peak amounted to 3,501,600 kW, for a margin of (27.5%).
Firm purchases, including short-term seasonal purchases, totaling 2,238,000 kW
were in place at the time of the peak ensuring the ability to meet the load
requirement, with an actual reserve margin of 6.4%.
18
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.
See "Generating Fuel and Purchased Power - Coal Supply" in Item 1 for a
discussion of changes in the amount of royalty payments and expiration of tax
waivers under the Navajo Generating Station and Four Corners leases.
PALO VERDE NUCLEAR GENERATING STATION
PALO VERDE LEASES
See Note 10 of Notes to Consolidated Financial Statements in Item 8 for a
discussion of three sale and 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 an external sinking fund 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, and 3. The decommissioning costs of Palo Verde Units 1,
2, and 3 are currently included in 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 13 of Notes to Consolidated Financial
Statements in Item 8 for additional information about our nuclear
decommissioning costs. See "Financial Review - Business Outlook - Competition
and Industry Restructuring" 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.
19
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 12 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 "Financial Review ___ Capital
Needs and Resources" in Item 7 for a discussion of our construction plans.
See Notes 6, 10, and 11 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" and "Business of SunCor Development
Company" for information regarding Pinnacle West Energy's and SunCor's
properties.
20
[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, and the location of transmission lines
operated by APS for others. The 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. 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.
21
ITEM 3. LEGAL PROCEEDINGS
APS In June 1999, the Navajo Nation served Salt River Project with a
lawsuit naming Salt River Project, several Peabody Coal Company entities,
Southern California Edison Company and other defendants, and citing various
claims in connection with the renegotiations of the coal royalty and lease
agreements under which Peabody mines coal for the Navajo Generating Station and
the Mohave Generating Station. THE NAVAJO NATION V. PEABODY HOLDING COMPANY,
INC., ET AL., United States District Court for the District of Columbia,
CA-99-0469-EGS. APS is a 14% owner of the Navajo Generating Station, which Salt
River Project operates. The suit alleges, among other things, that the
defendants obtained a favorable coal royalty rate by improperly influencing the
outcome of a federal administrative process under which the royalty rate was to
be adjusted. The suit seeks $600 million in damages, treble damages, punitive
damages of not less than $1 billion, and the ejection of defendants "from all
possessory interests and Navajo Tribal lands" arising out of the [primary coal
lease]. Salt River Project has advised APS that it denies all charges and will
vigorously defend itself. Because the litigation is in preliminary stages, we
cannot currently predict the outcome of this matter.
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.
APS is a party to a power service agreement with Citizens Communications
Company under which APS supplies Citizens with power. By letter dated March 7,
2001, Citizens advised APS that it believes APS has overcharged Citizens by over
$50 million under the agreement since the summer of 2000. APS believes that its
charges to Citizens under the agreement are fully in accordance with the terms
of the agreement and APS will vigorously defend any contrary claims raised by
Citizens.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
22
SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers are as follows:
Name Age at March 1, 2001 Position(s) at March 1, 2001
---- -------------------- ----------------------------
William J. Post 50 Chairman of the Board and
Chief Executive Officer (1)
Jack E. Davis 54 President and President, APS Energy
Delivery and Sales (1)
Robert S. Aiken 44 Vice President, Federal Affairs
John G. Bohon 55 Vice President, Corporate Services &
Human Resources
Armando B. Flores 57 Executive Vice President, Corporate
Business Services
Edward Z. Fox 47 Vice President, Communications,
Environment & Safety
Chris N. Froggatt 43 Vice President & Controller
Barbara M. Gomez 46 Treasurer
James M. Levine 51 Executive Vice President, APS
Generation
Nancy C. Loftin 47 Vice President & General Counsel
Michael V. Palmeri 42 Vice President, Finance
Martin L. Shultz 56 Vice President, Government Affairs
William L. Stewart 57 President, APS Generation and
President, Pinnacle West Energy
Faye Widenmann 52 Vice President and Secretary
(1) member of the Board of Directors
The executive officers of the Company 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
the Company 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 (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 and Blue Cross-Blue
Shield of Arizona.
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.
23
Mr. Aiken was elected to his present position in July 1999. Prior to that
time he was the Company'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. 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 to his present position in July 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. 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).
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.
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. 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 President of Pinnacle West Energy.
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.
24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
STOCK AND RELATED SECURITY HOLDER 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 8, 2001, our common stock was
held of record by approximately 39,847 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 2000 and 1999, and the dividends declared during each of the
four quarters for 2000 and 1999.
25
ITEM 6. SELECTED CONSOLIDATED DATA
(dollars in thousands, except per share amounts)
[Enlarge/Download Table]
2000 1999 1998 1997 1996
------------ ------------ ------------ ------------ ------------
OPERATING RESULTS
Operating revenues
Electric $ 3,531,810 $ 2,293,184 $ 2,006,398 $ 1,878,553 $ 1,718,272
Real estate 158,365 130,169 124,188 116,473 99,488
Income from continuing
operations $ 302,332 $ 269,772 $ 242,892 $ 235,856 $ 211,059 (a)
Discontinued operations -- 38,000 (d) -- -- (9,539)(b)
Extraordinary charge - net of
income tax -- (139,885)(e) -- -- (20,340)(c)
------------ ------------ ------------ ------------ ------------
Net income $ 302,332 $ 167,887 $ 242,892 $ 235,856 $ 181,180
============ ============ ============ ============ ============
COMMON STOCK DATA
Book value per share - year-end $ 28.09 $ 26.00 $ 25.50 $ 23.90 $ 22.51
Earnings (loss) per average
common share outstanding
Continuing operations - basic $ 3.57 $ 3.18 $ 2.87 $ 2.76 $ 2.41 (a)
Discontinued operations -- 0.45 -- -- (0.11)
Extraordinary charge -- (1.65) -- -- (0.23)
------------ ------------ ------------ ------------ ------------
Net income - basic $ 3.57 $ 1.98 $ 2.87 $ 2.76 $ 2.07
============ ============ ============ ============ ============
Continuing operations -
diluted $ 3.56 $ 3.17 $ 2.85 $ 2.74 $ 2.40 (a)
Net income - diluted $ 3.56 $ 1.97 $ 2.85 $ 2.74 $ 2.06
Dividends declared per share $ 1.425 $ 1.325 $ 1.225 $ 1.125 $ 1.025
Indicated annual dividend rate -
year-end $ 1.50 $ 1.40 $ 1.30 $ 1.20 $ 1.10
Average common shares
outstanding - basic 84,732,544 84,717,135 84,774,218 85,502,909 87,441,515
Average common shares
outstanding - diluted 84,935,282 85,008,527 85,345,946 86,022,709 88,021,920
TOTAL ASSETS $ 7,149,151 $ 6,608,506 $ 6,824,546 $ 6,850,417 $ 6,989,289
============ ============ ============ ============ ============
LIABILITIES AND EQUITY
Long-term debt less current
maturities $ 1,955,083 $ 2,206,052 $ 2,048,961 $ 2,244,248 $ 2,372,113
Other liabilities 2,811,354 2,196,721 2,516,993 2,407,572 2,428,180
------------ ------------ ------------ ------------ ------------
4,766,437 4,402,773 4,565,954 4,651,820 4,800,293
Minority interests
Non-redeemable preferred
stock of APS -- -- 85,840 142,051 165,673
Redeemable preferred stock of
APS -- -- 9,401 29,110 53,000
Common stock equity 2,382,714 2,205,733 2,163,351 2,027,436 1,970,323
------------ ------------ ------------ ------------ ------------
Total liabilities and equity $ 7,149,151 $ 6,608,506 $ 6,824,546 $ 6,850,417 $ 6,989,289
============ ============ ============ ============ ============
26
(a) Includes an after-tax charge of $18.9 million ($0.22 per share) for a
voluntary severance program and about $12 million ($0.13 per share) of
income tax benefits related to capital loss carryforwards.
(b) Charges, net of tax, associated with the settlement of a legal matter
related to MeraBank, A Federal Savings Bank.
(c) Charges associated with the repayment or refinancing of the parent
company's high-coupon debt.
(d) Tax benefit stemming from the resolution of income tax matters related to
MeraBank, A Federal Savings Bank.
(e) Charges associated with a regulatory disallowance.
(dollars in thousands, except per share amounts)
[Enlarge/Download Table]
2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------
ELECTRIC OPERATING
REVENUES
Residential $ 880,468 $ 805,173 $ 766,378 $ 746,937 $ 721,877
Commercial 771,909 733,038 699,016 687,988 678,130
Industrial 146,088 159,329 172,296 164,696 162,324
Irrigation 6,498 7,374 7,288 8,706 9,448
Other 10,719 11,708 10,644 11,842 13,078
----------- ----------- ----------- ----------- -----------
Total retail 1,815,682 1,716,622 1,655,622 1,620,169 1,584,857
Wholesale 1,594,541 506,877 300,698 226,828 98,560
Transmission for others 14,766 11,348 11,058 10,295 10,240
Miscellaneous services 106,821 58,337 39,020 21,261 24,615
----------- ----------- ----------- ----------- -----------
Total electric operating revenues $ 3,531,810 $ 2,293,184 $ 2,006,398 $ 1,878,553 $ 1,718,272
=========== =========== =========== =========== ===========
ELECTRIC SALES (MWH)
Residential 9,780,680 8,774,822 8,310,689 7,970,309 7,541,440
Commercial 10,057,707 9,543,853 8,697,397 8,524,882 8,233,762
Industrial 2,511,292 2,561,349 3,279,430 3,123,283 3,039,357
Irrigation 87,073 99,669 84,640 112,363 121,775
Other 97,772 94,877 90,927 86,090 84,362
----------- ----------- ----------- ----------- -----------
Total retail 22,534,524 21,074,570 20,463,083 19,816,927 19,020,696
Wholesale 21,997,357 15,693,834 10,317,391 9,233,573 3,367,234
----------- ----------- ----------- ----------- -----------
Total electric sales 44,531,881 36,768,404 30,780,474 29,050,500 22,387,930
=========== =========== =========== =========== ===========
ELECTRIC CUSTOMERS -
END OF YEAR
Residential 762,574 735,359 708,215 680,478 654,602
Commercial 90,273 86,707 83,506 81,246 78,178
Industrial 3,286 3,183 3,084 3,192 3,055
Irrigation 371 754 710 764 841
Other 965 932 895 851 828
----------- ----------- ----------- ----------- -----------
Total retail 857,469 826,935 796,410 766,531 737,504
Wholesale 67 73 67 50 48
----------- ----------- ----------- ----------- -----------
Total electric customers 857,536 827,008 796,477 766,581 737,552
=========== =========== =========== =========== ===========
See "Financial Review" on pages 29-45 for a discussion of certain information in
the table above.
27
QUARTERLY STOCK PRICES AND DIVIDENDS
STOCK SYMBOL: PNW
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
Dividends
Per
1999 High Low Close Share(a)
---- ---- --- ----- --------
1st Quarter $43.38 $35.94 $36.38 $ 0.325
2nd Quarter 42.94 36.25 40.25 0.650
3rd Quarter 41.31 34.69 36.38 --
4th Quarter 38.13 30.19 30.56 0.350
(a) Dividends for the 3rd quarter of 1999 were declared in June 1999.
28
ITEM 7. FINANCIAL REVIEW
INTRODUCTION
In this section, we explain the results of operations, general financial
condition, and outlook for Pinnacle West and our subsidiaries: Arizona Public
Service Company (APS), Pinnacle West Energy Corporation (Pinnacle West Energy),
APS Energy Services Company, Inc. (APS Energy Services), SunCor Development
Company (SunCor), and El Dorado Investment Company (El Dorado), including:
* the changes in our earnings from 1999 to 2000 and from 1998 to 1999;
* the effects of regulatory agreements on our results and outlook;
* our capital needs and resources;
* 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 retail and wholesale electric
service to the entire state with the exception of Tucson and about one-half of
the Phoenix area. APS also generates and, directly or through our power
marketing division, sells and delivers electricity to wholesale customers in the
western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we intend to conduct our
unregulated generation operations;
* APS Energy Services, which sells energy and energy-related products
and services in competitive retail markets in the western United
States;
* SunCor, which is a developer of residential, commercial, and
industrial real estate projects in Arizona, New Mexico, and Utah; and
* El Dorado, which is primarily a venture capital and investment firm.
OUR BUSINESS STRATEGIES
Our business strategies are linked to the strong growth characteristics of
Arizona and the western regional market. We are committed to the West and are
pursuing the following primary strategies:
29
* Continuing focus on customer value provided by APS, our regulated
"energy delivery" company;
* Expanding our interests in competitively efficient generation assets
in the West through Pinnacle West Energy by developing new plants,
increasing our ownership share of plants that we already operate and
partially own, and buying plants from other utilities;
* Aggressively managing costs, with an emphasis on the reduction of
variable costs per generating unit (fuel, operations, and maintenance
expenses) and on increased productivity through technological
efficiencies; and
* Managing energy activities, including:
* continuing expansion of wholesale operations;
* managing commodity price risk; and
* providing sufficient capacity, energy, and ancillary services to
reliably meet obligations to our regulated service customers.
BUSINESS SEGMENTS
As we discuss below in greater detail, APS' 1999 Settlement Agreement with
the Arizona Corporation Commission (ACC) authorizes APS to transfer its
competitive generation assets and services to one or more corporate affiliates
no later than December 31, 2002. We have internally organized our operations
into the following two principal business segments, determined by products,
services, and regulatory environment:
* The electricity delivery business segment, which consists of the
transmission and distribution of electricity and wholesale activities;
and
* The generation business segment, which consists of our generation
activities.
See "Business Segments" in Note 18 for more information about our business
segments. In general, we have structured our discussion below based on existing
legal entities rather than the operating segments defined by the new
organizational structure because we continue to analyze these matters internally
by legal entity. The "Results of Operations," for example, primarily reflect the
results of APS' operations because APS currently owns substantially all of our
assets and produces substantially all of our profits.
Throughout this Financial Review, we refer to specific "Notes" in the Notes
to Consolidated Financial Statements that begin on page 54. These Notes add
further details to the discussion.
30
RESULTS OF OPERATIONS
The following is a summary of net income for 2000, 1999, and 1998:
(dollars in millions)
[Download Table]
2000 1999 1998
-------- -------- --------
APS $ 307 $ 267 $ 246
Pinnacle West Energy (2) -- --
APS Energy Services (13) (9) --
SunCor 11 6 45
El Dorado 2 11 5
Parent Company (3) (5) (53)
-------- -------- --------
Income from Continuing Operations 302 270 243
Income Tax Benefit from Discontinued Operations -- 38 --
Extraordinary Charge - Net of Income Taxes of $94 -- (140) --
-------- --------- --------
Net Income $ 302 $ 168 $ 243
======== ======== ========
2000 COMPARED WITH 1999
Our 2000 consolidated net income was $302 million compared with $168
million in 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 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 increased $32 million, or 12%, over 1999
primarily because of increases in wholesale and retail electric sales and in
real estate profits. These positive factors more than offset decreases resulting
from the completion of investment tax credit (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.
