================================================================================
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 1-4473
ARIZONA PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
ARIZONA
(State or other jurisdiction 86-0011170
of incorporation or organization) (I.R.S. Employer Identification No.)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999 (602) 250-1000
(Address of principal executive offices, (Registrant's telephone number,
including zip code) including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OR 12(g) OF THE ACT: None.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in any amendment to this Form 10-K. [X]
As of March 13, 2001, there were issued and outstanding 71,264,947 shares
of the registrant's common stock, $2.50 par value, all of which were held
beneficially and of record by Pinnacle West Capital Corporation.
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I1(a)
AND (b) AND IS THEREFORE FILING THIS DOCUMENT WITH THE REDUCED DISCLOSURE
FORMAT.
================================================================================
TABLE OF CONTENTS
Page
----
GLOSSARY.................................................................... 1
PART I
Item 1. Business...................................................... 3
Item 2. Properties.................................................... 15
Item 3. Legal Proceedings............................................. 19
Item 4. Submission of Matters to a Vote of Security Holders........... 19
PART II
Item 5. Market for Registrant's Common Stock and Related Security
Holder Matters................................................ 20
Item 6. Selected Financial Data....................................... 21
Item 7. Financial Review.............................................. 22
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.... 32
Item 8. Financial Statements and Supplementary Data................... 33
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...................................... 69
PART III
Item 10. Directors and Executive Officers of the Registrant............ 69
Item 11. Executive Compensation........................................ 69
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 69
Item 13. Certain Relationships and Related Transactions................ 69
PART IV
Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
and Reports on Form 8-K....................................... 70
SIGNATURES.................................................................. 94
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
Cholla -- Cholla Power Plant
Cholla 4 -- Unit 4 of the Cholla Power Plant
Citizens - Citizens Communication Company
Company -- Arizona Public Service Company
CPUC -- California Public Utility Commission
DIG -- Derivatives Implementation Group
DOE -- United States Department of Energy
EITF -- Emerging Issues Task Force
EPA -- United States Environmental Protection Agency
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
NRC -- United States Nuclear Regulatory Commission
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 -- Pinnacle West Capital Corporation, an Arizona corporation, the
Company's parent
1
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
SEC -- United States Securities and Exchange Commission
SFAS -- Statement of Financial Accounting Standards
2
PART I
ITEM 1. BUSINESS
GENERAL
We were incorporated in 1920 under the laws of Arizona and are Arizona's
largest electric utility, with more than 850,000 customers. We provide wholesale
or retail electric service to the entire state of Arizona, with the exception of
Tucson and about one-half of the Phoenix area. We also generate and, directly or
through Pinnacle West's power marketing division, sell and deliver 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, we employed about 5,300 people, which includes
employees assigned to joint projects where we are project manager. Our principal
executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004
(telephone 602-250-1000).
See Note 16 of Notes to 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; our ability to compete successfully outside traditional
regulated markets (including the wholesale market); and technological
developments in the electric industry.
REGULATION AND COMPETITION
RETAIL
The ACC regulates our retail electric rates and our issuance of securities.
The ACC must also approve any transfer of our utility property and transactions
between us and affiliated parties. See "Financial Review - Business Outlook -
Competition and Industry Restructuring" in Item 7 and Note 3 of Notes to
Financial Statements in Item 8 for a discussion of electric industry
restructuring in Arizona, including our 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, we are 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
3
Agreement allows us to seek adjustment of these rates in the event of emergency
conditions or circumstances, such as the inability to secure financing on
reasonable terms, or material changes in our 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 our current retail rates. We
expect these market conditions to continue in 2001. We believe that our current
generation portfolio has been adequately supplemented 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 we
are able to obtain an adjustment of our rates under the 1999 Settlement
Agreement, there can be no assurance that we 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 us to transfer our competitive generation assets and
services to one or more corporate affiliates no later than December 31, 2002. We
intend to move our 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 Pinnacle West's power marketing
division (Power Marketing). Power Marketing, in turn, is expected to sell power
to us and to non-affiliated power purchasers. We expect to meet fifty percent of
our energy needs under a power purchase agreement with Power Marketing. As
required by the Rules, we will acquire the remaining fifty percent of our energy
needs through a competitive bid process in which Power Marketing may
participate. We believe that these arrangements will allow us to manage our
exposure to the wholesale power market during the period within which our 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, we are subject to varying degrees of
competition from other utilities in our 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). We also face
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. We transferred the wholesale power marketing function to
Pinnacle West during 2000.
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.
4
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.
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, we, 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. We
expect 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. We, 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 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 9 of Notes to Financial Statements in Item 8 for
additional information.
5
GENERATING FUEL AND PURCHASED POWER
2000 ENERGY MIX
Our 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 (including oil, hydro and solar) - 0.3%.
COAL SUPPLY
CHOLLA We purchase 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. We purchase a portion of Cholla's coal requirements on the spot market to
take advantage of competitive pricing options. Following expiration of current
contracts, we believe that numerous competitive fuel supply options will exist
to ensure continuous plant operation. We expect the current supplier to continue
to provide most of Cholla's low sulfur coal requirements through the current
contract. We believe 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 We purchase 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 we and our 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. We
anticipate that the Navajo Nation will levy additional taxes upon the expiration
of the tax waivers; however, we 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.
6
See "Properties - Accredited Capacity" in Item 2 for information about our
ownership interest in Cholla, Four Corners, and the Navajo Generating Station.
See Note 12 of Notes to Financial Statements in Item 8 for information regarding
our coal mine reclamation obligations.
NATURAL GAS SUPPLY
We purchase the majority of our natural gas requirements under contracts
with a number of natural gas suppliers. Our natural gas supply is transported
pursuant to a firm transportation service contract with El Paso Natural Gas
Company. 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:
* 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.
We are 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.
7
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 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.
We have existing fuel storage pools at Palo Verde and are in the process of
completing construction of a new facility for on-site dry storage of spent fuel.
With the existing storage pools and the addition of the new facility, we believe
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 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, we are currently shipping low-level waste to off-site facilities. We
currently believe that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
We believe that scientific and financial aspects of the issues of spent
fuel and low-level waste storage and disposal can be resolved satisfactorily.
However, we also acknowledge that their ultimate resolution in a timely fashion
will require political resolve and action on national and regional scales which
we are less able to predict. We expect to vigorously protect and pursue our
rights related to this matter.
8
PURCHASED POWER AGREEMENTS
In addition to that available from our own generating capacity (see
"Properties" in Item 2), we purchase electricity under various arrangements. One
of the most important of these is a long-term contract with Salt River Project.
The amount of electricity available to us is based in large part on customer
demand within certain areas now served by us pursuant to a related territorial
agreement. The generating capacity available to us pursuant to the contract was
322 MW from January through May 2000, and starting June 2000, it changed to 329
MW. In 2000, we 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. We may also cancel this
contract on five years' notice, given no earlier than December 31, 2006.
In September 1990, we entered into a thirty-year seasonal capacity exchange
agreement with PacifiCorp. Under this agreement, we receive electricity from
PacifiCorp during the summer peak season (from May 15 to September 15) and we
return electricity to PacifiCorp during the winter season (from October 15 to
February 15). Until 2020, PacifiCorp and APS each has 480 MW per hour of
capacity and a related amount of energy available to it under the agreement for
our respective seasons. In 2000, we received approximately 396,000 MWh of energy
under the capacity exchange. We must also make additional offers of energy to
PacifiCorp each year through October 31, 2020. Pursuant to this requirement,
during 2000, PacifiCorp received offers of 865,800 MWh and purchased about
218,000 MWh.
CONSTRUCTION PROGRAM
During the years 1998 through 2000, we incurred approximately $1.2 billion
in capital expenditures. Our 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. Our 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. We conduct a continuing review of our construction
program. See "Financial Review - Capital Needs and Resources" in Item 7 for
additional information.
MORTGAGE REPLACEMENT FUND REQUIREMENTS
So long as any of our first mortgage bonds are outstanding, we are required
for each calendar year to deposit with the trustee under our mortgage cash in a
formularized amount related to net additions to our mortgaged utility plant. We
may satisfy all or any part of this "replacement fund"
9
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 we have issued under the
mortgage that are callable prior to maturity are redeemable at their par value
plus accrued interest with cash we deposit in the replacement fund. These call
provisions are subject in many cases to a period of time after the original
issuance of the bonds during which they may not be 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:
* "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
10
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 us
cannot be determined at this time.