In 2000, electric operating revenues increased $1.2 billion primarily
because of:
* increased wholesale revenues ($1.1 billion);
* increases in the number of retail electricity customers and the
average amount of electricity used by customers ($97 million); and
* weather impacts ($33 million).
31
As mentioned above, these positive factors were partially offset by the
effects of reductions in retail electricity prices ($28 million).
The increase in wholesale revenues resulted primarily from higher prices
and increased activity in western United States wholesale power markets. These
revenues were accompanied by increases in purchased power and fuel expense of
$1.0 billion.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.
The increase in real estate profits resulted from increases in sales of
land and homes by SunCor.
The increase in operations and maintenance expenses, which primarily
related to customer growth, was substantially offset by $20 million of
non-recurring items recorded in 1999.
Net other income and expense decreased $11 million primarily because of a
decrease 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.
1999 COMPARED WITH 1998
Our 1999 consolidated net income was $168 million compared with $243
million in 1998. Our 1999 net income decreased $75 million from 1998 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 decrease in our 1999 net income was
partially offset by 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 increased $27 million, or 11%, over 1998
primarily because of increases in retail electricity revenues and lower
financing costs. These positive factors more than offset the effects of retail
electricity price reductions and higher utility operations and maintenance
expense. See "Regulatory Agreements" below and Note 3 for additional information
about the price reductions.
In 1999, electric operating revenues increased $287 million primarily
because of:
* increased wholesale revenues ($219 million);
* increases in retail electricity customers and the average amount of
electricity used by customers ($81 million); and
* miscellaneous factors ($9 million).
32
As mentioned above, these positive factors were partially offset by the
effects of reductions in retail prices ($22 million).
The increase in wholesale revenues resulted from higher prices and
increased activity in western United States wholesale markets. The revenues were
accompanied by an increase in purchased power expenses. Although these
activities contributed positively to earnings in both periods, the contribution
in 1999 was lower than in 1998.
Operations and maintenance expenses increased $27 million primarily because
of $20 million of non-recurring items recorded in 1999, including a provision
for certain environmental costs. Other increases primarily related to customer
growth were partially offset by lower employee benefit costs.
Net other income and expense increased $10 million primarily because of an
increase 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, full offer 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 now
being amortized as follows:
33
(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
annual revenue by about $49 million annually ($29 million after income taxes).
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).
CAPITAL NEEDS AND RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the
period ended December 31, 2000 and estimated capital expenditures for the next
three years:
34
CAPITAL EXPENDITURES
(dollars in millions)
(actual) (estimated)
------ ----------------------------
2000 2001 2002 2003
------ ------ ------ ------
APS
Delivery $ 285 $ 337 $ 293 $ 294
Existing Generation (a) 187 118 108 --
------ ------ ------ ------
472 455 401 294
------ ------ ------ ------
Pinnacle West Energy (b)
Generation Expansion 193 659 129 132
Existing Generation (a) -- -- -- 122
------ ------ ------ ------
193 659 129 254
------ ------ ------ ------
SunCor (c) 50 75 23 14
------ ------ ------ ------
Other (d) -- 21 9 9
------ ------ ------ ------
Total $ 715 $1,210 $ 562 $ 571
====== ====== ====== ======
(a) Pursuant to the 1999 Settlement Agreement, APS is required to move its
generating assets and competitive services no later than December 31, 2002.
(b) Does not include the Southern California Edison (SCE) purchase agreements.
See Note 12 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.
(d) Primarily APS Energy Services.
CAPITAL RESOURCES AND CASH REQUIREMENTS
PINNACLE WEST (PARENT COMPANY)
During the past three years, our primary cash needs were for:
* dividends to our shareholders;
* equity infusions into our subsidiaries, including $200 million
invested in APS from 1996 through 1999 as part of the 1996 regulatory
agreement (see Note 3) and $193 million invested in Pinnacle West
Energy for 2000 capital expenditures;
* interest payments; and
* optional and mandatory repayment of principal on our long-term debt.
Over the next three years, we anticipate that our cash needs will fall into
these same categories, although we expect our equity infusions into Pinnacle
West Energy to continue as it
35
invests in additional generating facilities (see below) until it begins to
finance its own construction needs.
Our primary sources of cash are dividends from our subsidiaries and
external financing. For the years 1998 through 2000, total dividends from
subsidiaries were $596 million, which included $510 million from APS, $50
million from SunCor, and $36 million from El Dorado.
Our long-term debt at December 31, 2000 was $238 million compared to $106
million at December 31, 1999. We have a $250 million line of credit, under which
we had $188 million of borrowings outstanding at December 31, 2000. Our debt
repayment requirements for the next three years are approximately: $213 million
in 2001, zero in 2002, and $25 million in 2003.
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.
During the period from 1998 through 2000, APS paid for substantially all of
its capital expenditures with cash from operations. APS expects to do so in 2001
through 2003, as well.
See the table above for actual capital expenditures in 2000 and projected
capital expenditures for the next three years. In general, most of APS'
projected capital expenditures are for:
* expanding transmission and distribution capabilities to serve growing
customer needs;
* upgrading existing utility property; and
* environmental purposes.
During 2000, APS redeemed approximately $357 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: $380 million in 2001; $125 million in 2002; and zero in
2003. APS made optional redemptions of about $13 million of long-term debt in
February 2001. Based on market conditions and optional call provisions, APS may
make optional redemptions of long-term debt from time to time.
As of December 31, 2000, 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 2000, APS
had about $82 million of commercial paper and no long-term bank borrowings
outstanding.
APS' long-term debt was $2.1 billion at December 31, 2000 and 1999.
Although provisions in APS' first mortgage bond indenture and ACC financing
orders establish maximum amounts of additional first mortgage bonds that APS may
issue, APS does not expect any of these provisions to limit its ability to meet
its capital requirements.
36
PINNACLE WEST ENERGY
Pinnacle West Energy has announced plans to build up to 2,800 megawatts
(MW) of generating capacity from 2001-2006 at an estimated cost of about $1.3
billion.
Site MW
---- ------
West Phoenix 4 120
West Phoenix 5 530
Redhawk 1 530
Redhawk 2 530
Redhawk 3 530
Redhawk 4 530
------
TOTAL 2,770
======
As discussed in greater detail below, Pinnacle West Energy has also
announced plans to purchase Nevada Power Company's (NPC) Harry Allen Power
Station and SCE's interest in the Palo Verde Nuclear Generating Station (Palo
Verde).
Pinnacle West Energy is also considering additional expansion, which may
result in additional expenditures.
Pinnacle West Energy expects to fund its capital requirements through
internally generated cash, debt issued directly by Pinnacle West Energy, and
capital infusions from the parent company's internally generated cash and
external financing.
Pinnacle West Energy is currently planning a 650 MW expansion of the West
Phoenix Power Plant and the construction of a natural gas-fired electric
generating station of up to four, 530 MW units, near the Palo Verde, called
Redhawk. Construction on the 120 MW West Phoenix Unit 4 began in June 2000, with
commercial operation of the unit expected in the summer of 2001. Pinnacle West
Energy expects construction to begin on the 530 MW West Phoenix Unit 5 in the
fall of 2001, with commercial operation beginning in mid-2003. Construction
began on the first two units of Redhawk in December 2000, and commercial
operation is currently scheduled for the summer of 2002.
Pinnacle West Energy has entered into an agreement with NPC to purchase
NPC's 72 MW gas-fired Harry Allen Power Station about 30 miles northeast of Las
Vegas, Nevada, for a net purchase price, after adjustments for purchased power
commitments, of approximately $65.2 million. The purchase is subject to filing
with and/or approval of various regulatory agencies, including the Federal
Energy Regulatory Commission (FERC) and the Nevada Public Utility Commission
(NPUC). The filing with the NPUC was made in February 2001. NPC will have the
right, but not the obligation, to purchase the output from the Harry Allen plant
at market rates, subject to a floor and a cap. As demand grows in the region
during the next five years, Pinnacle West Energy expects to add a 480 MW
gas-fired, combined cycle unit to the site. The Governor of Nevada recently
requested that the NPUC reexamine NPC's divestiture of generation assets. The
timing and result of any action by the NPUC is not yet known.
37
On April 27, 2000, Pinnacle West Energy entered into two separate
agreements with SCE to purchase SCE's 15.8% ownership interest in Palo Verde and
its 48% ownership interest in the Four Corners Power Plant. Consistent with the
agreements, on January 5, 2001, Pinnacle West Energy informed SCE that it would
not match a competing bid that SCE received for its Four Corners ownership
interest. Therefore, Pinnacle West Energy will not purchase SCE's Four Corners
interest under the April 2000 agreement unless the Palo Verde transaction
closes, the competing Four Corners transaction does not close, and Pinnacle West
Energy acquires the Four Corners interest at the original $300 million purchase
price as a standby purchaser. SCE did not receive any qualified competing bids
for its Palo Verde ownership interest, which Pinnacle West Energy agreed to
purchase for $250 million. However, recently-enacted California legislation
provides that "no facility for the generation of electricity owned by a public
utility may be disposed of prior to January 1, 2006." Unless this California law
is amended, Pinnacle West Energy would not be able to acquire SCE's Palo Verde
ownership interest pursuant to the original April 2000 agreement.
OTHER SUBSIDIARIES
During the past three years, SunCor and El Dorado each funded all of their
cash requirements with cash from operations and, in the case of SunCor, its own
external financings. APS Energy Services funded its cash requirements with cash
infusions from the parent company.
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 2000 and projected
capital expenditures for the next three years. SunCor expects to fund its
capital requirements from internally generated cash and external financings.
As of December 31, 2000, SunCor had a $120 million line of credit, under
which $110 million of borrowings were outstanding. SunCor's debt repayment
obligations for the next three years are approximately: zero in 2001; $37
million in 2002; and $74 million in 2003.
El Dorado does not have any capital requirements over the next three years.
El Dorado intends to focus on the realization of the value of its existing
investments. El Dorado's future investments are expected to be limited to
opportunities related to the energy sector.
APS Energy Services' capital expenditures and other cash requirements will
be funded from cash invested by the parent company.
ACCOUNTING MATTERS
We adopted a new standard on accounting for derivatives in 2001. As a
result, in January 2001 we recognized a $3 million after-tax loss in net income
as a cumulative effect of a change in accounting principles, and a $64 million
after-tax gain in equity (as a component of other comprehensive income). The
gain resulted from unrealized gains on cash flow hedges. There are still several
unresolved issues related to the application of certain provisions of this new
standard as it relates to the electric utility industry. The ultimate resolution
of these issues by the Financial Accounting Standards Board (FASB) could result
in a material impact to our financial statements and increased volatility in
future net income and comprehensive income. See Note 2 for further information.
Also, see Note 2 for a description of a proposed standard on accounting for
certain liabilities related to closure or removal of long-lived assets.
38
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 our 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 income
statement. See Note 1 for additional information on regulatory accounting and
Note 3 for additional information on the 1999 Settlement Agreement.
BUSINESS OUTLOOK
This section describes several major factors affecting our financial
outlook.
COMPETITION AND INDUSTRY RESTRUCTURING
ELECTRIC COMPETITION (WHOLESALE)
The National Energy Policy Act of 1992 (1992 Energy Act) and the FERC's
subsequent rulemaking activities have established the regulatory framework to
open the wholesale electricity market to competition. The 1992 Energy Act
amended provisions of the Public Utility Holding Company Act of 1935 and the
Federal Power Act to remove certain barriers to a competitive wholesale market.
The 1992 Energy Act permits utilities to participate in the development of
independent electric generating plants for electricity sales to wholesale
customers, and also permits the FERC to order transmission access for third
parties to transmission facilities owned by another entity. The 1992 Energy Act
does not, however, permit the FERC to issue an order requiring transmission
access to retail customers. Open-access transmission for wholesale customers as
defined by the FERC's final rules provides energy suppliers, including us, with
opportunities to sell and deliver electricity at market-based prices.
ELECTRIC COMPETITION (RETAIL)
On September 21, 1999, the ACC voted to approve the rules that provide a
framework for the introduction of retail electric competition in Arizona (the
Rules). Among other things, the Rules require most utilities, including APS, to
transfer all competitive generation assets and services either to an
unaffiliated party or to a separate corporate affiliate. The Rules require the
transfer to take place by January 1, 2001, absent a waiver. APS received a
waiver in the 1999 Settlement Agreement to allow the transfer of its competitive
generation assets and services to affiliates no later than December 31, 2002.
Accordingly, we plan 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 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 customers under rates that have been approved by the ACC.
These rates are fixed 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
39
market vary and, during the course of the last year, have been volatile. At
various times prices in the spot wholesale market have significantly exceeded
the amount included in APS' current retail rates. APS expects these market
conditions to continue in 2001. We believe we have adequately supplemented our
current generation portfolio with power purchased through contracts and hedging
techniques that limit exposure to the volatile spot wholesale power market.
However, 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.
As discussed in Note 3 of Notes to Consolidated Financial Statements in
Item 8, the 1999 Settlement Agreement authorizes APS to transfer its competitive
generation assets and services to one or more corporate affiliates no later than
December 31, 2002. APS intends to move its generation assets to Pinnacle West
Energy within that timeframe. Following its receipt of these generation assets,
Pinnacle West Energy expects to sell its power at wholesale to our power
marketing division (Power Marketing). Power Marketing, in turn, is expected to
sell power to APS and to non-affiliated power purchasers. APS is expected to
meet fifty percent of its energy needs under a power purchase agreement with
Power Marketing. As required by the Rules, APS will acquire the remaining fifty
percent of its energy needs through a competitive bid process in which Power
Marketing may participate. We believe that these arrangements will allow us to
manage APS' exposure to the wholesale power market during the period within
which APS' rates are fixed, as discussed in the preceding paragraph.
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. Several rural electric
cooperatives and the Arizona Consumers Council, a private non-profit public
interest group (represented by the Arizona Center for Law in the Public
Interest, also a private non-profit public interest organization) have filed
court challenges to the Rules. Although these actions do not directly challenge
the divestiture provisions of the Rules, they do raise fundamental
constitutional issues concerning the ability of the ACC to permit the forces of
competition to determine retail electric prices.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, 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 Court of Appeals, as a result of which the ruling is automatically
stayed pending further judicial review.
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 APS 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. A decision is still pending on the other
appeal, which raises a number of different issues.
40
Neither party challenging the 1999 Settlement Agreement has raised issues
regarding the 1999 Settlement Agreement that could not be remedied by the ACC if
the Arizona Court of Appeals remands the 1999 Settlement Agreement to the ACC.
However, it is impossible to predict with certainty exactly what the ACC would
do in the event the order approving the 1999 Settlement Agreement were
invalidated, either in whole or in part. Even aside from the pending litigation,
the ACC retains continuing jurisdiction over all orders issued by it and can
attempt to "rescind, alter or amend" such order under appropriate circumstances
and upon notice and hearing.
In May 1998, a law was enacted by the Arizona legislature to facilitate
implementation of retail electric competition in the state. Additionally,
legislation related to electric competition has been proposed in the United
States Congress. See Note 3 for additional information about the Rules, the 1999
Settlement Agreement, the ongoing litigation related to each, and for
legislative developments.
As a result of the foregoing matters, as well as energy market
developments, particularly in California (see "California Energy Market Issues"
below), electric utility restructuring is in a state of flux in the western
United States and around the country.
GENERATION EXPANSION
See "Capital Needs and Resources -- Capital Resources and Cash Requirements
- Pinnacle West Energy" and Note 12 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
SCE and PG&E Corp. (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 California Power Exchange (PX) and
California Independent System Operator (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; APS Energy Services' retail transactions
involving SCE and PG&E; and power marketing exposures. Based upon the financial
transactions to date, we do not believe the foregoing matters will have a
material adverse effect on our financial position or liquidity. 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.
See "Capital Resources and Cash Requirements - Pinnacle West Energy" above
for a discussion of Pinnacle West Energy's agreement to purchase SCE's Palo
Verde interest.
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.
41
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 3.8% a year for
the three years 1998 through 2000; we currently expect customer growth to
average 3.5% to 4% a year for 2001 through 2003. We currently estimate that
retail electricity sales in kilowatt-hours will grow 3.5% to 4.5% a year in 2001
through 2003, 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.
Wholesale activities will be affected by electricity prices and costs of
available fuel and purchased power in the western United States, as well as
competitive market conditions and regulatory and legislative changes in various
state and federal jurisdictions. These factors have significantly affected our
wholesale power activities and their resultant earnings contributions over the
last several years. We cannot predict future contributions from wholesale
activities.
Competitive sales of energy and energy-related products and services are
made by APS Energy Services in western states that have opened to competitive
supply. Such activities are currently not material to our consolidated financial
results.
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Fuel and purchased power costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, and our hedging program for
managing such costs.
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, inflation, 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. 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.
42
The annual earnings contribution from our real estate subsidiary, SunCor,
is expected to remain modest over the next several years. SunCor's earnings were
$5 million (excluding the effects of a $40 million deferred tax asset transfer)
in 1998, $6 million in 1999, and $11 million in 2000.
El Dorado, our investment subsidiary, is affected by market conditions
related to its investments. See Note 1 for a discussion of recent events
affecting El Dorado's financial results and its outlook. Historical results are
not necessarily indicative of future performance for El Dorado. El Dorado's
strategies focus on realization of the value of its existing investments. Any
future investments are expected to be in the energy business.
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.
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.
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 13). 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, 2000 and December 31, 1999. The interest rates
presented in the tables below represent the weighted average interest rates for
the years ended December 31, 2000 and December 31, 1999.
43
Expected Maturity/Principal Repayment
December 31, 2000
(dollars in thousands)
[Enlarge/Download Table]
Short-Term Variable Long-Term Fixed Long-Term
---------------------- ------------------------ ------------------------
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
======== =========== ===========
Expected Maturity/Principal Repayment
December 31, 1999
(dollars in thousands)
[Enlarge/Download Table]
Short-Term Variable Long-Term Fixed Long-Term
---------------------- ------------------------ ------------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
----- ------ ----- ------ ----- ------
2000 5.33% $ 38,300 10.25% $ 87 5.79% $ 114,711
2001 -- -- 7.00% 336,117 6.70% 27,488
2002 -- -- 8.47% 64,085 8.13% 125,000
2003 -- -- 5.51% 50,118 6.87% 25,000
2004 -- -- 10.25% 130 6.17% 205,000
Years thereafter -- -- 3.19% 479,727 7.87% 900,483
-------- --------- -----------
Total $ 38,300 $ 930,264 $ 1,397,682
======== ========= ===========
Fair value $ 38,300 $ 930,264 $ 1,366,968
======== ========= ===========
COMMODITY PRICE RISK
Pinnacle West's Energy Risk Management Committee (the ERMC) has established
risk management guidelines to monitor and manage commodity price risks. The ERMC
is chaired by Pinnacle West's Vice President of Finance and is comprised of
senior executives.
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/credits. In addition, subject to specified risk parameters
established by the Board of Directors and monitored by the ERMC, we
44
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 activites," such
trading positions are marked to market. These trading activities are part of our
wholesale activities and are reflected in the wholesale revenues and expenses.
As of December 31, 2000, a hypothetical adverse price movement of 10% in
the market price of our commodity derivative portfolio would have decreased the
fair market value of these contracts by approximately $29 million, compared to a
$6 million decrease that would have been realized as of December 31, 1999. The
increase in this exposure over 1999 is a result of the increased volume of
hedged positions and increased prices in this portfolio. This analysis does not
include the favorable impact this same hypothetical price move would have had on
certain underlying physical exposures being hedged with the commodity derivative
portfolio.
We are exposed to losses in the event of non-performance or non-payment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of counterparties. Despite the fact that the great majority
of trading counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could
default, resulting in a material impact on earnings for a given period.
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; the outcome of the regulatory
proceedings relating to the restructuring; regional economic and market
conditions, including the California energy situation, 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; 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 stock market
(particularly the technology sector in which El Dorado is currently invested)
and 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.
45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
Report of Management........................................................ 47
Independent Auditors' Report................................................ 48
Consolidated Statements of Income for 2000, 1999 and 1998................... 49
Consolidated Balance Sheets as of December 31, 2000 and 1999................ 50
Consolidated Statements of Cash Flows for 2000, 1999 and 1998............... 52
Consolidated Statements of Retained Earnings for 2000, 1999 and 1998........ 53
Notes to Consolidated Financial Statements.................................. 54
Financial Statement Schedule for 2000, 1999 and 1998
Schedule II - Valuation and Qualifying Accounts for 2000,
1999 and 1998............................................................. 85
See Note 14 of Notes to Consolidated Financial Statements for the selected
quarterly financial data required to be presented in this Item.
46
REPORT OF MANAGEMENT
The primary 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 and our independent auditors to test for compliance. 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 21, 2001, 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
47
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, 2000 and 1999, and
the related consolidated statements of income, retained earnings, and cash
flows for each of the three years in the period ended December 31, 2000. Our
audits also included the financial statement schedule listed in the Index at
Item 14. These financial statements and financial statement schedule are the
responsibility of the Corporation's management. Our responsibility is to express
an opinion on the financial statements and 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, 2000 and 1999, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2000 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.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 9, 2001
48
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands, except per share amounts)
[Enlarge/Download Table]
Year Ended December 31,
---------------------------------------------------
2000 1999 1998
----------- ----------- -----------
OPERATING REVENUES
Electric $ 3,531,810 $ 2,293,184 $ 2,006,398
Real estate 158,365 130,169 124,188
----------- ----------- -----------
Total 3,690,175 2,423,353 2,130,586
----------- ----------- -----------
OPERATING EXPENSES
Fuel and purchased power 1,934,783 796,109 545,297
Operations and maintenance 450,809 446,777 419,433
Real estate operations 134,422 119,516 115,331
Depreciation and amortization (Note 1) 394,410 385,568 379,679
Taxes other than income taxes 99,780 96,606 103,718
----------- ----------- -----------
Total 3,014,204 1,844,576 1,563,458
----------- ----------- -----------
OPERATING INCOME 675,971 578,777 567,128
----------- ----------- -----------
OTHER INCOME (EXPENSE)
Preferred stock dividend requirements
of APS -- (1,016) (9,703)
Net other income and expense (186) 10,793 609
----------- ----------- -----------
Total (186) 9,777 (9,094)
----------- ----------- -----------
INCOME BEFORE INTEREST AND INCOME TAXES 675,785 588,554 558,034
----------- ----------- -----------
INTEREST EXPENSE
Interest charges 171,239 162,381 169,145
Capitalized interest (21,638) (11,664) (18,596)
----------- ----------- -----------
Total 149,601 150,717 150,549
----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES 526,184 437,837 407,485
INCOME TAXES (NOTE 4) 223,852 168,065 164,593
----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS 302,332 269,772 242,892
Income tax benefit from
discontinued operations -- 38,000 --
Extraordinary charge - net of income
taxes of $94,115 -- (139,885) --
----------- ----------- -----------
NET INCOME $ 302,332 $ 167,887 $ 242,892
=========== =========== ===========
AVERAGE COMMON SHARES
OUTSTANDING - BASIC 84,733 84,717 84,774
AVERAGE COMMON SHARES
OUTSTANDING - DILUTED 84,935 85,009 85,346
EARNINGS PER AVERAGE COMMON
SHARE OUTSTANDING (NOTE 16)
Continuing operations - basic $ 3.57 $ 3.18 $ 2.87
Net income - basic 3.57 1.98 2.87
Continuing operations - diluted 3.56 3.17 2.85
Net income - diluted 3.56 1.97 2.85
DIVIDENDS DECLARED PER SHARE $ 1.425 $ 1.325 $ 1.225
=========== =========== ===========
See Notes to Consolidated Financial Statements.
49
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
-----------------------
2000 1999
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 10,363 $ 20,705
Customer and other receivables - net 513,822 244,599
Accrued utility revenues 74,566 72,919
Materials and supplies (at average cost) 71,966 69,977
Fossil fuel (at average cost) 19,405 21,869
Deferred income taxes (Note 4) 5,793 8,163
Other current assets 97,998 60,562
---------- ----------
Total current assets 793,913 498,794
---------- ----------
INVESTMENTS AND OTHER ASSETS
Real estate investments - net (Note 6) 371,323 344,293
Other assets (Note 13) 318,249 267,458
---------- ----------
Total investments and other assets 689,572 611,751
---------- ----------
UTILITY PLANT (NOTES 6, 10 AND 11)
Electric plant in service and held for future use 7,809,566 7,546,314
Less accumulated depreciation and amortization 3,188,302 3,026,194
---------- ----------
Total 4,621,264 4,520,120
Construction work in progress 464,540 209,281
Nuclear fuel, net of amortization of $61,256 and
$66,357 47,389 49,114
---------- ----------
Net utility plant 5,133,193 4,778,515
---------- ----------
DEFERRED DEBITS
Regulatory assets (Notes 3 and 4) 469,867 613,729
Other deferred debits 62,606 105,717
---------- ----------
Total deferred debits 532,473 719,446
---------- ----------
TOTAL ASSETS $7,149,151 $6,608,506
========== ==========
See Notes to Consolidated Financial Statements.
50
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
-----------------------
2000 1999
---------- ----------
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable $ 375,805 $ 186,524
Accrued taxes 89,246 70,510
Accrued interest 42,954 33,253
Short-term borrowings (Note 5) 82,775 38,300
Current maturities of long-term debt (Note 6) 463,469 114,798
Customer deposits 26,189 26,098
Other current liabilities 110,860 26,007
---------- ----------
Total current liabilities 1,191,298 495,490
---------- ----------
LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 6) 1,955,083 2,206,052
---------- ----------
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4) 1,143,040 1,183,855
Unamortized gain - (Note 10) 68,636 73,212
Other 408,380 444,164
---------- ----------
Total deferred credits and other 1,620,056 1,701,231
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTES 3, 12 AND 13)
COMMON STOCK EQUITY (NOTE 8)
Common stock, no par value; authorized
150,000,000 shares; issued and outstanding
84,824,947 at end of 2000 and 1999 1,532,831 1,537,449
Retained earnings 849,883 668,284
---------- ----------
Total common stock equity 2,382,714 2,205,733
---------- ----------
TOTAL LIABILITIES AND EQUITY $7,149,151 $6,608,506
========== ==========
See Notes to Consolidated Financial Statements.
51
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
[Enlarge/Download Table]
Year Ended December 31,
-----------------------------------------------
2000 1999 1998
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 302,332 $ 269,772 $ 242,892
Items not requiring cash
Depreciation and amortization 394,410 385,568 379,679
Nuclear fuel amortization 30,083 31,371 32,856
Deferred income taxes - net (8,973) (17,413) 41,262
Deferred investment tax credit 740 (23,514) (23,516)
Other - net 478 (12,476) 1,190
Changes in current assets and liabilities
Customer and other receivables - net (269,223) (10,723) (50,369)
Accrued utility revenues (1,647) (5,179) (9,181)
Materials, supplies and fossil fuel 475 (8,794) (2,797)
Other current assets (37,436) (12,968) (6,186)
Accounts payable 193,502 28,193 34,386
Accrued taxes 18,736 12,591 (22,090)
Accrued interest 9,701 1,387 (1,108)
Other current liabilities 89,714 15,047 (5,235)
(Increase) Decrease in land held (25,937) (12,542) 33,405
Other - net 2,605 (4,720) (39,350)
--------- --------- ---------
Net Cash Flow Provided By Operating
Activities 699,560 635,600 605,838
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (658,608) (343,448) (319,142)
Capitalized interest (21,638) (11,664) (18,596)
Other - net (41,761) (16,143) (2,144)
--------- --------- ---------
Net Cash Flow Used For Investing Activities (722,007) (371,255) (339,882)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 651,000 607,791 148,229
Short-term borrowings - net 44,475 (140,530) 48,080
Dividends paid on common stock (120,733) (112,311) (103,849)
Repayment of long-term debt (558,019) (510,693) (286,314)
Redemption of preferred stock -- (96,499) (75,517)
Other - net (4,618) (11,936) (3,531)
--------- --------- ---------
Net Cash Flow Provided by (Used for) Financing
Activities 12,105 (264,178) (272,902)
--------- --------- ---------
NET CASH FLOW (10,342) 167 (6,946)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 20,705 20,538 27,484
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT
END OF YEAR $ 10,363 $ 20,705 $ 20,538
========= ========= =========
See Notes to Consolidated Financial Statements.
52
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(dollars in thousands)
Year Ended December 31,
-----------------------------------
2000 1999 1998
--------- --------- ---------
Retained earnings at beginning of year $ 668,284 $ 612,708 $ 473,665
Net income 302,332 167,887 242,892
Common stock dividends (120,733) (112,311) (103,849)
--------- --------- ---------
Retained earnings at end of year $ 849,883 $ 668,284 $ 612,708
========= ========= =========
See Notes to Consolidated Financial Statements.
53
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION AND NATURE OF OPERATIONS
The consolidated financial statements include the accounts of Pinnacle West
and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor,
and El Dorado. Significant intercompany accounts and transactions between the
consolidated companies have been eliminated.
APS, our major subsidiary and Arizona's largest electric utility, provides
retail and wholesale electric service to the entire state with the exception of
Tucson and about one-half of the Phoenix area. APS also generates and, directly
or through our power marketing division, sells and delivers electricity to
wholesale customers in the western United States. Pinnacle West Energy, which
was formed in 1999, is the subsidiary through which we intend to conduct our
unregulated generation operations. APS Energy Services was formed in 1998 and
sells energy and energy-related products and services in competitive retail
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 primarily a venture capital and investment firm.
ACCOUNTING RECORDS
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 the use of
estimates by management. Actual results could differ from those estimates.
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 our 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 pre-tax ($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
54
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
The regulatory assets to be recovered under the 1999 Settlement Agreement
are now 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
The majority of our remaining regulatory assets relate to deferred income
taxes (see Note 4) and rate synchronization cost deferrals (see "Rate
Synchronization Cost Deferrals" in this Note).
The balance sheets include the amounts listed below for generation assets
not subject to SFAS No. 71 (for additional generation information see Note 18):
(dollars in thousands)
[Download Table]
December 31, December 31,
2000 1999
------------ ------------
Electric plant in service and held for future use ..... $ 3,856,600 $ 3,817,919
Accumulated depreciation and amortization.............. (1,693,079) (1,664,782)
Construction work in progress.......................... 304,992 87,819
Nuclear fuel, net of amortization...................... 47,389 49,114
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 proposed accounting
standard that impacts accounting for removal costs.