In July 1997, the EPA promulgated final National Ambient Air Quality
Standards for ozone and particulate matter. Pursuant to these rules, the ozone
standard is more stringent and a new ambient standard for very fine particles
has been established. Congress has enacted legislation that could delay the
implementation of regional haze requirements and the particulate matter ambient
standard; however, the legislation does not preclude the Visibility Commission
states and tribes from implementing the alternate regional haze rules discussed
above. A federal court determined that the EPA's promulgation of the National
Ambient Air Quality Standards violated the constitutional prohibition on
delegation of legislative power. The court remanded the ozone standard, vacated
the particulate matter standard, and invited the parties that challenged the
standards to brief the court on vacating or remanding the very fine particulates
standard. On February 27, 2001, the U.S. Supreme Court overruled the federal
court's ruling. The 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, we currently cannot estimate the capital expenditures, if any, which
would result from the final rules. However, we do not currently expect these
rules to have a material adverse effect on our financial position, results of
operations, or liquidity.
With respect to hazardous air pollutants emitted by electric utility steam
generating units, the EPA 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 us to make related
expenditures, such as permit fees. We do not expect any of these expenditures to
have a material impact on our financial position, results of operations, or
liquidity.
FEDERAL IMPLEMENTATION PLAN In September 1999, the EPA proposed a FIP to
set air quality standards at certain power plants, including the Navajo
Generating Station and Four Corners. The comment period on this proposal ended
in November 1999. The FIP is similar to current Arizona regulation of the Navajo
Generating Station and New Mexico regulation of Four Corners, with minor
modifications. We do not currently expect the FIP to have a material impact on
our financial position, results of operations, or liquidity.
11
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 us that the EPA considers us to
be a PRP in the Indian Bend Wash Superfund Site, South Area. Our Ocotillo Power
Plant is located in this area. We are 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, we do not expect this matter to have a
material impact on our financial position, results of operations, or liquidity.
MANUFACTURED GAS PLANT SITES We are currently investigating properties
which we now own or which were at one time owned by us or our corporate
predecessors, that were at one time sites of, or sites associated with,
manufactured gas plants. The purpose of this investigation is to determine if:
* waste materials are present;
* such materials constitute an environmental or health risk; and
* we have any responsibility for remedial action.
Where appropriate, we have begun remediation of certain of these sites. We
do not expect these matters to have a material adverse effect on our financial
position, results of operations, or liquidity.
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. We are the Four Corners operating agent.
We own a 100% interest in Four Corners Units 1, 2, and 3, and a 15% interest in
Four Corners Units 4 and 5. We own a 14% interest in Navajo Generating Station
Units 1, 2, and 3.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the
Navajo Nation Pesticide Act (collectively, the 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
12
* 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. We 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, we
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, we 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, we 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, we have adequate water to meet our needs. However, conflicting
claims to limited amounts of water in the southwestern United States have
resulted in numerous court actions in recent years.
Both groundwater and surface water in areas important to our operations
have been the subject of inquiries, claims, and legal proceedings which will
require a number of years to resolve.
13
We are one of a number of parties in a proceeding before a state court in New
Mexico to adjudicate rights to a stream system from which water for Four Corners
is derived. (STATE OF NEW MEXICO, IN THE RELATION OF S.E. REYNOLDS, STATE
ENGINEER VS. UNITED STATES OF AMERICA, CITY OF FARMINGTON, UTAH INTERNATIONAL,
INC., ET AL., San Juan County, New Mexico, District Court No. 75-184). An
agreement reached with the Navajo Nation in 1985, however, provides that if Four
Corners loses a portion of its rights in the adjudication, the Navajo Nation
will provide, for a then-agreed upon cost, sufficient water from its allocation
to offset the loss.
A summons served on us in early 1986 required all water claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987, in an action pending in Maricopa County Superior Court. (IN RE
THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA RIVER SYSTEM AND
SOURCE, Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1,
WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4
(Consolidated)). Palo Verde is located within the geographic area subject to the
summons. Our rights and the rights of the Palo Verde participants to the use of
groundwater and effluent at Palo Verde are potentially at issue in this action.
As project manager of Palo Verde, we filed claims that dispute the court's
jurisdiction over the Palo Verde participants' groundwater rights and their
contractual rights to effluent relating to Palo Verde. Alternatively, we seek
confirmation of such rights. Three of our other power plants are also located
within the geographic area subject to the summons. Our claims dispute the
court's jurisdiction over our groundwater rights with respect to these plants.
Alternatively, we seek confirmation of such rights. The Arizona Supreme Court
issued a decision confirming that certain groundwater rights may be available to
the federal government and Indian tribes. We 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. We 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.
We have 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).
Our groundwater resource utilized at Cholla is within the geographic area
subject to the adjudication and is therefore potentially at issue in the case.
Our claims dispute the court's jurisdiction over our groundwater rights.
Alternatively, we seek confirmation of such rights. 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, we
expect that the described litigation will not have a material adverse impact on
our financial position, results of operations or liquidity.
14
ITEM 2. PROPERTIES
ACCREDITED CAPACITY
Our 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
Our 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 us under
long-term purchase power contracts as well as our own generating capacity, our
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 us
from our resources fluctuates from time to time due in part to planned outages
and technical problems. The available capacity from sources actually operable at
the time of the 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%.
15
See "Business - Purchased Power Agreements" in Item 1 for information about
certain of our long-term power agreements.
PLANT SITES LEASED FROM NAVAJO NATION
The Navajo Generating Station and Four Corners are located on land held
under easements from the federal government and also under leases from the
Navajo Nation. These are long term agreements with options to extend, and we do
not believe that the risk with respect to enforcement of these easements and
leases is material. The majority of coal contracted for use in these plants and
certain associated transmission lines are also located on Indian reservations.
See "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 9 of Notes to 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
us, 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. We currently rely on the external sinking fund mechanism
to meet the NRC financial assurance requirements for our interests in Palo Verde
Units 1, 2, and 3. The decommissioning costs of Palo Verde Units 1, 2, and 3 are
currently included in ACC jurisdictional rates. ACC retail electric competition
rules provide that decommissioning costs would be recovered through a
non-bypassable "system benefits" charge, which would allow us to maintain our
external sinking fund mechanism. See Note 13 of Notes to 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 Financial Statements in Item 8 for additional
information about the ACC retail electric competition rules and the legal
challenges to these rules.
16
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to
Financial Statements in Item 8 for a discussion of the insurance maintained by
the Palo Verde participants, including us, for Palo Verde.
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 5, 8, and 9 of Notes to Financial Statements in Item 8 with
respect to our property not held in fee or held subject to any major
encumbrance.
17
[MAP PAGE]
In accordance with Item 304 of Regulation S-T of the Securities Exchange
Act of 1934, our Service Territory map contained in this Form 10-K is a map of
the State of Arizona showing the Company's service area, the location of its
major power plants and principal transmission lines, and the location of
transmission lines operated by the Company 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. The
Company's 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.
18
ITEM 3. LEGAL PROCEEDINGS
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 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. We
are 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 us 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
Financial Statements in Item 8 for a discussion of competition and the ACC
retail electric competition rules and related litigation. In December 1999, we
filed a lawsuit to protect our legal rights regarding the rules, and in the
complaint we 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, we filed two lawsuits to protect
our legal rights under the stranded cost order and in our complaints we 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.
We are a party to a power service agreement with Citizens Communications Company
under which we supply Citizens with power. By letter dated March 7, 2001,
Citizens advised us that it believes we have overcharged Citizens by over $50
million under the agreement since the summer of 2000. We believe that our
charges to Citizens under the agreement are fully in accordance with the terms
of the agreement and we will vigorously defend any contrary claims raised by
Citizens.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
STOCK AND RELATED SECURITY HOLDER MATTERS
The Company's common stock is wholly-owned by Pinnacle West and is not
listed for trading on any stock exchange. As a result, there is no established
public trading market for the Company's common stock.
The chart below sets forth the dividends declared on the Company's common
stock for each of the four quarters for 2000 and 1999.
COMMON STOCK DIVIDENDS
(DOLLARS IN THOUSANDS)
QUARTER 2000 1999
------- ------- -------
1st Quarter $42,500 $42,500
2nd Quarter 42,500 42,500
3rd Quarter 42,500 42,500
4th Quarter 42,500 42,500
After payment or setting aside for payment of cumulative dividends and
mandatory sinking fund requirements, where applicable, on all outstanding issues
of preferred stock, the holders of common stock are entitled to dividends when
and as declared out of funds legally available therefor. See Note 5 of Notes to
Financial Statements in Item 8 for restrictions on retained earnings available
for the payment of common stock dividends.