We record depreciation on utility property on a straight-line basis. For
the years 1998 through 2000 the rates, as prescribed by our regulators, ranged
from a low of 3.33% to a high of 20%. The weighted-average rate was 3.40% for
2000, 3.34% for 1999, and 3.32% for 1998. We depreciate non-utility property and
equipment over the estimated useful lives of the related assets, ranging from 3
to 30 years.
55
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EL DORADO INVESTMENTS
Net other income consists primarily of El Dorado's share in the earnings of
a venture capital partnership. The partnership adjusts the value of its
investments at the end of each fiscal quarter. The value of El Dorado's
investment in the partnership is determined by various factors beyond our
control, including equity market conditions. Most of the partnership's
investments are in technology-related companies whose share prices are highly
volatile.
Prior to June 2000, we recorded our share of the earnings from the
partnership, as the partnership adjusted the value of its investment, on a
one-quarter lag. This procedure was followed due to time constraints in
obtaining and analyzing such results for inclusion in our consolidated financial
statements on a current basis. In the second quarter of 2000, we requested a
distribution of our share of the investments held by the partnership, and we
adjusted our investment to reflect the current market value.
An amendment to the partnership agreement resulted in El Dorado receiving a
distribution, subject to certain sale restrictions, of securities representing
substantially all of El Dorado's investment in the partnership. We began
accounting for the securities as available for sale with changes in fair value
recorded in other comprehensive income. Gains and losses from the ultimate sale
of such securities will be reflected in our net earnings.
The book value of El Dorado's investment in the partnership was
approximately $7 million at December 31, 2000 and $21 million at December 31,
1999.
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 6.62% for 2000, 6.65% for 1999, and 6.88% for 1998.
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.
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 on the Statements of Income.
56
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 12 for information about spent nuclear fuel
disposal and Note 13 for information on nuclear decommissioning costs.
INCOME TAXES
We file our federal income tax return on a consolidated basis and we file
our state income tax returns on a consolidated or unitary basis. In accordance
with our intercompany tax sharing agreement, federal and state income taxes are
allocated to each subsidiary as though each 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. The accelerated portion of the regulatory asset amortization is
included in depreciation and amortization expense in the Statements of Income.
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/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.
Gains and losses related to derivatives that qualify as 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 closes (deferral method).
Net gains and losses on derivatives utilized for trading are recognized in
wholesale revenues on a current basis (the mark to market method). Trading
positions are measured at fair value as of the balance sheet date. The net gain
was $9 million for 2000 and $1 million for 1999.
57
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
STATEMENTS OF CASH FLOWS
We consider temporary cash investments and marketable securities, with
original maturities of less than 90 days, to be cash equivalents for purposes of
reporting cash flows. During 2000, 1999, and 1998, we paid interest, net of
amounts capitalized, income taxes, and dividends on preferred stock of APS as
follows:
(dollars in millions)
Years Ended December 31,
------------------------
2000 1999 1998
---- ---- ----
Interest paid $132 $141 $144
Income taxes paid 219 200 165
Dividends paid on preferred stock of APS -- 1 10
2. ACCOUNTING MATTERS
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 sheet and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholder's 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, as defined by SFAS No. 133, 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 balance sheet
as of January 1, 2001. We recorded a $3 million after-tax loss in net income as
a cumulative effect of a change in accounting principles and a $64 million
after-tax gain in equity (as a component of other comprehensive income). The
gain resulted from unrealized gains on cash flow hedges.
In December 2000, the FASB's Derivatives Implementation Group (DIG)
discussed whether contracts in the electric industry that have some of the
characteristics of purchased and written options should qualify for the "normal
purchases and sales" scope exception. The DIG did not reach a conclusion on this
issue. We account for electricity contracts with characteristics of options as
normal purchases and sales if it is probable that the contract will not be
settled in cash and will result in the physical delivery of electricity. The DIG
also discussed but did not determine whether electricity contracts subject to
"bookout" should qualify for the normal exception. A bookout occurs when one
party appears more than once in a contract path for the sale and purchase of
energy. In that instance, the counterparties may agree that they will not
schedule or deliver physical energy that originates and ends with the same
counterparty, but rather will settle in cash the amounts due to or from each
counterparty. We account for our non-trading electricity transactions that
bookout as gross settlement with physical delivery (and eligible for the normal
scope exception) if title transfers, gross cash payment is made, and the
transaction retains both performance and credit risk. Trading contracts are
measured at fair value (mark to market) as discussed in Note 1.
58
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our accounting is reflective of the non-storability of our product and the
lack of predictability of the demand for electricity at any point in time. If
the FASB or DIG ultimately provides us with contrary guidance, we may be
required to mark our non-trading electricity contracts to their fair market
values each reporting period, which could have a material impact on our
financial statements and add significant net income and comprehensive income
volatility that would not be reflective of the nature of our business. If these
agreements are required to be treated as derivative instruments, a cumulative
effect of a change in accounting principles would be applied in the quarter
following final resolution of the issues.
In 1999 we adopted 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 the
gains and losses included in earnings and separately disclosed in the financial
statements or footnotes. The effects of adopting EITF 98-10 were not material to
our 1999 financial statements.
In February 1996, the FASB issued an exposure draft, "Accounting for
Certain Liabilities Related to Closure or Removal of Long-Lived Assets." This
proposed standard would require 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. The FASB issued a revised exposure draft in February
2000 and we are evaluating the impacts.
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE
1999 SETTLEMENT AGREEMENT. On May 14, 1999, APS entered into a
comprehensive 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 APS 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. A decision is still pending on the other appeal, which raises a
number of different issues.
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
electric 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 reduction authorized
in the 1999 Settlement Agreement, there was a retail price decrease of
approximately $28 million ($17 million after taxes), or 1.5%,
effective July 1, 2000. For
59
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 current
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.
* 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 (CTC) that will remain in effect through
December 31, 2004, at which time it will terminate. Any
over/under-recovery due to sales volume variances will be
credited/debited against the costs subject to recovery under the
adjustment clause described above.
* APS will form a separate corporate affiliate or affiliates and
transfer to such affiliate(s) its generating assets and competitive
services at book value as of the date of transfer, which transfer
shall take place 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. 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.
60
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* When the 1999 Settlement Agreement approved by the ACC is no longer
subject to judicial review, APS will move to dismiss all of its
litigation pending against the ACC as of the date APS entered into the
1999 Settlement Agreement. To protect its rights, APS has several
lawsuits pending on ACC orders relating to stranded cost recovery and
the adoption and amendment of the ACC's electric competition rules,
which would be voluntarily dismissed at the appropriate time under
this provision.
As discussed in Note 1 above, we have discontinued the application of SFAS
No. 71 for our generation operations.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve the 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 is pending, along with several other lawsuits on ACC orders
relating to stranded cost recovery, the adoption or amendment of the Rules, and
the certification of competitive electric service providers.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, 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 Court of Appeals, as a result of which the ruling is automatically
stayed pending further judicial review. 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 was available to all APS
retail customers.
* Electric service providers that get Certificates of Convenience and
Necessity from the ACC can supply only competitive services, including
electric generation, but not electric transmission and distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
non-competitive 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
generation assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the 1999 Settlement Agreement,
61
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS received a waiver to allow transfer of its generation and other
competitive assets and services to affiliates no later than December
31, 2002. See "1999 Settlement Agreement" above for a discussion of
the planned timing of the transfer.
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):
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
APS cannot accurately predict the impact of full retail competition on its
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, APS will continue to
evaluate strategies and alternatives that will position it to compete in the new
regulatory environment.
62
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FEDERAL
The 1992 Energy Act and recent rulemakings by FERC have promoted increased
competition in the wholesale energy markets. APS does not expect these rules to
have a material impact on its financial statements.
Several electric utility industry restructuring bills will undoubtedly be
introduced during the current congressional session. Several of these bills are
written to allow consumers to choose their electricity suppliers beginning in
2001 and beyond. These bills and other bills are expected to be introduced, and
ongoing discussions at the federal level suggest a wide range of opinion that
will need to be narrowed before any comprehensive restructuring of the electric
utility industry can occur.
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
Sheet 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 this
accelerated amortization in depreciation and amortization expense on the
Statements of Income. The components of income tax expense for continuing
operations are:
(dollars in thousands)
Year Ended December 31,
-------------------------------------------
2000 1999 1998
--------- --------- ---------
Current
Federal $ 189,779 $ 171,491 $ 105,922
State 42,306 37,501 40,621
--------- --------- ---------
Total current 232,085 208,992 146,543
Deferred (8,973) (17,413) 41,566
ITC amortization 740 (23,514) (23,516)
--------- --------- ---------
Total expense $ 223,852 $ 168,065 $ 164,593
========= ========= =========
The following chart compares pretax income at the 35% federal income tax rate to
income tax expense:
63
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
Year Ended December 31,
---------------------------------
2000 1999 1998
--------- --------- ---------
Federal income tax expense at 35%
statutory rate $ 184,164 $ 153,243 $ 142,620
Increases (reductions) in tax expense
resulting from:
Tax under book depreciation 12,328 14,575 17,848
Preferred stock dividends of APS -- 356 3,396
ITC amortization 740 (23,514) (23,516)
State income tax net of federal income tax
benefit 23,555 23,030 22,764
Other 3,065 375 1,481
--------- --------- ---------
Income tax expense $ 223,852 $ 168,065 $ 164,593
========= ========= =========
The components of the net deferred income tax liability were as follows:
(dollars in thousands)
Year Ended December 31,
-----------------------
2000 1999
---------- ----------
DEFERRED TAX ASSETS
Deferred gain on Palo Verde Unit 2 sale/leaseback $ 27,056 $ 29,446
Other 89,416 133,748
---------- ----------
Total deferred tax assets 116,472 163,194
---------- ----------
DEFERRED TAX LIABILITIES
Plant-related 1,081,637 1,104,769
Regulatory asset for income taxes 172,082 234,117
---------- ----------
Total deferred tax liabilities 1,253,719 1,338,886
---------- ----------
Accumulated deferred income taxes - net $1,137,247 $1,175,692
========== ==========
INVESTMENT TAX CREDIT
Because of a 1994 rate settlement agreement, we accelerated amortization of
substantially all of our ITCs over a five-year period (1995-1999).
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.
64
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, 2000 and $350 million at December 31, 1999, which were available
either to support the issuance of commercial paper or to be used for bank
borrowings. The commitment fees at December 31, 2000 and 1999 for these lines of
credit ranged from 0.09% to 0.125% per annum. APS had no long-term bank
borrowings at December 31, 2000 and $50 million outstanding at December 31,
1999.
APS' commercial paper borrowings outstanding were $82 million at December
31, 2000 and $38 million at December 31, 1999. The weighted average interest
rate on commercial paper borrowings was 6.64% for the year ended December 31,
2000 and 5.33% for the year ended December 31, 1999. By Arizona statute, APS'
short-term borrowings cannot exceed 7% of its total capitalization unless
approved by the ACC.
Pinnacle West had a revolving line of credit of $250 million at December
31, 2000 and 1999. The commitment fees were 0.15% in 2000 and 0.10% in 1999.
Outstanding amounts at December 31, 2000 were $188 million and at December 31,
1999 were $56 million.
SunCor had revolving lines of credit totalling $120 million at December 31,
2000 and $100 million at December 31, 1999. The commitment fees were 0.125% in
2000 and 1999. SunCor had $110 million outstanding at December 31, 2000 and $94
million outstanding at December 31, 1999.
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; Pinnacle West's debt is
unsecured. The following table presents the components of consolidated long-term
debt outstanding at December 31, 2000 and December 31, 1999:
65
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
[Enlarge/Download Table]
December 31,
Maturity Interest -------------------
Dates (a) Rates 2000 1999
--------- ----- ---- ----
APS
First mortgage bonds 2000 5.75% $ -- $ 100,000
2002 8.125% 125,000 125,000
2004 6.625% 80,000 80,000
2020 10.25% -- 100,550
2021 9.5% 45,140 45,140
2021 9% 72,370 72,370
2023 7.25% 70,650 70,650
2024 8.75% 121,668 121,668
2025 8% 33,075 47,075
2028 5.5% 25,000 25,000
2028 5.875% 154,000 154,000
Unamortized discount and premium (5,993) (5,860)
Pollution control bonds 2024-2034 Adjustable
rate(b) 476,860 476,860
Funds held in trust account for
certain pollution control bonds -- (1,236)
Collateralized loan 2000 5.375%-6.125% -- 10,000
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 --
Floating rate notes 2001 Adjustable
rate(c) 250,000 250,000
Senior notes (d) 2006 6.75% 83,695 83,695
Debentures 2025 10% -- 75,000
Bank loans 2003 Adjustable
rate(e) -- 50,000
Capitalized lease obligation 2000 7.48%(f) -- 7,199
Capitalized lease obligation 2001-2003 7.75% 709 --
---------- ----------
2,057,174 2,112,111
---------- ----------
SUNCOR
Revolving credit 2002-2003 (g) 110,000 94,000
Notes payable 2001-2006 (h) 8,163 3,404
Bonds payable 2039 5.85% 5,215 5,335
---------- ----------
123,378 102,739
---------- ----------
PINNACLE WEST
Revolving credit 2001 (i) 188,000 56,000
Senior notes 2001-2003 (j) 50,000 50,000
---------- ----------
238,000 106,000
---------- ----------
Total long-term debt 2,418,552 2,320,850
Less current maturities 463,469 114,798
---------- ----------
Total long-term debt less current
maturities $1,955,083 $2,206,052
========== ==========
66
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, 2000 was 4.06%
and for December 31, 1999 was 3.15%. Changes in short-term interest rates
would affect the costs associated with this debt.
(c) The weighted-average rate for the year ended December 31, 2000 was 7.33%
and for December 31, 1999 was 6.8525%.
(d) 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.
(e) The weighted-average rate for the year ended December 31, 2000 was 6.53%
and for December 31, 1999 was 5.5%. Changes in short-term interest rates
would affect the costs associated with this debt. At December 31, 2000, we
had no long-term bank borrowings outstanding.
(f) Represents the present value of future lease payments (discounted at an
interest rate of 7.48%) on a combined cycle plant that was sold and leased
back. The capital lease was paid off early and the related asset was
purchased in December 2000 (See Note 10).
(g) The weighted-average rate at December 31, 2000 was 8.61% and at December
31, 1999 was 8.51%. Interest for 2000 and 1999 was based on LIBOR plus 2%
or prime plus 0.5%.
(h) Multiple notes primarily with variable interest rates based mostly on the
lenders' prime plus 1.75% and lenders' prime plus .25%.
(i) The weighted-average rate at December 31, 2000 was 7.51% and at December
31, 1999 was 6.825%. Interest for 2000 was based on LIBOR plus 0.75% and
interest for 1999 was based on LIBOR plus 0.33%.
(j) Includes two series of notes: $25 million at 6.62% due 2001, and $25
million at 6.87% due 2003.