20
ITEM 6. SELECTED FINANCIAL DATA
2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------
(Dollars in Thousands)
Electric operating revenues .................. $ 3,480,252 $ 2,292,798 $ 2,006,398 $ 1,878,553 $ 1,718,272
Fuel and purchased power ..................... 1,880,729 795,494 545,297 443,571 329,489
Operating expenses ........................... 1,148,628 1,108,380 1,090,290 1,063,157 1,023,575
----------- ----------- ----------- ----------- -----------
Operating income ........................... 450,895 388,924 370,811 371,825 365,208
Other income/(expense) ....................... (6,412) 20,990 20,448 21,586 35,217
Interest deductions -- net ................... 137,889 141,592 136,012 141,918 156,954
----------- ----------- ----------- ----------- -----------
Income before extraordinary charge ......... 306,594 268,322 255,247 251,493 243,471
Extraordinary charge - net of tax .......... -- 139,885 -- -- --
----------- ----------- ----------- ----------- -----------
Net income ................................. 306,594 128,437 255,247 251,493 243,471
Preferred dividends ........................ -- 1,016 9,703 12,803 17,092
----------- ----------- ----------- ----------- -----------
Earnings for common stock .................. $ 306,594 $ 127,421 $ 245,544 $ 238,690 $ 226,379
=========== =========== =========== =========== ===========
Total Assets ................................. $ 6,399,715 $ 6,117,624 $ 6,393,299 $ 6,331,142 $ 6,423,222
=========== =========== =========== =========== ===========
Capital Structure:
Common stock equity ........................ $ 2,119,768 $ 1,983,174 $ 1,975,755 $ 1,849,324 $ 1,729,390
Non-redeemable preferred stock ............. -- -- 85,840 142,051 165,673
Redeemable preferred stock ................. -- -- 9,401 29,110 53,000
Long-term debt less current maturities...... 1,806,908 1,997,400 1,876,540 1,953,162 2,029,482
----------- ----------- ----------- ----------- -----------
Total capitalization ..................... 3,926,676 3,980,574 3,947,536 3,973,647 3,977,545
Commercial paper ........................... 82,100 38,300 178,830 130,750 16,900
Current maturities of long-term debt........ 250,266 114,711 164,378 104,068 153,780
----------- ----------- ----------- ----------- -----------
Total .................................... $ 4,259,042 $ 4,133,585 $ 4,290,744 $ 4,208,465 $ 4,148,225
=========== =========== =========== =========== ===========
See "Financial Review" in Item 7 for a discussion of certain information in
the foregoing table.
21
ITEM 7. FINANCIAL REVIEW
INTRODUCTION
In this section, we explain the results of operations, general financial
condition, and outlook 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
We are Arizona's largest electric utility and provide retail and wholesale
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate and, directly or through Pinnacle
West's power marketing division, sell and deliver electricity to wholesale
customers in the western United States. Pinnacle West owns all of our
outstanding common stock.
Throughout this Financial Review, we refer to specific "Notes" in the Notes
to Financial Statements that begin on page 42. These Notes add further details
to the discussion.
RESULTS OF OPERATIONS
2000 COMPARED WITH 1999
Our 2000 earnings were $307 million compared with $127 million in 1999. Our
2000 earnings increased $180 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. See
"Regulatory Agreements" below and Notes 1 and 3 for additional information about
the 1999 Settlement Agreement and the resulting regulatory disallowance.
Earnings excluding the extraordinary charge increased $39 million, or 15%,
over 1999 primarily because of increases in wholesale and retail electric sales.
These positive factors more than offset decreases resulting from the completion
of investment tax credit (ITC) amortization in 1999, reductions in retail
electricity prices and miscellaneous factors. See "Regulatory Agreements" below
and Note 3 for information on the price reductions. See "Regulatory Agreements"
below and Note 10 for additional information about ITC amortization.
In 2000, electric operating revenues increased $1.2 billion primarily
because of:
22
* increased wholesale revenues ($1.1 billion);
* increases in the number of retail electricity customers and the
average amount of electricity used by customers ($98 million); and
* weather impacts ($33 million).
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 operations and maintenance expenses, which primarily
related to customer growth, was substantially offset by $19 million of
non-recurring items recorded in 1999.
1999 COMPARED WITH 1998
Our 1999 earnings were $127 million compared with $246 million in 1998. Our
1999 earnings decreased $119 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. See
"Regulatory Agreements" below and Notes 1 and 3 for additional information about
the 1999 Settlement Agreement and the resulting regulatory disallowance.
Earnings excluding the extraordinary charge increased $21 million, or 9%,
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 $286 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 ($8 million).
As mentioned above, these positive factors were partially offset by the
effects of reductions in retail prices ($22 million).
23
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 $18 million primarily because
of $19 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.
REGULATORY AGREEMENTS
Regulatory agreements approved by the ACC affect the results of our
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 our regulatory
assets; and
* A 1994 settlement that accelerated the amortization of our deferred
ITCs.
1999 SETTLEMENT AGREEMENT
As part of the 1999 Settlement Agreement, we 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. We recorded this regulatory disallowance as a net
reduction of regulatory assets and reported it as a $140 million after-tax
extraordinary charge on the 1999 income statement.
Under the 1996 Regulatory Agreement, we were recovering substantially all
of our 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:
(dollars in millions)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
24
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, we reduced our 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). We also agreed
to share future cost savings with our 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, we accelerated amortization of
substantially all of our ITCs over a five-year period that ended on December 31,
1999. The amortization of ITCs decreased annual income tax expense by about $28
million. Beginning in 2000, no further benefits were reflected in income tax
expense related to the acceleration of the ITCs (see Note 10).
CAPITAL NEEDS AND RESOURCES
CAPITAL RESOURCES AND CASH REQUIREMENTS
Our capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. We pay for our capital
requirements with cash from operations and, to the extent necessary, external
financing.
During the period from 1998 through 2000, we paid for substantially all of
our capital expenditures with cash from operations. We expect to do so in 2001
through 2003, as well.
Our capital expenditures in 2000 were $472 million. Our projected capital
expenditures for the next three years are: $455 million in 2001; $401 million in
2002; and $294 million in 2003. These amounts include about $30 - $35 million
each year for nuclear fuel. In general, most of our projected capital
expenditures are for:
* expanding transmission and distribution capabilities to serve growing
customer needs;
* upgrading existing utility property; and
* environmental purposes.
25
During 2000, we redeemed approximately $357 million of long-term debt,
including premiums, with cash from operations and from the issuance of long- and
short-term debt. Our long-term debt redemption requirements for the next three
years are approximately: $380 million in 2001; $125 million in 2002; and zero in
2003. We made optional redemptions of about $13 million of long-term debt in
February 2001. Based on market conditions and optional call provisions, we may
make optional redemptions of long-term debt from time to time.
As of December 31, 2000, we had credit commitments from various banks
totaling about $250 million, which were available either to support the issuance
of commercial paper or to be used as bank borrowings. At the end of 2000, we had
about $82 million of commercial paper and no long-term bank borrowings
outstanding.
Our long-term debt was $2.1 billion at December 31, 2000 and 1999.
Although provisions in our first mortgage bond indenture and ACC financing
orders establish maximum amounts of additional first mortgage bonds that we may
issue, we do not expect any of these provisions to limit our ability to meet our
capital requirements.
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.
We prepare our financial statements in accordance with Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated
enterprise to reflect the impact of regulatory decisions in its financial
statements. As a result of the 1999 Settlement Agreement (see "Regulatory
Agreements" above and Note 3), we discontinued the application of SFAS No. 71
for our generation operations. As a result, we tested the generation assets for
impairment and determined that the generation assets were not impaired. Pursuant
to the 1999 Settlement Agreement, we reported a regulatory disallowance ($140
million after income taxes) as an extraordinary charge on the 1999 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.
26
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 Arizona Corporation Commission (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 us, 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. We received a waiver in the 1999 Settlement Agreement to allow
the transfer of our 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 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, we are 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
us to seek adjustment of these rates in the event of emergency conditions or
circumstances, such as the inability to secure financing on reasonable terms, or
material changes in our 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 our current retail rates. We expect 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 we are able to obtain an adjustment of our
rates under the 1999 Settlement Agreement, there can be no assurance that we
would be able to fully recover the costs of this power.