The following is a list of principal payments due on total long-term debt
and sinking fund requirements through 2005:
* $463 million in 2001;
* $162 million in 2002;
* $99 million in 2003;
* $205 million in 2004; and
* $400 million in 2005.
First mortgage bondholders share a lien on substantially all utility plant
assets (other than nuclear fuel and transportation equipment). The mortgage bond
indenture restricts the payment of common stock dividends under certain
conditions. These conditions did not exist at December 31, 2000.
67
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. PREFERRED STOCK OF APS
On March 1, 1999, APS redeemed all of its preferred stock. Preferred stock
balances of APS at December 31, 2000 and 1999 were zero. Redeemable preferred
stock transactions of APS during each of the three years in the period ended
December 31, 2000 are as follows:
(dollars in thousands)
Number of Par Value
Shares Amount
------- -------
Balance, December 31, 1997 291,098 $ 29,110
Retirements
$10.00 Series U (197,087) (19,709)
-------- --------
Balance, December 31, 1998 94,011 9,401
Retirements
$10.00 Series U (94,011) (9,401)
-------- --------
Balance, December 31, 1999 -- --
-------- --------
Balance, December 31, 2000 -- $ --
======== ========
8. COMMON STOCK
Our common stock issued during each of the three years in the period ended
December 31, 2000 is as follows:
(dollars in thousands)
Number of
Shares Amount
----------- -----------
Balance, December 31, 1997 84,824,947 $ 1,553,771
Common stock expense -- (3,128)(a)
----------- -----------
Balance, December 31, 1998 84,824,947 1,550,643
Common stock expense -- (13,194)(a)
----------- -----------
Balance, December 31, 1999 84,824,947 1,537,449
Common stock expense -- (4,618)
----------- -----------
Balance, December 31, 2000 84,824,947 $ 1,532,831
=========== ===========
(a) Including premiums and expenses of preferred stock issues of APS.
68
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLANS
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 these plans 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, 2000 were mostly domestic and international
common stocks and bonds and real estate.
Pension expense, including administrative costs, was:
* $2 million in 2000;
* $4 million in 1999; and
* $11 million in 1998.
The following table shows the components of net pension cost before
consideration of amounts capitalized or billed to others:
(dollars in thousands)
[Download Table]
2000 1999 1998
-------- -------- --------
Service cost - benefits earned during the period $ 24,955 $ 24,982 $ 24,817
Interest cost on projected benefit obligation 58,361 52,905 51,524
Expected return on plan assets (77,231) (68,335) (54,513)
Amortization of:
Transition asset (3,227) (3,226) (3,226)
Prior service cost 2,078 2,078 2,078
Net actuarial gain (1,633) -- --
-------- -------- --------
Net periodic pension cost $ 3,303 $ 8,404 $ 20,680
======== ======== ========
The following table shows a reconciliation of the funded status of the
plans to the amounts recognized in the balance sheets:
69
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
2000 1999
--------- ---------
Funded status - pension plan assets more than
(less than) projected benefit obligation $ (20,730) $ 37,275
Unrecognized net transition asset (16,781) (20,008)
Unrecognized prior service cost 18,558 20,636
Unrecognized net actuarial gains (23,816) (101,153)
--------- ---------
Net pension liability recognized in the balance sheets $ (42,769) $ (63,250)
========= =========
The following table sets forth the defined benefit pension plans' change in
projected benefit obligation for the plan years 2000 and 1999:
(dollars in thousands)
[Download Table]
2000 1999
--------- ---------
Projected pension benefit obligation at beginning of year $ 742,638 $ 731,305
Service cost 24,955 24,982
Interest cost 58,361 52,905
Benefit payments (30,568) (29,694)
Actuarial (gains)/losses 540 (36,860)
--------- ---------
Projected pension benefit obligation at end of year $ 795,926 $ 742,638
========= =========
The following table sets forth the defined benefit pension plans' change in
the fair value of plan assets for the plan years 2000 and 1999:
(dollars in thousands)
2000 1999
--------- ---------
Fair value of pension plan assets at beginning of year $ 779,913 $ 690,271
Actual return on plan assets 1,851 93,977
Employer contributions 24,000 25,359
Benefit payments (30,568) (29,694)
--------- ---------
Fair value of pension plan assets at end of year $ 775,196 $ 779,913
========= =========
We made the assumptions below to calculate the pension liability:
2000 1999
---- ----
Discount rate 7.75% 7.75%
Rate of increase in compensation levels 4.25% 4.25%
Expected long-term rate of return on assets 10.00% 10.00%
70
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 to participant accounts. We
recorded expenses for this plan of approximately $4 million for 2000, 1999, and
1998.
POSTRETIREMENT PLANS
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 was:
* $ 3 million for 2000;
* $ 7 million for 1999; and
* $ 9 million for 1998.
The following table shows the components of net periodic postretirement
benefit costs before consideration of amounts capitalized or billed to others:
(dollars in thousands)
[Download Table]
2000 1999 1998
-------- -------- --------
Service cost - benefits earned during the period $ 8,613 $ 8,939 $ 7,890
Interest cost on accumulated benefit obligation 19,315 17,366 15,763
Expected return on plan assets (22,381) (18,454) (12,001)
Amortization of:
Transition obligation 7,698 7,698 7,698
Net actuarial gains (7,983) (5,117) (2,952)
-------- -------- --------
Net periodic postretirement benefit cost $ 5,262 $ 10,432 $ 16,398
======== ======== ========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the balance sheets:
71
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
2000 1999
--------- ---------
Funded status - postretirement plan assets more than
(less than) projected benefit obligation $ (14,851) $ 25,549
Unrecognized net obligation at transition 92,446 100,145
Unrecognized net actuarial gains (81,280) (128,309)
--------- ---------
Net postretirement amount recognized in the balance
sheets $ (3,685) $ (2,615)
========= =========
The following table sets forth the postretirement benefit plans' change in
accumulated benefit obligation for the plan years 2000 and 1999:
(dollars in thousands)
2000 1999
--------- ---------
Accumulated postretirement benefit obligation at
beginning of year $ 231,989 $ 237,679
Service cost 8,613 8,939
Interest cost 19,315 17,366
Benefit payments (8,905) (8,761)
Actuarial (gains) losses 12,994 (23,234)
--------- ---------
Accumulated postretirement benefit obligation at
end of year $ 264,006 $ 231,989
========= =========
The following table sets forth the postretirement benefit plans' change in
the fair value of plan assets for the plan years 2000 and 1999:
(dollars in thousands)
2000 1999
--------- ---------
Fair value of postretirement plan assets at
beginning of year $ 257,538 $ 213,410
Actual return on plan assets (4,436) 42,975
Employer contributions 4,958 9,914
Benefit payments (8,906) (8,761)
--------- ---------
Fair value of postretirement plan assets at the
end of year $ 249,154 $ 257,538
========= =========
We made the assumptions below to calculate the postretirement liability:
2000 1999
---- ----
Discount rate 7.75% 7.75%
Expected long-term rate of return on assets - after tax 8.77% 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 6.00% 6.00%
Ultimate health care cost trend rate (reached in the
year 2002) 5.00% 5.00%
72
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 2000 cost of postretirement benefits
other than pensions $ 5 $ (4)
Effect on the accumulated postretirement benefit
obligation at December 31, 2000 43 (34)
10. 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.
The average amounts to be paid for the Palo Verde Unit 2 leases are
approximately $49 million per year for the years 2001-2015.
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). The accelerated amortization is
included in depreciation and amortization expense on the Statements of Income.
The balance of this regulatory asset at December 31, 2000 was $33 million.
In December 2000, APS purchased Units 1, 2, and 3 of West Phoenix Power
Plant. These units were previously reflected as a capital lease.
In addition, we lease certain land, buildings, equipment, and miscellaneous
other items through operating rental agreements with varying terms, provisions,
and expiration dates.
Total lease expense was $58 million in 2000, $52 million in 1999, and $55
million in 1998.
Estimated future minimum lease commitments, are approximately $67 million
for each of the years 2001 to 2005 and $663 million thereafter.
11. 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 at December 31, 2000. APS' share of operating and
maintaining these facilities is included in the income statement in operations
and maintenance expense.
73
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
[Enlarge/Download Table]
PERCENT CONSTRUCTION
OWNED BY PLANT IN ACCUMULATED WORK IN
COMPANY SERVICE DEPRECIATION PROGRESS
------- ------- ------------ --------
Generating Facilities: (dollars in thousands)
Palo Verde Nuclear Generating Station
Units 1 and 3 29.1% $1,824,480 $ 814,693 $ 7,414
Palo Verde Nuclear Generating Station
Unit 2 (see Note 10) 17.0% 571,573 265,571 29,593
Four Corners Steam Generating Station
Units 4 and 5 15.0% 152,717 75,797 --
Navajo Steam Generating Station
Units 1, 2, and 3 14.0% 231,509 99,623 4,899
Cholla Steam Generating Station
Common Facilities (a) 62.8%(b) 73,382 40,023 686
Transmission Facilities:
ANPP 500KV System 35.8%(b) 67,987 22,813 --
Navajo Southern System 31.4%(b) 27,290 17,804 55
Palo Verde-Yuma 500KV System 23.9%(b) 9,712 3,844 1
Four Corners Switchyards 27.5%(b) 3,071 1,925 --
Phoenix-Mead System 17.1%(b) 36,418 2,681 --
Palo Verde - Estrella 500KV System 50.0%(b) -- -- 610
(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for them. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
12. COMMITMENTS AND CONTINGENCIES
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.
POWER SERVICE AGREEMENT
APS is a party to a power service agreement with Citizens Communications
Company (Citizens) under which APS supplies Citizens with power. By letter dated
March 7, 2001, Citizens advised APS that it believes APS has overcharged
Citizens by over $50 million under the agreement since the summer of 2000. APS
believes that its charges to Citizens under the agreement are fully in
accordance with the terms of the agreement and APS will vigorously defend any
contrary claims raised by Citizens.
PALO VERDE NUCLEAR GENERATING STATION
Pursuant to the Nuclear Waste Policy Act of 1982 , the DOE must accept and
dispose of all spent nuclear fuel and other high-level radioactive wastes
generated by domestic power reactors. The United States Nuclear Regulatory
Commission (NRC) requires operators of nuclear power reactors to enter into
spent fuel disposal contracts with the DOE. Under the Nuclear Waste Policy Act
74
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of 1982, the DOE was to develop a permanent repository for the storage and
disposal of spent nuclear fuel by 1998. The DOE has announced that such a
permanent 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 precluding the DOE from
excusing its own delay, but refused to order the DOE to begin accepting spent
nuclear fuel. Based on this decision, a number of utilities filed damages
actions against DOE in the Court of Federal Claims. In decisions that became
final in December 2000, the United States Court of Appeals for the Federal
Circuit held that utilities do not have to exhaust the DOE administrative claims
before filing lawsuits for damages against the DOE in the Court of Federal
Claims.
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 $113 million (in 2000 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, 2000, APS had recorded
a liability and regulatory asset of $40 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.
75
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FUEL AND PURCHASED POWER COMMITMENTS
APS is a party to various fuel and purchased power contracts with terms
expiring from 2001 through 2021 that include required purchase provisions. APS
estimates its contract requirements to be approximately $277 million in 2001;
$145 million in 2002; $90 million in 2003; $83 million in 2004; and $55 million
in 2005. However, this amount may vary significantly pursuant to certain
provisions in such contracts that permit APS to decrease its required purchases
under certain circumstances.
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 $58 million at December 31, 2000 and is included in
deferred credits-other in the Balance Sheet.
A regulatory asset has been established for amounts not yet recovered from
ratepayers. 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. The balance of the regulatory asset at December 31, 2000
was about $32 million.
CALIFORNIA ENERGY MARKET ISSUES
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; APS Energy Services' retail transactions
involving SCE and PG&E; and power marketing exposures. Based upon the financial
transactions to date, we do not believe the foregoing matters will have a
material adverse effect on our financial position or liquidity. 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.
See "Generation Expansion" below for a discussion of Pinnacle West Energy's
agreement to purchase SCE's Palo Verde interest.
CONSTRUCTION PROGRAM
Consolidated capital expenditures in 2001 are estimated at:
CAPITAL EXPENDITURES
(dollars in millions)
2001
-------
APS $ 455
Pinnacle West Energy 659
SunCor 75
Other 21
-------
Total $ 1,210
=======
76
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
GENERATION EXPANSION
Pinnacle West Energy has announced plans to build and acquire up to 2,800
MW of generating capacity from 2001-2006 at an estimated cost of about $1.3
billion.
Pinnacle West Energy is also considering additional expansion over the next
several years, which may result in additional expenditures. Pinnacle West
Energy's expenditures are expected to be funded through internally generated
cash and debt issued directly by Pinnacle West Energy, as well as capital
infusions from Pinnacle West's internally generated cash and debt proceeds.
Pinnacle West Energy is currently planning a 650-megawatt expansion of the
West Phoenix Power Plant and the construction of a natural gas-fired electric
generating station of up to four, 530 MW units, near Palo Verde, called Redhawk.
Construction on the 120 MW West Phoenix Unit 4 began in June 2000, with
commercial operation of the unit expected in the summer of 2001. Pinnacle West
Energy expects construction to begin on the 530 MW Unit 5 in the fall of 2001,
with commercial operation beginning in mid-2003. Construction began on the first
two units of Redhawk in December 2000, and commercial operation is scheduled for
the summer of 2002.
Pinnacle West Energy has entered into an agreement with NPC to purchase
NPC's 72 MW gas-fired Harry Allen Power Station about 30 miles northeast of Las
Vegas, Nevada, for a net purchase price, after adjustments for purchased power
commitments, of approximately $65.2 million. The purchase is subject to filing
with and/or approval of various regulatory agencies, including FERC and the
NPUC. The filing with the NPUC was made in February 2001. NPC will have the
right, but not the obligation, to purchase the output from the Harry Allen plant
at market rates, subject to a floor and a cap. As demand grows in the region
during the next five years, Pinnacle West Energy expects to add a 480 MW
gas-fired, combined cycle unit to the site. The Governor of Nevada has recently
requested that the NPUC reexamine the divestiture of generation. The timing and
result of any action by the NPUC is not yet known.
On April 27, 2000, Pinnacle West Energy entered into two separate
agreements with SCE to purchase SCE's 15.8% ownership interest in Palo Verde and
its 48% ownership interest in the Four Corners Power Plant. Consistent with the
agreements, on January 5, 2001, Pinnacle West Energy informed SCE that it would
not match a competing bid that SCE received for its Four Corners ownership
interest. Therefore, Pinnacle West Energy will not purchase SCE's Four Corners
interest under the April 2000 agreement unless the Palo Verde transaction
closes, the competing Four Corners transaction does not close, and Pinnacle West
Energy acquires the Four Corners interest at the original $300 million purchase
price as a standby purchaser. SCE did not receive any qualified competing bids
for its Palo Verde ownership interest, which Pinnacle West Energy agreed to
purchase for $250 million. However, recently-enacted California legislation
provides that "no facility for the generation of electricity owned by a public
utility may be disposed of prior to January 1, 2006." Unless this California law
is amended, Pinnacle West Energy would not be able to acquire SCE's Palo Verde
ownership interest pursuant to the original April 2000 agreement.