As discussed in Note 3 of Notes to Financial Statements in Item 8, the 1999
Settlement authorizes us to transfer our competitive generation assets and
services to one or more corporate affiliates no later than December 31, 2002. We
intend to move our generation assets to Pinnacle West Energy within that
timeframe. Following its receipt of these generation assets,
27
Pinnacle West Energy expects to sell its power at wholesale to Pinnacle West's
power marketing division (Power Marketing). Power Marketing, in turn, is
expected to sell power to us and to non-affiliated power purchasers. We expect
to meet fifty percent of our energy needs under a power purchase agreement with
Power Marketing. As required by the Rules, we will acquire the remaining fifty
percent of our energy needs through a competitive bid process in which Power
Marketing may participate. We believe that these arrangements will allow us to
manage our exposure to the wholesale power market during the period within which
our 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, we must seek, and the
other parties to the 1999 Settlement Agreement must support, a waiver of the
Rules in favor of the 1999 Settlement Agreement. 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 in
Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The
1999 Settlement Agreement was not at issue in the consolidated cases before the
judge. Further, the ACC made findings related to the fair value of our property
in the order approving the 1999 Settlement Agreement. The ACC and other parties
aligned with the ACC have appealed the ruling to the 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 our 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.
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.
28
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.
CALIFORNIA ENERGY MARKET ISSUES
Southern California Edison (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. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with 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 the regional energy market
in general.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona, and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer, as well as electricity prices and
variations in weather from period to period.
In our regulated retail market area, we 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 our 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 our 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.
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.
29
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, and changes in
regulatory asset amortization. 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
additions to existing facilities.
Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt.
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.
30
Expected Maturity/Principal Repayment
December 31, 2000
(dollars in thousands)
Short-Term Variable Long-Term Fixed Long-Term
------------------ ------------------ ------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
----- ---------- ----- ---------- ----- ----------
2001 6.64% $ 82,100 7.33% $ 250,000 7.75% $ 266
2002 -- 8.13% 125,000
2003 -- 7.75% 443
2004 -- 6.17% 205,000
2005 -- 7.28% 400,000
Years thereafter -- 4.06% 476,860 7.48% 605,598
---------- ---------- ----------
Total $ 82,100 $ 726,860 $1,336,307
========== ========== ==========
Fair value $ 82,100 $ 726,860 $1,393,251
========== ========== ==========
Expected Maturity/Principal Repayment
December 31, 1999
(dollars in thousands)
Short-Term Variable Long-Term Fixed Long-Term
------------------ ------------------ ------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
----- ---------- ----- ---------- ----- ----------
2000 5.33% $ 38,300 $ 5.79% $ 114,711
2001 -- -- 6.85% 250,000 7.48% 2,488
2002 -- -- 8.13% 125,000
2003 -- -- 5.50% 50,000
2004 -- -- 6.17% 205,000
Years thereafter -- -- 3.15% 476,860 7.87% 895,148
---------- ---------- ----------
Total $ 38,300 $ 776,860 $1,342,347
========== ========== ==========
Fair value $ 38,300 $ 776,860 $1,312,423
========== ========== ==========
COMMODITY PRICE RISK
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances/credits. In addition, subject to specified risk parameters, we engage
in trading activities intended to profit from market price movements. In
accordance with Emerging Issues Task Force (EITF) 98-10, "Accounting for
contracts involved in energy trading and risk management activities," such
trading positions
31
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; our ability to compete successfully outside traditional
regulated markets (including the wholesale market); and technological
developments in the electric industry.
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.
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
Report of Management........................................................ 34
Independent Auditors' Report................................................ 35
Statements of Income for 2000, 1999 and 1998................................ 37
Balance Sheets as of December 31, 2000 and 1999............................. 38
Statements of Cash Flows for 2000, 1999 and 1998............................ 40
Statements of Retained Earnings for 2000, 1999 and 1998..................... 41
Notes to Financial Statements............................................... 42
See Note 14 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.
33
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.
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 Pinnacle West Capital Corporation
34
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 2000 and 1999 and the related statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 2000. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Arizona Public Service Company at December
31, 2000 and 1999 and the results of its operations and its 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.
Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 9, 2001
35
[THIS PAGE INTENTIONALLY LEFT BLANK.]
36
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
Year Ended December 31,
-------------------------------------------
2000 1999 1998
----------- ----------- -----------
(Dollars in Thousands)
Electric Operating Revenues .................. $ 3,480,252 $ 2,292,798 $ 2,006,398
----------- ----------- -----------
Fuel Expenses:
Fuel for electric generation ............... 333,265 243,849 231,967
Purchased power ............................ 1,547,464 551,645 313,330
----------- ----------- -----------
Total................................. 1,880,729 795,494 545,297
----------- ----------- -----------
Operating Revenues Less Fuel Expenses ........ 1,599,523 1,497,304 1,461,101
----------- ----------- -----------
Other Operating Expenses:
Operations and maintenance excluding
fuel expenses ............................ 430,696 437,729 419,433
Depreciation and amortization (Note 1)...... 388,660 382,057 376,574
Income taxes (Note 10) ..................... 229,542 192,015 192,207
Other taxes ................................ 99,730 96,579 102,076
----------- ----------- -----------
Total................................. 1,148,628 1,108,380 1,090,290
----------- ----------- -----------
Operating Income ............................. 450,895 388,924 370,811
----------- ----------- -----------
Other Income (Deductions):
Income taxes (Note 10) ..................... 4,225 32,527 32,751
Other -- net ............................... (10,637) (11,537) (12,303)
----------- ----------- -----------
Total................................. (6,412) 20,990 20,448
----------- ----------- -----------
Income Before Interest Deductions ............ 444,483 409,914 391,259
----------- ----------- -----------
Interest Deductions:
Interest on long-term debt ................. 134,431 132,676 137,214
Interest on short-term borrowings .......... 7,455 8,272 7,481
Debt discount, premium and expense ......... 6,897 7,323 7,580
Capitalized interest ....................... (10,894) (6,679) (16,263)
----------- ----------- -----------
Total................................. 137,889 141,592 136,012
----------- ----------- -----------
Income Before Extraordinary Charge ........... 306,594 268,322 255,247
Extraordinary Charge - net of income taxes
of $94,115 (Note 1) ........................ -- 139,885 --
----------- ----------- -----------
Net Income ................................... 306,594 128,437 255,247
Preferred Stock Dividend Requirements ........ -- 1,016 9,703
----------- ----------- -----------
Earnings for Common Stock .................... $ 306,594 $ 127,421 $ 245,544
=========== =========== ===========
See Notes to Financial Statements.
37
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS
December 31,
-----------------------------
2000 1999
----------- -----------
(Dollars in Thousands)
Utility Plant (Notes 5, 8 and 9):
Electric plant in service and held for future use...... $ 7,805,025 $ 7,545,575
Less accumulated depreciation and amortization ........ 3,187,328 3,026,041
----------- -----------
Total ........................................... 4,617,697 4,519,534
Construction work in progress ......................... 245,749 184,764
Nuclear fuel, net of amortization of $61,256
and $66,357 ......................................... 47,389 49,114
----------- -----------
Utility Plant -- net............................. 4,910,835 4,753,412
----------- -----------
Investments and Other Assets (Note 13) .................. 269,678 208,457
----------- -----------
Current Assets:
Cash and cash equivalents ............................. 2,609 7,477
Accounts receivable:
Service customers ................................... 422,012 201,704
Other ............................................... 48,711 35,684
Allowance for doubtful accounts ..................... (2,380) (1,538)
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 10) ....................... 5,793 8,163
Other ................................................. 55,920 30,885
----------- -----------
Total Current Assets ............................ 698,602 447,140
----------- -----------
Deferred Debits:
Regulatory assets (Note 1) ............................ 469,867 613,729
Unamortized debt issue costs .......................... 12,805 15,172
Other ................................................. 37,928 79,714
----------- -----------
Total Deferred Debits ........................... 520,600 708,615
----------- -----------
Total ........................................... $ 6,399,715 $ 6,117,624
=========== ===========
See Notes to Financial Statements.
38
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES
December 31,
---------------------------
2000 1999
---------- ----------
(Dollars in Thousands)
Capitalization (Notes 4 and 5):
Common stock ............................................. $ 178,162 $ 178,162
Additional paid - in capital ............................. 1,246,804 1,246,804
Retained earnings ........................................ 694,802 558,208
---------- ----------
Common stock equity ................................ 2,119,768 1,983,174
Long-term debt less current maturities ................... 1,806,908 1,997,400
---------- ----------
Total Capitalization ............................... 3,926,676 3,980,574
---------- ----------
Current Liabilities:
Commercial paper (Note 6) ................................ 82,100 38,300
Current maturities of long-term debt (Note 5) ............ 250,266 114,711
Accounts payable ......................................... 267,999 170,662
Accrued taxes ............................................ 106,515 62,858
Accrued interest ......................................... 39,488 32,299
Customer deposits ........................................ 24,498 24,682
Other .................................................... 142,126 26,248
---------- ----------
Total Current Liabilities .......................... 912,992 469,760
---------- ----------
Deferred Credits and Other:
Deferred income taxes (Note 10) .......................... 1,110,437 1,178,085
Deferred investment tax credit (Note 10) ................. 4,570 4,839
Unamortized gain -- sale of utility plant (Note 9)........ 68,636 73,212
Customer advances for construction ....................... 40,694 38,150
Other .................................................... 335,710 373,004
---------- ----------
Total Deferred Credits and Other ................... 1,560,047 1,667,290
---------- ----------
Commitments and Contingencies (Notes 3, 12, 13)
Total .............................................. $6,399,715 $6,117,624
========== ==========
See Notes to Financial Statements.