13. NUCLEAR DECOMMISSIONING COSTS
APS recorded $11 million for nuclear decommissioning expense in each of the
years 2000, 1999, and 1998. APS estimates it will cost about $1.8 billion ($493
million in 2000 dollars) to decommission its share of the three Palo Verde
units. The decommissioning costs are expected to be
77
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 1998 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.
The trust accounts are reported in investments and other assets on the
Consolidated Balance Sheets at their market value of $205 million at December
31, 2000 and $176 million at December 31, 1999. 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.
See Note 2 for a proposed accounting standard on accounting for certain
liabilities related to closure or removal of long-lived assets.
14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Consolidated quarterly financial information for 2000 and 1999 is as
follows:
(dollars in thousands, except per share amounts)
2000
----------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Operating revenues
Electric $446,228 $720,174 $1,567,960 $797,448
Real estate 41,889 36,374 39,396 40,706
Operating income (a) $ 96,271 $201,153 $ 256,001 $122,546
Net income $ 54,070 $ 89,901 $ 116,049 $ 42,312
Earnings per 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
78
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share amounts)
1999
----------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Operating revenues
Electric $413,983 $511,434 $ 867,630 $500,137
Real estate 24,533 32,697 26,640 46,299
Operating income (a) $ 91,599 $148,968 $ 240,294 $ 97,916
Income from continuing
Operations $ 30,690 $ 68,702 $ 125,579 $ 44,801
Income tax benefit from
discontinued operations -- -- 38,000 --
Extraordinary charge - net of
income tax -- -- (139,885) --
-------- -------- ---------- --------
Net income $ 30,690 $ 68,702 $ 23,694 $ 44,801
======== ======== ========== ========
Earnings (loss) per average
common share outstanding
Continuing operations - basic $ 0.36 $ 0.81 $ 1.48 $ 0.53
Discontinued operations -
Basic -- -- 0.45 --
Extraordinary charge - basic -- -- (1.65) --
-------- -------- ---------- --------
Net Income - basic $ 0.36 $ 0.81 $ 0.28 $ 0.53
======== ======== ========== ========
Continuing operations - diluted $ 0.36 $ 0.81 $ 1.48 $ 0.53
Discontinued operations -
Diluted -- -- 0.45 --
Extraordinary charge - diluted -- -- (1.65) --
-------- -------- ---------- --------
Net Income - diluted $ 0.36 $ 0.81 $ 0.28 $ 0.53
======== ======== ========== ========
Dividends declared per share (b) $ 0.325 $ 0.65 $ -- $ 0.35
(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.
(b) Dividends for the quarter ending September 30, 1999 were declared in June
1999.
15. 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, 2000 and
1999 due to their short maturities.
We hold investments in debt and equity securities for purposes other than
trading. The December 31, 2000 and 1999 fair values of such investments, which
we determine by using quoted market values, approximate their carrying amount.
79
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. On December 31, 1999, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.31 billion, with an estimated
fair value of $2.29 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.
16. EARNINGS PER SHARE
The following table presents earnings per average common share outstanding
(EPS):
2000 1999 1998
----- ----- -----
Basic EPS:
Continuing operations $3.57 $3.18 $2.87
Discontinued operations -- 0.45 --
Extraordinary charge -- (1.65) --
----- ----- -----
Net income $3.57 $1.98 $2.87
===== ===== =====
Diluted EPS:
Continuing operations $3.56 $3.17 $2.85
Discontinued operations -- 0.45 --
Extraordinary charge -- (1.65) --
----- ----- -----
Net income $3.56 $1.97 $2.85
===== ===== =====
Dilutive stock options increased average common shares outstanding by
202,738 shares in 2000, 291,392 shares in 1999, and 571,728 shares in 1998.
Total average common shares outstanding for the purposes of calculating diluted
earnings per share were 84,935,282 shares in 2000, 85,008,527 shares in 1999,
and 85,345,946 shares in 1998.
Options to purchase 517,614 shares of common stock were outstanding at
December 31, 2000 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 506,734 at December 31, 1999 and
244,200 at December 31, 1998.
17. STOCK-BASED COMPENSATION
Pinnacle West offers two stock incentive plans for our and our
subsidiaries' officers and key employees.
The 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. 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.
80
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The awards outstanding under the incentive plans at December 31, 2000
approximate 1,569,171 non-qualified stock options, 193,992 shares of restricted
stock, and no incentive stock options, stock appreciation rights or dividend
equivalents.
The FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation"
which was effective beginning in 1996. The statement 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)
2000 1999 1998
----------- ----------- -----------
Net income
As reported $ 302,332 $ 167,887 $ 242,892
Pro forma (fair value method) $ 301,102 $ 166,913 $ 242,177
Earnings per share - basic
As reported $ 3.57 $ 1.98 $ 2.87
Pro forma (fair value method) $ 3.55 $ 1.97 $ 2.86
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:
2000 1999 1998
---- ---- ----
Risk-free interest rate 5.81% 5.68% 4.54%
Dividend yield 3.48% 3.33% 3.03%
Volatility 32.00% 20.50% 18.80%
Expected life (months) 60 60 60
The following table is a summary of the status of our stock option plans as
of December 31, 2000, 1999, and 1998 and changes during the years ending on
those dates:
81
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
[Enlarge/Download Table]
2000 Weighted 1999 Weighted 1998 Weighted
Average Average Average
2000 Exercise 1999 Exercise 1998 Exercise
Shares Price Shares Price Shares Price
--------- ------ --------- ------ --------- ------
Outstanding at
Beginning of year 1,441,124 $33.45 1,563,512 $27.95 1,554,631 $24.38
Granted 451,450 43.28 458,450 35.95 244,200 46.78
Exercised (283,819) 20.90 (516,838) 18.19 (217,317) 23.09
Forfeited (39,584) 39.86 (64,000) 40.36 (18,002) 33.42
--------- ---------- ----------
Outstanding at end
of year 1,569,171 37.55 1,441,124 33.45 1,563,512 27.95
--------- ---------- ----------
Options exercisable
at year-end 831,537 34.37 835,381 29.69 1,106,165 22.04
--------- ---------- ----------
Weighted average
fair value of
options granted
during the year 11.81 7.05 8.15
The following table summarizes information about our stock option plans at
December 31, 2000:
Weighted Average
Exercise Options Remaining Options
Prices Per Share Outstanding Contract Life (Years) Exercisable
---------------- ----------- --------------------- -----------
$10.06 7,000 .50 7,000
15.75 10,000 .90 10,000
17.68 4,900 1.10 4,900
18.13 14,000 1.50 14,000
19.00 58,618 3.90 58,618
19.56 15,000 1.90 15,000
22.13 33,250 3.00 33,250
23.25 14,000 2.50 14,000
27.16 20,000 9.20 5,000
27.44 84,918 4.90 84,918
31.44 87,335 5.90 87,335
34.66 327,113 8.90 118,124
36.56 5,000 8.80 2,083
39.75 170,636 7.00 170,636
41.00 70,000 8.10 44,722
44.03 431,450 9.90 11,985
46.78 215,951 7.90 149,966
--------- --------
$10.06-$46.78 1,569,171 831,537
========= ========
82
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and regulatory environment) which consist of the transmission and distribution
of electricity and wholesale activities (delivery business segment) and the
generation of electricity (generation business segment). The other amounts
include activity relating to the parent company and other subsidiaries including
APS Energy Services, SunCor and El Dorado. Eliminations primarily relate to
intersegment sales of electricity. Financial data for the business segments is
provided as follows:
Business Segments For Year Ended December 31, 2000
(dollars in thousands)
[Enlarge/Download Table]
Generation Delivery Other Eliminations Total
---------- -------- ----- ------------ -----
Operating revenues $ 990,415 $3,531,810 $ 158,365 $ (990,415) $3,690,175
Operating expense 600,389 2,871,329 138,677 (990,415) 2,619,980
---------- ---------- ---------- ---------- ----------
Operating margin 390,026 660,481 19,688 -- 1,070,195
Depreciation and
amortization 125,220 263,446 5,744 -- 394,410
Interest 41,808 96,081 11,712 -- 149,601
---------- ---------- ---------- ---------- ----------
Pretax margin 222,998 300,954 2,232 -- 526,184
Income taxes 87,828 134,692 1,332 -- 223,852
---------- ---------- ---------- ---------- ----------
Earnings for common stock $ 135,170 $ 166,262 $ 900 $ -- $ 302,332
========== ========== ========== ========== ==========
Total assets $2,606,046 $4,068,510 $ 474,595 $ -- $7,149,151
========== ========== ========== ========== ==========
Capital expenditures $ 379,761 $ 285,455 $ 49,949 $ -- $ 715,165
========== ========== ========== ========== ==========
Business Segments For Year Ended December 31, 1999
(dollars in thousands)
[Enlarge/Download Table]
Generation Delivery Other Eliminations Total
---------- -------- ----- ------------ -----
Operating revenues $ 853,755 $ 2,292,798 $ 130,555 $ (853,755) $ 2,423,353
Operating expense 522,925 1,672,169 106,876 (853,755) 1,448,215
----------- ----------- ----------- ----------- -----------
Operating margin 330,830 620,629 23,679 -- 975,138
Depreciation and
amortization 121,683 260,374 3,511 -- 385,568
Interest and preferred stock
dividend requirements
40,753 101,855 9,125 -- 151,733
----------- ----------- ----------- ----------- -----------
Pretax margin 168,394 258,400 11,043 -- 437,837
Income taxes 47,976 111,512 8,577 -- 168,065
Income tax benefit from
discontinued operations -
PNW
-- -- 38,000 -- 38,000
Extraordinary charge - net
of income tax of $94,115
-- (139,885) -- -- (139,885)
----------- ----------- ----------- ----------- -----------
Earnings for common stock $ 120,418 $ 7,003 $ 40,466 $ -- $ 167,887
=========== =========== =========== =========== ===========
Total assets $ 2,342,291 $ 3,795,846 $ 470,369 $ -- $ 6,608,506
=========== =========== =========== =========== ===========
Capital expenditures $ 110,798 $ 241,469 $ 126,581 $ -- $ 478,848
=========== =========== =========== =========== ===========
83
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Business Segments For Year Ended December 31, 1998
(dollars in thousands)
Generation Delivery Other Eliminations Total
---------- -------- ----- ------------ -----
Operating revenues $ 858,340 $ 2,006,398 $ 124,188 $ (858,340) $ 2,130,586
Operating expense 522,696 1,414,753 104,061 (858,340) 1,183,170
----------- ----------- ----------- ----------- -----------
Operating margin 335,644 591,645 20,127 -- 947,416
Depreciation and
amortization 135,406 241,168 3,105 -- 379,679
Interest and preferred stock
dividend requirements 37,045 108,670 14,537 -- 160,252
----------- ----------- ----------- ----------- -----------
Pretax margin 163,193 241,807 2,485 -- 407,485
Income taxes 49,969 109,487 5,137 -- 164,593
----------- ----------- ----------- ----------- -----------
Earnings for common stock $ 113,224 $ 132,320 $ (2,652) $ -- $ 242,892
=========== =========== =========== =========== ===========
Total assets $ 2,399,560 $ 3,993,740 $ 431,246 $ -- $ 6,824,546
=========== =========== =========== =========== ===========
Capital expenditures $ 85,767 $ 241,638 $ 73,133 $ -- $ 400,538
=========== =========== =========== =========== ===========
84
PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
[Enlarge/Download Table]
Additions
---------------------
Balance at Charged to Charged Balance
beginning cost and to other at end of
Description of period expenses accounts Deductions(a) Period
----------- --------- -------- -------- ------------- ------
(dollars in thousands)
YEAR ENDED DECEMBER 31, 2000
Real Estate Valuation Reserves $ 8,000 $ -- $ -- $ 6,000 $ 2,000
YEAR ENDED DECEMBER 31, 1999
Real Estate Valuation Reserves $ 15,000 $ -- $ -- $ 7,000 $ 8,000
YEAR ENDED DECEMBER 31, 1998
Real Estate Valuation Reserves $ 23,000 $ -- $ -- $ 8,000 $ 15,000
(a) REPRESENTS PRO-RATA ALLOCATIONS FOR SALE OF LAND.
85
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" and to "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 23,
2001 (the 2001 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 "Directors' Compensation," "Human Resources
Committee Report on Executive Compensation," "Stock Performance Comparisons,"
"Executive Compensation," "Option Grants, Exercise, and Holdings," and
"Executive Benefit Plans" in the 2001 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Security Ownership of Certain Beneficial
Owners and Management" in the 2001 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 Relationship" in the 2001
Proxy Statement.
86
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
----------- -----------
10.1a -- 2001 Management Variable Incentive Plan (Pinnacle West)
10.2a -- 2001 Senior Management Variable Incentive Plan (Pinnacle West)
10.3a -- 2001 Officer Variable Incentive Plan (Pinnacle West)
10.4a -- 2001 Management Variable Incentive Plan (APS)
10.5a -- 2001 Senior Management Variable Incentive Plan (APS)
10.6a -- 2001 Officers Variable Incentive Plan (APS)
10.7 -- Four Corners Project Co-Tenancy Agreement Amendment No. 6
10.8a -- Sixth Amendment to Arizona Public Service Company Deferred
Compensation Plan
12.1 -- Ratio of Earnings to Fixed Charges
21.1 -- Subsidiaries of the Company
23.1 -- Consent of Deloitte & Touche LLP
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:
[Enlarge/Download Table]
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
87
[Enlarge/Download Table]
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- ----------- --------------
3.2 Bylaws, amended as of December 4.1 to the Company's 1-8962 1-20-00
15, 1999 Registration 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 Mortgage 10-Q Report
Bonds, together with forty-eight
indentures supplemental thereto
4.2 Forty-ninth Supplemental Indenture 4.1 to APS' 1992 Form 10-K 1-4473 3-30-93
Report
4.3 Fiftieth Supplemental Indenture 4.2 to APS' 1993 Form 10-K 1-4473 3-30-94
Report
4.4 Fifty-first Supplemental Indenture 4.1 to APS' August 1, 1993 Form 1-4473 9-27-93
8-K Report
4.5 Fifty-second Supplemental 4.1 to APS' September 30, 1993
Indenture Form 10-Q Report 1-4473 11-15-93
4.6 Fifty-third Supplemental Indenture 4.5 to APS' Registration 1-4473 3-1-94
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
4.8 Fifty-fifth Supplemental Indenture 4.8 to APS' Registration 1-4473 4-9-97
Statement Nos. 33-55473,
33-64455 and 333-15379 by means
of April 7, 1997 Form 8-K Report
4.9 Agreement, dated March 21, 1994, 4.1 to APS' 1993 Form 10-K 1-4473 3-30-94
relating to the filing of Report
instruments defining the rights of
holders of APS long-term debt
not in excess of 10% of APS'
total assets
88
[Enlarge/Download Table]
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- ----------- --------------
4.10 Indenture dated as of January 1, 4.6 to APS' Registration 1-4473 1-11-95
1995 among APS and The Bank of Statement Nos. 33-61228 and
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 November 4.5 to APS' Registration 1-4473 11-22-96
15, 1996 among APS and The Bank Statements Nos. 33-61228,
of New York, as Trustee 33-55473, 33-64455 and 333-
15379 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
4.15 Indenture dated as of December 1, 4.1 to the Company's 1-8962 1-25-01
2000 between the Company and The Registration Statement No.