39
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
Year Ended December 31,
-----------------------------------------
2000 1999 1998
--------- --------- ---------
(Dollars in Thousands)
Cash Flows from Operations:
Net income ................................................ $ 306,594 $ 128,437 $ 255,247
Items not requiring cash:
Depreciation and amortization ............................ 388,660 382,057 376,574
Nuclear fuel amortization ................................ 30,083 31,371 32,856
Deferred income taxes - net .............................. (35,805) (29,654) (26,374)
Deferred investment tax credit - net ..................... (269) (27,626) (27,628)
Extraordinary Charge - net of income taxes ............... -- 139,885 --
Changes in certain current assets and liabilities:
Accounts receivable - net ................................ (232,493) (8,363) (56,490)
Accrued utility revenues ................................. (1,647) (5,179) (9,181)
Materials, supplies and fossil fuel ...................... 475 (8,794) (2,797)
Other current assets ..................................... (25,035) (4,190) (2,166)
Accounts payable ......................................... 101,558 22,992 33,731
Accrued taxes ............................................ 43,657 3,031 (26,059)
Accrued interest ......................................... 7,189 1,081 (442)
Other current liabilities ................................ 115,694 7,833 (4,654)
Other - net ............................................... 11,176 (4,922) (29,641)
--------- --------- ---------
Net cash provided .................................. 709,837 627,959 512,976
--------- --------- ---------
Cash Flows from Investing:
Capital expenditures ...................................... (464,368) (322,547) (319,142)
Capitalized interest ...................................... (10,894) (6,679) (16,263)
Other ..................................................... (58,355) (8,173) (8,593)
--------- --------- ---------
Net cash used ...................................... (533,617) (337,399) (343,998)
--------- --------- ---------
Cash Flows from Financing:
Issuance of long-term debt ................................ 300,000 392,952 126,245
Short-term borrowings - net ............................... 43,800 (140,530) 48,080
Common equity infusion from parent ........................ -- 50,000 50,000
Dividends paid on common stock ............................ (170,000) (170,000) (170,000)
Dividends paid on preferred stock ......................... -- (1,393) (10,279)
Repayment of preferred stock .............................. -- (96,499) (75,517)
Repayment and reacquisition of long-term debt ............. (354,888) (323,171) (144,501)
--------- --------- ---------
Net cash used ...................................... (181,088) (288,641) (175,972)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents........ (4,868) 1,919 (6,994)
Cash and cash equivalents at beginning of year ............. 7,477 5,558 12,552
--------- --------- ---------
Cash and cash equivalents at end of year ................... $ 2,609 $ 7,477 $ 5,558
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest (excluding capitalized interest) ............... $ 123,895 $ 132,995 $ 128,627
Income taxes ............................................ $ 222,866 $ 189,002 $ 235,475
See Notes to Financial Statements.
40
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
--------------------------------------
2000 1999 1998
-------- -------- --------
(Dollars in Thousands)
Retained earnings at beginning of year ............. $558,208 $601,968 $528,798
Add: Net income .................................... 306,594 128,437 255,247
-------- -------- --------
Total ...................................... 864,802 730,405 784,045
-------- -------- --------
Deduct:
Dividends:
Common stock (Notes 4 and 5) ................... 170,000 170,000 170,000
Preferred stock (at required rates) (Note 4).... -- 1,016 9,703
Other ............................................ -- 1,181 2,374
-------- -------- --------
Total deductions ........................... 170,000 172,197 182,077
-------- -------- --------
Retained earnings at end of year ................... $694,802 $558,208 $601,968
======== ======== ========
See Notes to Financial Statements.
41
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
We are Arizona's largest electric utility. We provide retail and wholesale
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate and, directly or through Pinnacle
West's power marketing division, sell and deliver electricity to wholesale
customers in the western United States.
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
We are regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.
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.
Accordingly, 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 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:
42
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(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 10) 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 Note16):
(dollars in thousands)
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 .................... 86,329 67,306
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 our
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.
43
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
CAPITALIZED INTEREST
Capitalized interest represents the cost of debt funds used to finance
construction of utility plants. Plant construction costs, including capitalized
interest, are expensed through depreciation when completed projects are placed
into commercial operation. Capitalized interest does not represent current cash
earnings. The rate used to calculate capitalized interest was a composite rate
of 6.62% 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.
NUCLEAR FUEL
We charge nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method that is based on
actual physical usage. We divide the cost of the fuel by the estimated number of
thermal units that we expects to produce with that fuel. We then multiply that
rate by the number of thermal units that we produce within the current period.
This calculation determines the current period nuclear fuel expense.
We also charge nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The United States Department of Energy (DOE) is responsible for
the permanent disposal of spent nuclear fuel, and it charges us $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.
REACQUIRED DEBT COSTS
For debt related to the regulated portion of our business, we amortize
those gains and losses incurred upon early retirement over the remaining life of
the debt. In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate reacquired debt costs over an eight-year period that will end June
30, 2004. The accelerated portion of the regulatory asset amortization is
included in depreciation and amortization expense in the Statements of Income.
44
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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, 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.
CASH AND CASH EQUIVALENTS
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.
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 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
45
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 conclude on 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 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. The contracts we are referring to here
are not trading contracts, which we already measure at fair value (mark to
market) as discussed in Note 1.
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 provide contrary guidance, we may be required to mark
certain 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, we 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
46
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
bringing the lawsuits appealed the ACC's order approving our 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:
* We have reduced, and will reduce, rates for standard offer service for
customers with loads less than three megawatts (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 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 us for competitive direct access service
(for example, distribution services) became effective upon approval of the
1999 Settlement Agreement, retroactive to July 1, 1999, and also became
subject to annual reductions beginning January 1, 2000, that vary by rate
class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard offer and
unbundled competitive direct access services until July 1, 2004, except for
the price reductions described above and certain other limited
circumstances. Neither the ACC nor we will be prevented from seeking or
authorizing rate changes prior to July 1, 2004 in the event of conditions
or circumstances that constitute an emergency, such as an inability to
finance on reasonable terms, or material changes in our cost of service for
ACC-regulated services resulting from federal, tribal, state or local laws,
regulatory requirements, judicial decisions, actions or orders.
* We 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.
* Our distribution system opened for retail access effective September 24,
1999. Customers were eligible for retail access in accordance with the
phase-in adopted by the ACC under the electric competition rules (see
"Retail Electric Competition Rules" below), including an additional 140 MW
being made available to eligible non-residential customers. We opened our
distribution system to retail access for all customers on January 1, 2001.
* Prior to the 1999 Settlement Agreement, we were recovering substantially
all of our regulatory assets through July 1, 2004, pursuant to the 1996
regulatory agreement. In
47
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
addition, the 1999 Settlement Agreement states that we have demonstrated
that our allowable stranded costs, after mitigation and exclusive of
regulatory assets, are at least $533 million net present value. We will not
be allowed to recover $183 million net present value of the above amounts.
The 1999 Settlement Agreement provides that we 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.
* We will form a separate corporate affiliate or affiliates and transfer to
such affiliate(s) our 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, we plan to complete the move of such
assets and services to the parent company or to Pinnacle West Energy by the
end of 2002, as required. We will be allowed to defer and later collect,
beginning July 1, 2004, sixty-seven percent of our costs to accomplish the
required transfer of generation assets to an affiliate.
* When the 1999 Settlement Agreement approved by the ACC is no longer subject
to judicial review, we will move to dismiss all of our litigation pending
against the ACC as of the date we entered into the 1999 Settlement
Agreement. To protect our rights, we have 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,
we must seek, and the other parties to the 1999 Settlement Agreement must
support, a waiver of the Rules in favor of the 1999 Settlement Agreement. On
December 8, 1999, we filed a lawsuit to protect our 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 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
48
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
value of our property in the order approving the 1999 Settlement Agreement. The
ACC and other parties aligned with the ACC have appealed the ruling to the 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 us.