Bank of New York, as Trustee, 333-53150
relating to Senior Debt Securities
4.16 Indenture dated as of December 1, 4.2 to the Company's 1-8962 1-25-01
2000 between the Company and The Registration Statement No.
Bank of New York, as Trustee, 333-53150
relating to subordinated Debt
Securities
89
[Enlarge/Download Table]
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- ----------- --------------
4.17 Specimen Certificate of Pinnacle 4.2 to the Company's 1988 1-8962 3-31-89
West Capital Corporation Common Form 10-K Report
Stock, no par value
4.18 Agreement, dated March 29, 1988, 4.1 to the Company's 1987 1-8962 3-30-88
relating to the filing of Form 10-K Report
instruments defining the rights
of holders of long-term debt
not in excess of 10% of the
Company's total assets
4.19 Indenture dated as of January 15, 4.10 to APS' Registration The 1-4473 1-16-98
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
4.20 First Supplemental Indenture 4.3 to APS' Registration 1-4473 1-16-98
dated as of January 15, 1998 Statement Nos. 333-15379 and
333-27551 by means of January
13, 1998 Form 8-K Report
4.21 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
4.22 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
90
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EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
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4.23 Amended and Restated Rights 4.1 to the Company's March 22, 1-8962 4-19-99
Agreement, dated as of March 26, 1999 Form 8-K Report
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
10.9 Two separate Decommissioning 10.2 to APS' September 1991 1-4473 11-14-91
Trust Agreements (relating to Form 10-Q Report
PVNGS Units 1 and 3,
respectively), each dated
July 1, 1991, between APS and
Mellon Bank, N.A., as
Decommissioning Trustee
10.10 Amendment No. 1 to 10.1 to APS' 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Agreement Report
(PVNGS Unit 1), dated as of
December 1, 1994
10.11 Amendment No. 1 to 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Agreement Report
(PVNGS Unit 3), dated as of
December 1, 1994
10.12 Amendment No. 2 to APS 10.4 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Agreement Report
(PVNGS Unit 1) dated as of July
1, 1991
10.13 Amendment No. 2 to APS 10.6 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Agreement Report
(PVNGS Unit 3) dated as of July
1, 1991
91
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10.14 Amended and Restated 10.1 to the Company's 1991 Form 1-8962 3-26-92
Decommissioning Trust Agreement 10-K Report
(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
10.15 First Amendment to Amended and 10.2 to APS' 1992 Form 10-K 1-4473 3-30-93
Restated Decommissioning Trust Report
Agreement (PVNGS Unit 2), dated
as of November 1, 1992
10.16 Amendment No. 2 to Amended and 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
Restated Decommissioning Trust Report
Agreement (PVNGS Unit 2), dated
as of November 1, 1994
10.17 Amendment No. 3 to Amended and 10.1 to APS' June 1996 Form 1-4473 8-9-96
Restated Decommissioning Trust 10-Q Report
Agreement (PVNGS Unit 2), dated
as of November 1, 1994
10.18 Amendment No. 4 to Amended and APS 10.5 to APS' 1996 Form 1-4473 3-28-97
Restated Decommissioning Trust 10-K Report
Agreement (PVNGS Unit 2) dated
as of January 31, 1992
92
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10.19 Asset Purchase and Power Exchange 10.1 to APS' June 1991 Form 1-4473 8-8-91
Agreement dated September 21, 10-Q Report
1990 between APS and PacifiCorp,
as amended as of October 11,
1990 and as of July 18, 1991
10.20 Long-Term Power Transaction 10.2 to APS' June 1991 Form 1-4473 8-8-91
Agreement dated September 21, 10-Q Report
1990 between APS and PacifiCorp,
as amended as of October 11,
1990, and as of July 8, 1991
10.21 Amendment No. 1 dated April 5, 10.3 to APS' 1995 Form 10-K 1-4473 3-29-96
1995 to the Long-Term Power Report
Transaction Agreement and Asset
Purchase and Power Exchange
Agreement between PacifiCorp
and APS
10.22 Restated Transmission Agreement 10.4 to APS' 1995 Form 10-K 1-4473 3-29-96
between PacifiCorp and APS dated Report
April 5, 1995
10.23 Contract among PacifiCorp, APS 10.5 to APS' 1995 Form 10-K 1-4473 3-29-96
and United States Department of Report
Energy Western Area Power
Administration, Salt Lake Area
Integrated Projects for Firm
Transmission Service dated
May 5, 1995
10.24 Reciprocal Transmission Service 10.6 to APS' 1995 Form 10-K 1-4473 3-29-96
Agreement between APS and Report
PacifiCorp dated as of March 2,
1994
93
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10.25 Contract, dated July 21, 1984, 10.31 to the Company's Form 2-96386 3-13-85
with DOE providing for the S-14 Registration Statement
disposal of nuclear fuel and/or
high-level radioactive waste,
ANPP
10.26 Indenture of Lease with Navajo 5.01 to APS' Form S-7 2-59644 9-1-77
Tribe of Indians, Four Corners Registration Statement
Plant
10.27 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
10.28 Amendment and Supplement No. 1 to 10.36 to the Company's 1-8962 7-25-85
Supplemental and Additional Registration Statement on
Indenture of Lease Four Corners, Form 8-B Report
dated April 25, 1985
10.29 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
10.30 Application and Amendment No. 1 10.37 to the Company's 1-8962 7-25-85
to Grant of multi-party Registration Statement on
rights-of-way and easements, Form 8-B
Four Corners Power Plant Site
dated April 25, 1985
10.31 Application and Grant of Arizona 5.05 to APS' Form S-7 2-59644 9-1-77
Public Service Company rights- Registration Statement
of-way and easements, Four
Corners Plant Site
10.32 Application and Amendment No. 1 10.38 to the Company's 1-8962 7-25-85
to Grant of Arizona Public Registration Statement on
Service Company rights-of-way Form 8-B
and easements, Four Corners
Power Plant Site dated April 25,
1985
94
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10.33 Indenture of Lease, Navajo Units 5(g) to APS' Form S-7 2-36505 3-23-70
1, 2, and 3 Registration Statement
10.34 Application of Grant of 5(h) to APS Form S-7 2-36505 3-23-70
rights-of-way and easements, Registration Statement
Navajo Plant
10.35 Water Service Contract Assignment 5(l) to APS' Form S-7 2-394442 3-16-71
with the United States Department Registration Statement
of Interior, Bureau of
Reclamation, Navajo Plant
10.36 Arizona Nuclear Power Project 10. 1 to APS' 1988 Form 10-K 1-4473 3-8-89
Participation Agreement, dated
August 23, 1973, among APS
Salt River Project Agricultural
Improvement and Power District,
Southern California Edison
Company, Public Service Company
of New Mexico, El Paso Electric
Company, Southern California
Public Power Authority, and
Department of Water and Power of
the City of Los Angeles, and
amendments 1-12 thereto
95
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10.37 Amendment No. 13, dated as of 10.1 to APS' March 1991 1-4473 5-15-91
April 22, 1991, to Arizona Form 10-Q
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
10.38 Amendment No. 14 to Arizona 99.1 to the Company's June 1-8962 8-14-00
Nuclear Power Project 2000 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
10.39(c) Facility Lease, dated as of 4.3 to APS' Form S-3 33-9480 10-24-86
August 1, 1986, between State Registration 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
96
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10.40(c) Amendment No. 1, dated as of 10.5 to APS' September 1986 1-4473 12-4-86
November 1, 1986, to Facility Form 10-Q Report by means of
Lease, dated as of August 1, Amendment No. on December 3,
1986, between State Street Bank 1986 Form 8
and Trust Company, as successor
to The First National Bank of
Boston, in its capacity as Owner
Trustee, as Lessor, and APS, as
Lessee
10.41(c) Amendment No. 2 dated as of June 10.3 to APS' 1988 Form 10-K 1-4473 3-8-89
1, 1987 to Facility Lease dated Report
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
10.42(c) Amendment No. 3, dated as of 10.3 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of August 1,
1986, between State Street Bank
and Trust Company, as successor
to The First National Bank of
Boston, as Lessor, and APS, as
Lessee
10.43 Facility Lease, dated as of 10.1 to APS' November 18 1986 1-4473 1-20-87
December 15, 1986, between State Form 8-K Report
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
97
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10.44 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 15, 33-9480 by means of August 1,
1986, between State Street Bank 1987 Form 8-K Report
and Trust Company, as successor
to The First National Bank of
Boston, as Lessor, and APS, as
Lessee
10.45 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
10.46(a) Pinnacle West Capital Corporation 10.13 to the Company's 1999 1-8962 3-30-00
Supplemental Excess Benefit Form 10-K Report
Retirement Plan, as amended and
restated, dated December 7, 1999
10.47(a) Trust for the Pinnacle West 10.14 to the Company's 1999 1-8962 3-30-00
Capital Corporation, Arizona Form 10-K Report
Public Service Company and SunCor
Development Company Deferred
Compensation Plans dated August
1, 1996
10.48(a) First Amendment dated December 7, 10.15 to the Company's 1999 1-8962 3-30-00
1999 to the Trust for the Form 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company and SunCor
Development Company Deferred
Compensation Plans
98
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10.49(a) Directors' Deferred Compensation 10.1 to APS' June 1986 Form 1-4473 8-13-86
Plan, as restated, effective 10-Q Report
January 1, 1986
10.50(a) Second Amendment to the Arizona 10.2 to APS' 1993 Form 10-K 1-4473 3-30-94
Public Service Company Deferred Report
Compensation Plan, effective as
of January 1, 1993
10.51(a) Third Amendment to the Arizona 10.1 to APS' September 1994 1-4473 11-10-94
Public Service Company Directors' Form 10-Q
Deferred Compensation Plan,
effective as of May 1, 1993
10.52(a) Fourth Amendment dated December 10.8 to the Company's 1999
28, 1999 to the Arizona Public Form 10-K Report 1-8962 3-30-00
Service Company Directors
Deferred Compensation Plan
10.53(a) Arizona Public Service Company 10.4 to APS' 1988 Form 10-K 1-4473 3-8-89
Deferred Compensation Plan, as Report
restated, effective January 1,
1984, and the second and third
amendments thereto, dated
December 22, 1986, and December
23, 1987 respectively
10.54(a) Third Amendment to the Arizona 10.3 to APS' 1993 Form 10-K 1-4473 3-30-94
Public Service Company Deferred Report
Compensation Plan, effective as
of January 1, 1993
10.55(a) Fourth Amendment to the Arizona 10.2 to APS' September 1994 1-4473 11-10-94
Public Service Company Deferred Form 10-Q Report
Compensation Plan effective as of
May 1, 1993
99
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----------- ----------- ---------------------------- ----------- --------------
10.56(a) Fifth Amendment to the Arizona 10.3 to APS' 1996 Form 10-K 1-4473 3-28-97
Public Service Company Deferred Report
Compensation Plan
10.57(a) First Amendment effective as of 10.7 to the Company's 1999 1-8962 3-30-00
January 1, 1999, to the Pinnacle Form 10-K Report
West Capital Corporation, Arizona
Public Service Company, SunCor
Development Company and El Dorado
Investment Company Deferred
Compensation Plan
10.58(a) Second Amendment effective 10.10 to the Company's 1999 1-8962 3-30-00
January 1, 2000 to the Pinnacle Form 10-K Report
West Capital Corporation, Arizona
Public Service Company, SunCor
Development Company and El Dorado
Investment Company Deferred
Compensation Plan
10.59(a) Pinnacle West Capital 10.10 to APS' 1995 Form 1-4473 3-29-96
Corporation, Arizona Public 10-K Report
Service Company, SunCor
Development Company and El
Dorado Investment Company
Deferred Compensation Plan as
amended and restated effective
January 1, 1996
10.60(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
10.61(a) Letter Agreement dated July 28, 10.16 to the Company's 1999 1-8962 3-30-00
1995 between Arizona Public Form 10-K Report
Service Company and Armando B.
Flores
100
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10.62(a) Letter Agreement dated October 3, 10.17 to the Company's 1999 1-8962 3-30-00
1997 between Arizona Public Form 10-K Report
Service Company and James M.