* Effective January 1, 2001 retail access was available to all of our
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, we
received a waiver to allow transfer of our 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 us. 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 the parent company infuse $200
million of common equity into us 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:
49
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
* Arizona's largest government-operated electric utility (Salt River
Project) and, at their option, smaller municipal electric systems must
(i) make at least 20% of their 1995 retail peak demand available to
electric service providers by December 31, 1998 and for all retail
customers by December 31, 2000; (ii) decrease rates by at least 10%
over a ten-year period beginning as early as January 1, 1991; (iii)
implement procedures and public processes comparable to those already
applicable to public service corporations for establishing the terms,
conditions, and pricing of electric services as well as certain other
decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt
River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive
basis during the first two years of competition only for customers
having demands in excess of one MW (and that are eligible for
competitive generation services), and thereafter for all customers
receiving competitive electric generation.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.
FEDERAL
The 1992 Energy Act and recent rulemakings by FERC have promoted increased
competition in the wholesale energy markets. We do not expect these rules to
have a material impact on our 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.
50
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
4. COMMON AND PREFERRED STOCKS
On March 1, 1999, we redeemed all of our preferred stock. Common stock
balances at December 31, 2000 and 1999 are shown below:
Number
of Shares Par Par Value
Outstanding Value Outstanding
------------------------- Per --------------------
Authorized 2000 1999 Share 2000 1999
----------- ----------- ----------- ----- -------- --------
(dollars in thousands)
Common Stock.... 100,000,000 71,264,947 71,264,947 $2.50 $178,162 $178,162
=========== =========== ======== ========
Preferred Stock:
Redeemable preferred stock transactions during each of the three years in the
period ended December 31, 2000 are as follows:
Number of Shares Par Value
Outstanding Outstanding
------------------------------ --------------------------------
(dollars in thousands)
Description 2000 1999 1998 2000 1999 1998
- ----------- -------- -------- -------- -------- -------- --------
Balance, January 1........ -- 94,011 291,098 $ -- $ 9,401 $ 29,110
Retirements:
$10.00 Series U....... -- (94,011) (197,087) -- (9,401) (19,709)
$7.875 Series V....... -- -- -- --
-------- -------- -------- -------- -------- --------
Balance, December 31...... -- -- 94,011 $ -- $ -- $ 9,401
======== ======== ======== ======== ======== ========
5. LONG-TERM DEBT
Borrowings under our mortgage bond indenture are secured by substantially
all utility plant; we also have unsecured debt. The following table presents the
components of long-term debt outstanding at December 31, 2000 and December 31,
1999:
51
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
December 31,
-----------------------
Maturity Interest
Dates (a) Rates 2000 1999
--------- ----- ---------- ----------
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 --
---------- ----------
Total long-term debt 2,057,174 2,112,111
Less current maturities 250,266 114,711
---------- ----------
Total long-term debt less current
maturities $1,806,908 $1,997,400
========== ==========
- ----------
(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.
52
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(c) The weighted-average rate for the year ended December 31, 2000 was 7.33%
and for December 31, 1999 was 6.8525%.
(d) We currently have outstanding $84 million of first mortgage bonds (senior
note mortgage bonds) issued to the senior note trustee as collateral for
the senior notes. The senior note mortgage bonds have the same interest
rate, interest payment dates, maturity, and redemption provisions as the
senior notes. Our payments of principal, premium, and/or interest on the
senior notes satisfy our corresponding payment obligations on the senior
note mortgage bonds. As long as the senior note mortgage bonds secure the
senior notes, the senior notes will effectively rank equally with the first
mortgage bonds. When we repay all of our first mortgage bonds, other than
those that secure senior notes, the senior note mortgage bonds will no
longer secure the senior notes and will cease to be outstanding.
(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 9).
The following is a list of principal payments due on total long-term debt
and sinking fund requirements through 2005:
(dollars in millions)
Year Amount
------ ------
2001 $ 250
2002 125
2003 --
2004 205
2005 400
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.
6. LINES OF CREDIT
We 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. We have no long-term bank
borrowings at December 31, 2000 and $50 million outstanding at December 31,
1999.
Our 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
53
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 1999. By Arizona statute, our short-term borrowings cannot exceed
7% of our total capitalization unless approved by the ACC.
7. 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.
The carrying value of our long-term debt (excluding a capitalized lease
obligation) was $2.06 billion on December 31, 2000, with an estimated fair value
of $2.11 billion. On December 31, 1999, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.10 billion, with an estimated
fair value of $2.08 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.
8. JOINTLY-OWNED FACILITIES
We share ownership of some of our generating and transmission facilities
with other companies. The following table shows our interest in those
jointly-owned facilities at December 31, 2000. Our share of operating and
maintaining these facilities is included in the income statement in operations
and maintenance expense.
54
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Percent Construction
Owned by Plant in Accumulated Work in
Company Service Depreciation Progress
-------- ---------- ------------ --------
(dollars in thousands)
Generating Facilities:
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 9) 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 we operate the unit for them. The common
facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
9. LEASES
In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain
common facilities in three separate sale leaseback transactions. We account for
these leases as operating leases. The gain 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, we are continuing to
accelerate amortization of the regulatory asset for leases over an eight-year
period that will end June 30, 2004 (see Note 1). The accelerated amortization is
included in depreciation and amortization expense on
55
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
the Statements of Income. The balance of this regulatory asset at December 31,
2000 was $33 million.
In December 2000, we 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 $53 million in 2000, $49 million in 1999, and $52
million in 1998.
Estimated future minimum lease commitments, are approximately $64 million
for each of the years 2001 to 2005 and $613 million thereafter.
10. INCOME TAXES
INCOME TAXES
We are included in Pinnacle West's consolidated tax return. However, when
Pinnacle West allocates income taxes to us, it does so based on our taxable
income or loss alone. Because of a 1994 rate settlement agreement, we
accelerated amortization of substantially all of our ITCs over a five-year
period (1995-1999).
Certain assets and liabilities are reported differently for income tax
purposes than they are for financial statements. The tax effect of these
differences is recorded as deferred taxes. We calculate deferred taxes using the
current income tax rates.
We have recorded a regulatory asset related to income taxes on our Balance
Sheet in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. We amortize this amount as the differences reverse. In accordance
with the 1999 Settlement Agreement, we are continuing to accelerate our
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:
56
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
Year Ended December 31,
-----------------------------------
2000 1999 1998
--------- --------- ---------
Current
Federal $ 211,139 $ 175,227 $ 170,806
State 50,252 41,541 42,652
--------- --------- ---------
Total current 261,391 216,768 213,458
Deferred (35,805) (29,654) (26,374)
ITC amortization (269) (27,626) (27,628)
--------- --------- ---------
Total expense $ 225,317 $ 159,488 $ 159,456
========= ========= =========
The following chart compares pretax income at the 35% federal income tax
rate to income tax expense:
(dollars in thousands)
Year Ended December 31,
-----------------------------------
2000 1999 1998
--------- --------- ---------
Federal income tax expense at 35%
statutory rate $ 186,169 $ 149,710 $ 145,146
Increases (reductions) in tax expense
resulting from:
Tax under book depreciation 12,328 14,575 17,848
ITC amortization (269) (27,626) (27,628)
State income tax net of federal income
tax benefit 23,714 24,135 23,024
Other 3,375 (1,306) 1,066
--------- --------- ---------
Income tax expense $ 225,317 $ 159,488 $ 159,456
========= ========= =========
57
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 122,019 139,518
---------- ----------
Total deferred tax assets 149,075 168,964
---------- ----------
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 $1,104,644 $1,169,922
========== ==========
11. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLANS
Through 1999, we sponsored defined benefit pension plans for our employees.
As of January 1, 2000, this plan is sponsored by Pinnacle West. In 2000, we
represent 71% of the total cost of this plan. A defined benefit plan specifies
the amount of benefits a plan participant is to receive using information about
the participant. The 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
* $10 million in 1998.
58
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The following table shows the components of net pension cost before
consideration of amounts capitalized or billed to others:
(dollars in thousands)
2000 1999 1998
-------- -------- --------
Service cost - benefits earned during the period $ 24,197 $ 24,266 $ 24,126
Interest cost on projected benefit obligation 57,785 52,208 50,863
Expected return on plan assets (76,524) (67,528) (53,883)
Amortization of:
Transition asset (3,198) (3,216) (3,216)
Prior service cost 2,059 2,063 2,063
Net actuarial gain (1,617) -- --
-------- -------- --------
Net periodic pension cost $ 2,702 $ 7,793 $ 19,953
======== ======== ========
The following table shows a reconciliation of the funded status of the
plans to the amounts recognized in the balance sheets:
(dollars in thousands)
2000 1999
-------- --------
Fund status - pension plan assets more than (less than)
projected benefit obligation $(22,438) $ 37,784
Unrecognized net transition asset (16,745) (19,943)
Unrecognized prior service cost 18,440 20,499
Unrecognized net actuarial gains (20,075) (99,602)
-------- --------
Net pension liability recognized in the balance sheets $(40,818) $(61,262)
======== ========
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)
2000 1999
-------- --------
Projected pension benefit obligation at beginning of year $732,911 $721,229
Service cost 24,197 24,266
Interest cost 57,785 52,208
Benefit payments (30,498) (29,444)
Actuarial (gains)/losses 3,461 (35,348)
-------- --------
Projected pension benefit obligation at end of year $787,856 $732,911
======== ========
59
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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 $ 770,695 $ 682,272
Actual return on plan assets 1,830 92,867
Employer contributions 23,391 25,000
Benefit payments (30,498) (29,444)
--------- ---------
Fair value of pension plan assets at end of year $ 765,418 $ 770,695
========= =========
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%
EMPLOYEE SAVINGS PLAN BENEFITS
Through 1999, we sponsored defined contribution savings plans for our
employees. As of January 1, 2000, this plan is sponsored by Pinnacle West. In
2000, we represent 92% of the total cost of this plan. 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 $3 million for 2000 and $4 million for each of the years 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. In 2000, we represent
84% of the total cost of this plan.
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:
* $ 2 million for 2000;
* $ 6 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:
60
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
2000 1999 1998
-------- -------- --------
Service cost - benefits earned during the period $ 8,312 $ 8,676 $ 7,676
Interest cost on accumulated benefit obligation 19,169 17,188 15,610
Expected return on plan assets (22,381) (18,454) (12,001)
Amortization of:
Transition obligation 7,638 7,652 7,652
Net actuarial gains (7,931) (5,095) (2,927)
-------- -------- --------
Net periodic postretirement benefit cost $ 4,807 $ 9,967 $ 16,010
======== ======== ========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the balance sheets:
(dollars in thousands)
2000 1999
--------- ---------
Funded status - postretirement plan assets more than
(less than) projected benefit obligation $ (12,786) $ 27,930
Unrecognized net obligation at transition 91,844 99,482
Unrecognized net actuarial gains (79,596) (127,338)
--------- ---------
Net postretirement amount recognized in the balance
sheets $ (538) $ 74
========= =========
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 $ 229,608 $ 235,322
Service cost 8,312 8,675
Interest cost 19,169 17,188
Benefit payments (8,905) (8,761)
Actuarial (gains) losses 13,756 (22,816)
--------- ---------
Accumulated postretirement benefit obligation at
end of year $ 261,940 $ 229,608
========= =========
The following table sets forth the postretirement benefit plans' change in
the fair value of plan assets for the plan years 2000 and 1999:
61
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(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 4,957 9,914
Benefit payments (8,905) (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%
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 42 (34)
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
We are a party to a power service agreement with Citizens Communications
Company (Citizens) under which we supply Citizens with power. By letter dated
March 7, 2001, Citizens advised us that it believes we have overcharged Citizens
by over $50 million under the agreement since the summer of 2000. We believe
that our charges to Citizens under the agreement are fully in accordance with
the terms of the agreement and will vigorously defend any contrary claims raised
by Citizens.
62
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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
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.
We have existing fuel storage pools at Palo Verde and are in the process of
completing construction of a new facility for on-site dry storage of spent fuel.
With the existing storage pools and the addition of the new facility, we believe
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, we are currently shipping low-level waste to off-site facilities. We
currently believe that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
We currently estimate that we will incur $113 million (in 2000 dollars)
over the life of Palo Verde for our share of the costs related to the on-site
interim storage of spent nuclear fuel. As of December 31, 2000, we have 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, we could be
assessed retrospective premium adjustments. The maximum assessment per reactor
under the program for each nuclear incident is approximately $88 million,
subject to an annual limit of $10 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.
63
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
FUEL AND PURCHASED POWER COMMITMENTS
We are a party to various fuel and purchased power contracts with terms
expiring from 2001 through 2021 that include required purchase provisions. We
estimate our 2001 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 us to decrease our required purchases
under certain circumstances.
We must reimburse certain coal providers for amounts incurred for coal mine
reclamation. We estimate our 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, we
are continuing to accelerate the amortization of the regulatory asset for coal
mine reclamation over an eight-year period that will end June 30, 2004.
Amortization is included in depreciation and amortization expense on the
Statements of Income. 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. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with 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 the regional market in
general.
64
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
CONSTRUCTION PROGRAM
Total capital expenditures in 2001 are estimated at $455 million.
13. NUCLEAR DECOMMISSIONING COSTS
We recorded $11 million for nuclear decommissioning expense in each of the
years 2000, 1999, and 1998. We estimate it will cost about $1.8 billion ($493
million in 2000) to decommission our share of the three Palo Verde units. The
decommissioning costs are expected to be incurred over a 14-year period
beginning in 2024. We charge decommissioning costs to expense over each unit's
operating license term and includes them in the accumulated depreciation balance
until each unit is retired. Nuclear decommissioning costs are recovered in
rates.
Our current estimates are based on a 1998 site-specific study for Palo
Verde that assumes the prompt removal/dismantlement method of decommissioning.
An independent consultant prepared this study. We are required to update the
study every three years.
To fund the costs we expect to incur to decommission the plant, we
established external decommissioning trusts in accordance with NRC regulations.
The trust accounts are reported in investments and other assets on the Balance
Sheets at their market value of $205 million at December 31, 2000 and $176
million at December 31, 1999. We invest the trust funds primarily in fixed
income securities and domestic stock and classify them as available for sale.
Realized and unrealized gains and losses are reflected in accumulated
depreciation.
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)
Quarterly financial information for 2000 and 1999 is as follows:
65
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
2000
-------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Electric operating revenues $445,981 $719,394 $1,565,622 $749,255
Operating income (a) $ 66,094 $132,345 $ 160,646 $ 91,810
Net income and
Earnings for Common Stock $ 32,775 $ 95,851 $ 124,231 $ 53,737
(dollars in thousands)
1999
-------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Electric operating revenues $413,983 $511,434 $867,504 $499,877
Operating income (a) $ 66,956 $ 98,503 $150,914 $ 72,551
Net Income/(Loss) (b) $ 33,795 $ 69,542 $(10,377) $ 35,477
Earnings/(Loss) for Common
Stock $ 32,779 $ 69,542 $(10,377) $ 35,477
- ----------
(a) Our utility business is seasonal in nature, with the peak sales periods
generally occurring during the summer months. Comparisons among quarters of
a year may not represent overall trends and changes in operations.
(b) The quarter ending September 30, 1999 includes and extraordinary charge of
$139,885, net of income taxes of $94,115.
15. STOCK-BASED COMPENSATION
Pinnacle West offers two stock incentive plans for our 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.
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."