Levine
10.63(a) Letter Agreement dated as of 10.8 to APS' 1995 Form 10-K 1-4473 3-29-96
January 1, 1996 between APS and Report
Robert G. Matlock & Associates,
Inc. for consulting services
10.64(a) Letter Agreement dated December 10.7 to APS' 1994 Form 10-K 1-4473 3-30-96
21, 1993, between APS and Report
William L. Stewart
10.65(a) Letter Agreement dated August 10.8 to APS' 1996 Form 10-K 1-4473 3-28-97
16, 1996 between APS and William Report
L. Stewart
10.66(a) Letter Agreement between APS and 10.2 to APS' September 1997 1-4473 11-12-97
William L. Stewart Form 10-Q Report
10.67(a) Letter Agreement dated December
13, 1999 between APS and William
L. Stewart
10.68(a)(d) Key Executive Employment and 10.1 to June 1999 Form 10-Q 1-8962 8-16-99
Severance Agreement between Report
Pinnacle West and certain
executive officers of Pinnacle
West and its subsidiaries
10.69(a) Pinnacle West Capital 10.1 to APS' 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option and Report
Incentive Plan
10.70(a) First Amendment dated December 7, 10.11 to the Company's 1999 1-8962 3-30-00
1999 to the Pinnacle West Capital Form 10-K Report
Corporation Stock Option and
Incentive Plan
101
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10.71(a) Pinnacle West Capital Corporation A to the Proxy Statement for 1-8962 4-16-94
1994 Long-Term Incentive Plan, the Plan Report for the
effective as of March 23, 1994 Company's 1994 Annual
Meeting of Shareholders
10.72(a) First Amendment dated December 7, 10.12 to the Company's 1999 1-8962 3-30-00
1999 to the Pinnacle West Capital Form 10-K Report
Corporation 1994 Long-Term
Incentive Plan
10.73(a) Pinnacle West Capital Corporation B to the Proxy Statement for 1-8962 4-16-94
Director Equity Participation the Plan Report for the
Plan Company's 1994 Annual Meeting
of Shareholders
10.74(a) Pinnacle West Capital Corporation 99.1 to the Company's 1-8962 7-3-00
2000 Director Equity Plan Registration Statement on
Form S-8 (No. 333-40796)
10.75(a) Pinnacle West Capital Corporation 99.2 to the Company's 1-8962 7-3-00
and Arizona Public Service Registration Statement on
Company Directors' Retirement Form S-8 (No. 333-40796)
Plan, as amended and restated on
June 21, 2000
10.76 Agreement No. 13904 (Option and 10.3 to APS' 1991 Form 10-K 1-4473 3-19-92
Purchase of Effluent) with Cities Report
of Phoenix, Glendale, Mesa,
Scottsdale, Tempe, Town of
Youngtown, and Salt River Project
Agricultural Improvement and
Power District, dated April 23,
1973
102
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10.77 Agreement for the Sale and 10.4 to APS' 1991 Form 10-K 1-4473 3-19-92
purchase of Wastewater Effluent Report
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
10.78(a) APS Director Equity Plan 10.1 to September 1997 Form 1-4473 11-12-97
10-Q Report
10.79 Territorial Agreement between the 10.1 to APS' March 1998 Form 1-4473 5-15-98
Company and Salt River Project 10-Q Report
10.80 Power Coordination Agreement 10.2 to APS' March 1998 Form 1-4473 5-15-98
between the Company and Salt 10-Q Report
River Project
10.81 Memorandum of Agreement between 10.3 to APS' March 1998 Form 1-4473 5-15-98
the Company and Salt River 10-Q Report
Project
10.82 Addendum to Memorandum of 10.2 to APS' May 19, 1998 1-4473 6-26-98
Agreement between APS and Salt Form 8-K Report
River Project dated as of May 19,
1998
99.1 Collateral Trust Indenture among 4.2 to APS' 1992 Form 10 K 1-4473 3-30-93
PVNGS II Funding Corp., Inc., Report
APS and Chemical Bank, as Trustee
99.2 Supplemental Indenture to 4.3 to APS' 1992 Form 10 K 1-4473 3-30-93
Collateral Trust Indenture among Report
PVNGS II Funding Corp., Inc.,
APS and Chemical Bank, as Trustee
103
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99.3(c) Participation Agreement, dated as 28.1 to APS' September 1992 1-4473 11-9-92
of August 1, 1986, among PVNGS Form 10-Q Report
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
99.4(c) Amendment No. 1 dated as of 10.8 to APS' September 1986 1-4473 12-4-86
November 1, 1986, to Form 10-Q Report by means of
Participation Agreement, dated as Amendment No. 1, on December
of August 1, 1986, among PVNGS 3, 1986 Form 8
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
104
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----------- ----------- ---------------------------- ----------- --------------
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 Participation Report
Agreement, dated as of August 1,
1986, among PVNGS Funding Corp.,
Inc., PVNGS II Funding Corp.,
Inc., State Street Bank and
Trust Company, as successor to
The First National Bank of
Boston, in its individual
capacity and as Owner Trustee,
Chemical Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Equity
Participant named therein
99.6(c) Trust Indenture, Mortgage, 4.5 to APS' Form S-3 33-9480 10-24-86
Security Agreement and Assignment Registration Statement
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. 1, 10.6 to APS' September 1986 1-4473 12-4-86
dated as of November 1, 1986 to Form 10-Q Report by means of
Trust Indenture, Mortgage, Amendment No. 1 on
Security Agreement and Assignment December 3, 1986 Form 8
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
105
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----------- ----------- ---------------------------- ----------- --------------
99.8(c) Supplemental Indenture No. 2 to 28.14 to APS' 1992 Form 10-K
Trust Indenture, Mortgage, Report 1-4473 3-30-93
Security Agreement and
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank and
Trust Company, as successor to
The First National Bank of
Boston, as Owner Trustee, and
Chemical Bank, as Lease
Indenture Trustee
99.9(c) Assignment, Assumption and 28.3 to APS' Form S-3 33-9480 10-24-86
Further Agreement, dated as of Registration Statement
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 1-4473 12-4-86
November 1, 1986, to Assignment, Form 10-Q Report by means of
Assumption and Further Amendment No. l on
Agreement, dated as of August 1, December 3, 1986 Form 8
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 Assignment, Report
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
106
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----------- ----------- ---------------------------- ----------- --------------
99.12 Participation Agreement, dated 28.2 to APS' September 1992 1-4473 11-9-92
as of December 15, 1986, among Form 10-Q Report
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 Participation Registration Statement No.
Agreement, dated as of December 33-9480 by means of a
15, 1986, among PVNGS Funding November 6, 1986 Form 8-K
Corp., Inc. as Funding Report
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
107
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----------- ----------- ---------------------------- ----------- --------------
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 Participation Report
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 Security 10.2 to APS' November 18, 1-4473 1-20-87
Agreement and Assignment of 1986 Form 10-K Report
Facility Lease, dated as of
December 15, 1986, between State
Street Bank and Trust Company,
as successor to The First
National Bank of Boston, as Owner
Trustee, and Chemical Bank, as
Indenture Trustee
99.16 Supplemental Indenture No. 1, 4.13 to APS' Form S-3 1-4473 8-24-87
dated as of August 1, 1987, to Registration Statement No.
Trust Indenture, Mortgage, 33-9480 by means of
Security Agreement and August 1, 1987 Form
Assignment of Facility Lease, 8-K Report
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
108
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----------- ----------- ---------------------------- ----------- --------------
99.17 Supplemental Indenture No. 2 to 4.5 to APS' 1992 Form 10-K
Trust Indenture Mortgage, Report 1-4473 3-30-93
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, 1-4473 1-20-87
Further Agreement, dated as of 1986 Form 8-K Report
December 15, 1986, between APS
and State Street Bank and Trust
Company, as successor to The
First National Bank of Boston,
as Owner Trustee
99.19 Amendment No. 1, dated as of 28.7 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Assignment, Report
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 of 28.3 to APS' 1992 Form 10-K 1-4473 3-30-93
March 17, 1993 by APS Report
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 Participation 33-9480 by means of a November
Agreement to Chemical Bank 6, 1986 Form 8-K Report
99.22 Arizona Corporation Commission 28.1 to APS' 1991 Form 10-K 1-4473 3-19-92
Order dated December 6, 1991 Report
109
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EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- ----------- --------------
99.23 Arizona Corporation Commission 10.1 to APS' June 1994 form 1-4473 8-12-94
Order dated June 1, 1994 10-Q Report
99.24 Rate Reduction Agreement dated 10.1 to APS' December 4, 1995 1-4473 12-14-95
December 4, 1995 between APS and 8-K Report
the ACC Staff
99.25 ACC Order dated April 24, 1996 10.1 to APS' March 1996 Form 1-4473 5-14-96
10-Q Report
99.26 Arizona Corporation Commission 99.1 to APS' 1996 Form 10-K 1-4473 3-28-97
Order, Decision No. 59943, dated Report
December 26, 1996, including the
Rules regarding the introduction
of retail competition in Arizona
99.27 Retail Electric Competition Rules 10.1 to APS' June 1998 Form 1-4473 8-14-98
10-Q Report
99.28 Arizona Corporation Commission 10.1 to APS' September 1999 1-4473 11-15-99
Order, Decision No. 61973, dated 10-Q Report
October 6, 1999, approving APS'
Settlement Agreement
99.29 Addendum to Settlement Agreement 10.1 to the Company's 1-8962 11-14-00
September 2000 Form 10-Q
Report
99.29 Arizona Corporation Commission 10.2 to APS' September 1999 1-4473 11-15-99
Order, Decision No. 61969, dated 10-Q Report
September 29, 1999, including the
Retail Electric Competition Rules
99.30 Purchase and Sale Agreement for 99.1 to the Company's March 1-8962 5-15-00
Palo Verde Nuclear Generating 2000 Form 10-Q Report
Station by and between Southern
California Edison Company and
Pinnacle West Energy Corporation,
dated as of April 27, 2000
110
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EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE
----------- ----------- ---------------------------- ----------- --------------
99.31 Purchase and Sale Agreement for 99.2 to the Company's March 1-8962 5-15-00
Four Corners Power Plant by and 2000 10-Q Report
between Southern California
Edison Company and Pinnacle West
Energy Corporation, dated as of
April 27, 2000
----------
(a) Management contract or compensatory plan or arrangement to be filed as
an exhibit pursuant to Item 14(c) of Form 10-K.
(b) Reports filed under File No. 1-4473 and 1-8962 were filed in the office
of the Securities and Exchange Commission located in Washington, D.C.
(c) An additional document, substantially identical in all material
respects to this Exhibit, has been entered into, relating to an additional
Equity Participant. Although such additional document may differ in other
respects (such as dollar amounts, percentages, tax indemnity matters, and dates
of execution), there are no material details in which such document differs from
this Exhibit.
(d) Additional agreements, substantially identical in all material respects
to this Exhibit have been entered into with additional persons. Although such
additional documents may differ in other respects (such as dollar amounts and
dates of execution), there are no material details in which such agreements
differ from this Exhibit.
REPORTS ON FORM 8-K
During the quarter ended December 31, 2000, and the period ended March 13,
2001, the Company filed the following Reports on Form 8-K:
Report dated October 26, 2000, regarding the written materials presented at
an analyst conference in Phoenix, Arizona.
Report dated November 27, 2000, regarding: (i) the Court of Appeals
affirming the ACC's approval of the 1999 Settlement Agreement; a Maricopa County
Superior Court judge's final judgment related to the Rules; the proposed timing
of the transfer of generation assets; and issues related to generation
expansion.
111
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 13, 2001 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 March 13, 2001
--------------------------------- Officer and Director
(William J. Post, Chairman
of the Board of Directors and
Chief Executive Officer)
Jack E. Davis President and Director March 13, 2001
---------------------------------
(Jack E. Davis, President)
Michael V. Palmeri Principal Financial March 13, 2001
--------------------------------- Officer
(Michael V. Palmeri,
Vice President, Finance)
Chris N. Froggatt Principal Accounting March 13, 2001
--------------------------------- Officer
(Chris N. Froggatt,
Vice President and Controller)
Edward N. Basha Director March 13, 2001
---------------------------------
(Edward N. Basha, Jr.)
112
Michael L. Gallagher Director March 13, 2001
---------------------------------
(Michael L. Gallagher)
Pamela Grant Director March 13, 2001
---------------------------------
(Pamela Grant)
Roy A. Herberger, Jr. Director March 13, 2001
---------------------------------
(Roy A. Herberger, Jr.)
Martha O. Hesse Director March 13, 2001
---------------------------------
(Martha O. Hesse)
William S. Jamieson, Jr. Director March 13, 2001
---------------------------------
(William S. Jamieson, Jr.)
Humberto S. Lopez Director March 13, 2001
---------------------------------
(Humberto S. Lopez)
Robert G. Matlock Director March 13, 2001
---------------------------------
(Robert G. Matlock)
Kathryn L. Munro Director March 13, 2001
---------------------------------
(Kathryn L. Munro)
Bruce J. Nordstrom Director March 13, 2001
---------------------------------
(Bruce J. Nordstrom)
113
Dates Referenced Herein and Documents Incorporated by Reference
| Referenced-On Page |
|---|
| This ‘10-K’ Filing | | Date | | First | | Last | | | Other Filings |
|---|
| |  |
| | 10/31/20 | | 12 |
| | 12/31/06 | | 11 | | | | | 10-K, 11-K, 8-K |
| | 1/1/06 | | 40 | | 79 |
| | 12/31/04 | | 62 | | | | | 10-K, 11-K, 8-K, U-3A-2 |
| | 7/1/04 | | 6 | | 62 | | | 4 |
| | 6/30/04 | | 8 | | 78 | | | 10-Q, 8-K |
| | 1/1/04 | | 62 |
| | 12/31/03 | | 11 | | | | | 10-K, 11-K, 8-K, U-3A-2 |
| | 7/1/03 | | 35 | | 61 | | | 4, 4/A |
| | 12/31/02 | | 7 | | 64 | | | 10-K, 11-K, 5, 8-K, U-3A-2 |
| | 5/23/01 | | 1 | | 88 | | | DEF 14A |
| Filed as of: | | 3/14/01 |
| Filed on: | | 3/13/01 | | 113 | | 115 |
| | 3/8/01 | | 1 | | 27 |
| | 3/7/01 | | 24 | | 76 |
| | 3/1/01 | | 25 |
| | 2/27/01 | | 14 |
| | 2/21/01 | | 49 |
| | 2/9/01 | | 50 |
| | 1/5/01 | | 40 | | 79 |
| | 1/1/01 | | 41 | | 63 |
| For Period End: | | 12/31/00 | | 1 | | 113 | | | 11-K, U-3A-2 |
| | 12/26/00 | | 42 | | 61 |
| | 11/27/00 | | 42 | | 113 | | | 8-K |
| | 10/26/00 | | 113 | | | | | 8-K |
| | 10/16/00 | | 8 |
| | 7/25/00 | | 20 |
| | 7/12/00 | | 16 | | | | | 8-K |
| | 7/1/00 | | 61 |
| | 6/29/00 | | 16 |
| | 6/21/00 | | 104 |
| | 5/5/00 | | 16 |
| | 4/27/00 | | 40 | | 113 |
| | 1/1/00 | | 62 | | 102 |
| | 12/31/99 | | 36 | | 87 | | | 10-K, 11-K, 5, U-3A-2 |
| | 12/20/99 | | 7 |
| | 12/13/99 | | 42 | | 103 |
| | 12/8/99 | | 63 |
| | 12/7/99 | | 100 |
| | 11/2/99 | | 92 |
| | 11/1/99 | | 92 |
| | 10/6/99 | | 112 |
| | 9/30/99 | | 81 | | | | | 10-Q |
| | 9/29/99 | | 112 | | | | | 8-K |
| | 9/24/99 | | 62 |
| | 9/23/99 | | 61 |
| | 9/21/99 | | 41 | | 63 | | | 8-K |
| | 7/1/99 | | 35 | | 64 |
| | 5/14/99 | | 61 | | | | | 8-K |
| | 4/22/99 | | 13 |
| | 4/15/99 | | 16 |
| | 3/26/99 | | 93 | | | | | 8-K |
| | 3/1/99 | | 70 | | | | | U-3A-2 |
| | 2/19/99 | | 16 |
| | 2/18/99 | | 92 |
| | 2/15/99 | | 92 |
| | 1/1/99 | | 102 |
| | 12/31/98 | | 64 | | 87 | | | 10-K405, 11-K, U-3A-2 |
| | 8/28/98 | | 24 |
| | 7/1/98 | | 36 | | 64 |
| | 5/19/98 | | 105 |
| | 4/10/98 | | 15 |
| | 1/15/98 | | 92 |
| | 1/13/98 | | 92 |
| | 7/1/97 | | 36 | | 64 | | | 4 |
| | 4/7/97 | | 90 | | 91 |
| | 12/26/96 | | 112 |
| | 11/19/96 | | 90 | | 91 |
| | 8/1/96 | | 100 |
| | 7/1/96 | | 36 | | 64 |
| | 6/10/96 | | 13 |
| | 1/1/96 | | 102 | | 103 |
| | 12/4/95 | | 112 | | | | | 8-K |
| | 10/18/95 | | 15 |
| | 10/17/95 | | 15 |
| | 10/13/95 | | 15 |
| | 5/5/95 | | 95 |
| | 4/5/95 | | 95 |
| | 1/1/95 | | 91 | | 102 |
| | 12/1/94 | | 93 |
| | 11/1/94 | | 94 |
| | 3/23/94 | | 104 |
| | 3/21/94 | | 90 |
| | 3/2/94 | | 95 |
| | 2/23/94 | | 90 |
| | 9/30/93 | | 90 |
| | 8/1/93 | | 90 |
| | 5/1/93 | | 101 |
| | 3/17/93 | | 99 | | 111 |
| | 1/1/93 | | 101 |
| | 11/1/92 | | 94 |
| | 1/31/92 | | 94 |
| List all Filings |
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