66
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
If we had recorded compensation expense based on the fair value method, our
net income would have been reduced to the following pro forma amounts:
(dollars in thousands)
2000 1999 1998
-------- -------- --------
Net income
As reported $306,594 $128,437 $255,247
Pro forma (fair value method) $305,610 $127,658 $254,640
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
16. 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). 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)
Generation Delivery Eliminations Total
---------- ---------- --------- ----------
Operating revenues $ 990,415 $3,480,252 $(990,415) $3,480,252
Operating expense 597,948 2,814,259 (990,415) 2,421,792
---------- ---------- --------- ----------
Operating margin 392,467 665,993 -- 1,058,460
Depreciation and Amortization 125,220 263,440 -- 388,660
Interest 41,808 96,081 -- 137,889
---------- ---------- --------- ----------
Pretax margin 225,439 306,472 -- 531,911
Income taxes 88,755 136,562 -- 225,317
---------- ---------- --------- ----------
Earnings for common stock $ 136,684 $ 169,910 $ -- $ 306,594
========== ========== ========= ==========
Total assets $2,377,499 $4,022,216 $ -- $6,399,715
========== ========== ========= ==========
Capital expenditures $ 186,521 $ 285,455 $ -- $ 471,976
========== ========== ========= ==========
67
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Business Segments For Year Ended December 31, 1999
(dollars in thousands)
Generation Delivery Eliminations Total
---------- ---------- ---------- ----------
Operating revenues $ 853,755 $2,292,798 $ (853,755) $2,292,798
Operating expense 522,925 1,672,169 (853,755) 1,341,339
---------- ---------- ---------- ----------
Operating margin 330,830 620,629 -- 951,459
Depreciation and Amortization 121,683 260,374 -- 382,057
Interest and preferred stock dividend
requirements
40,753 101,855 -- 142,608
---------- ---------- ---------- ----------
Pretax margin 168,394 258,400 -- 426,794
Income taxes 47,976 111,512 -- 159,488
Extraordinary charge - net
of income tax of $94,115
-- 139,885 -- 139,885
---------- ---------- ---------- ----------
Earnings for common stock $ 120,418 $ 7,003 $ -- $ 127,421
========== ========== ========== ==========
Total assets $2,371,014 $3,746,611 $ -- $6,117,624
========== ========== ========== ==========
Capital expenditures $ 90,285 $ 241,469 $ -- $ 331,754
========== ========== ========== ==========
Business Segments For Year Ended December 31, 1998
(dollars in thousands)
Generation Delivery Eliminations Total
---------- ---------- ---------- ----------
Operating revenues $ 858,340 $2,006,398 $ (858,340) $2,006,398
Operating expense 522,696 1,414,753 (858,340) 1,079,109
---------- ---------- ---------- ----------
Operating margin 335,644 591,645 -- 927,289
Depreciation and Amortization 135,406 241,168 -- 376,574
Interest and preferred stock
dividend requirements 37,045 108,670 -- 145,715
---------- ---------- ---------- ----------
Pretax margin 163,193 241,807 -- 405,000
Income taxes 49,969 109,487 -- 159,456
---------- ---------- ---------- ----------
Earnings for common stock $ 113,224 $ 132,320 $ -- $ 245,544
========== ========== ========== ==========
Total assets $2,399,560 $3,993,739 $ -- $6,393,299
========== ========== ========== ==========
Capital expenditures $ 85,767 $ 241,638 $ -- $ 327,405
========== ========== ========== ==========
68
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT
Not applicable.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
69
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS
See the Index to Financial Statements in Part II, Item 8.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION
- ----------- -----------
12.1 -- Computation of Ratio of Earnings to Fixed Charges
23.1 -- Consent of Deloitte & Touche LLP
In addition to those Exhibits shown above, the Company hereby incorporates
the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation
ss.229.10(d) by reference to the filings set forth below:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96
February 20, 1996 Report
3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95
Directors temporarily Report
suspending Bylaws in part
3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, 1988 Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report
4.1 Mortgage and Deed of Trust 4.1 to September 1992 1-4473 11-9-92
Relating to the Company's Form 10-Q Report
First Mortgage Bonds,
together with forty-eight
indentures supplemental
thereto
4.2 Forty-ninth Supplemental 4.1 to 1992 Form 10-K 1-4473 3-30-93
Indenture Report
70
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
4.3 Fiftieth Supplemental 4.2 to 1993 Form 10-K 1-4473 3-30-94
Indenture Report
4.4 Fifty-first Supplemental 4.1 to August 1, 1993 1-4473 9-27-93
Indenture Form 8-K Report
4.5 Fifty-second Supplemental 4.1 to September 30, 1993 1-4473 11-15-93
Indenture Form 10-Q Report
4.6 Fifty-third Supplemental 4.5 to Registration 1-4473 3-1-94
Indenture Statement No. 33-61228
by means of February 23,
1994 Form 8-K Report
4.7 Fifty-fourth Supplemental 4.1 to Registration 1-4473 11-22-96
Indenture Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996
Form 8-K Report
4.8 Fifty-fifth Supplemental 4.8 to Registration 1-4473 4-9-97
Indenture Statement Nos. 33-55473,
33-64455 and 333-15379
by means of April 7, 1997
Form 8-K Report
4.9 Agreement, dated March 21, 4.1 to 1993 Form 10-K 1-4473 3-30-94
1994, relating to the filing Report
of instruments defining the
rights of holders of long-term
debt not in excess of 10% of
the Company's total assets
4.10 Indenture dated as of January 4.6 to Registration 1-4473 1-11-95
1, 1995 among the Company Statement Nos. 33-61228
and The Bank of New York, and 33-55473 by means of
as Trustee January 1, 1995 Form 8-K
Report
4.11 First Supplemental Indenture 4.4 to Registration 1-4473 1-11-95
dated as of January 1, 1995 Statement Nos. 33-61228
and 33-55473 by means of
January 1, 1995 Form 8-K
Report
71
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
4.12 Indenture dated as of 4.5 to Registration 1-4473 11-22-96
November 15, 1996 among Statements Nos. 33-61228,
the Company and The Bank 33-55473, 33-64455 and
of New York, as Trustee 333-15379 by means of
November 19, 1996
Form 8-K Report
4.13 First Supplemental Indenture 4.6 to Registration 1-4473 11-22-96
Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996
Form 8-K Report
4.14 Second Supplemental Inden- 4.10 to Registration 1-4473 4-9-97
ture dated as of April 1, 1997 Statement Nos. 33-55473,
33-64455 and 333-15379
by means of April 7, 1997
Form 8-K Report
4.15 Indenture dated as of January 4.10 to Registration 1-4473 1-16-98
15, 1998 among the Company Statement Nos. 333-15379
and The Chase Manhattan and 333-27551 by means
Bank, as Trustee of January 13, 1998
Form 8-K Report
4.16 First Supplemental Indenture 4.3 to Registration 1-4473 1-16-98
dated as of January 15, 1998 Statement Nos. 333-15379
and 333-27551 by means
of January 13, 1998
Form 8-K Report
4.17 Second Supplemental 4.3 to Registration 1-4473 2-22-99
Indenture dated as of Statement Nos. 333-27551
February 15, 1999 and 333-58445 by means of
February 18, 1999
Form 8-K Report
4.18 Third Supplemental Indenture 4.5 to Registration 1-4473 11-5-99
dated as of November 1, 1999 Statement No. 333-58445
by means of November 2,
1999 Form 8-K Report
72
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
4.19 Fourth Supplemental Inden- 4.1 to Registration 1-4473 8-4-00
ture dated as of August 1, Statement Nos. 333-58445
2000 and 333-94277 by means
of August 2, 2000 Form
8-K Report
10.1 Two separate 10.2 to September 1991 1-4473 11-14-91
Decommissioning Trust Form 10-Q
Agreements (relating to
PVNGS Units 1 and 3,
respectively), each dated
July 1, 1991, between the
Company and Mellon Bank,
N.A., as Decommissioning
Trustee
10.2 Amendment No. 1 to 10.1 to 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 1)
dated as of December 1,
1994
10.3 Amendment No. 2 to 10.4 to 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS
Unit 1) dated as of
July 1, 1991
10.4 Amendment No. 1 to 10.2 to 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS
Unit 3) dated as of
December 1, 1994
10.5 Amendment No. 2 to 10.6 to 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS
Unit 3) dated as of
July 1, 1991
73
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.6 Amended and Restated 10.1 to Pinnacle West 1-8962 3-26-92
Decommissioning Trust 1991 Form 10-K Report
Agreement (PVNGS Unit 2)
dated as of January 31, 1992,
among the Company, Mellon
Bank, N.A., as Decommissioning
Trustee, and State Street Bank
and Trust Company, as successor
to The First National Bank of
Boston, as Owner Trustee under
two separate Trust Agreements,
each with a separate Equity
Participant, and as Lessor
under two separate Facility
Leases, each relating to an
undivided interest in PVNGS
Unit 2
10.7 First Amendment to Amended 10.2 to 1992 Form 10-K 1-4473 3-30-93
and Restated Report
Decommissioning Trust
Agreement (PVNGS
Unit 2), dated as of
November 1, 1992
10.8 Amendment No. 2 to 10.3 to 1994 Form 10-K 1-4473 3-30-95
Amended and Restated Report
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
November 1, 1994
10.9 Amendment No. 3 to 10.1 to June 1996 Form 1-4473 8-9-96
Amended and Restated 10-Q Report
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
January 31, 1992
74
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.10 Amendment No. 4 to 10.5 to 1996 Form 10-K 1-4473 3-28-97
Amended and Restated Report
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
January 31, 1992
10.11 Asset Purchase and Power 10.1 to June 1991 Form 1-4473 8-8-91
Exchange Agreement dated 10-Q Report
September 21, 1990 between
the Company and PacifiCorp,
as amended as of October 11,
1990 and as of July 18, 1991
10.12 Long-Term Power Trans- 10.2 to June 1991 Form 1-4473 8-8-91
actions Agreement dated 10-Q Report
September 21, 1990
between the Company and
PacifiCorp, as amended as
of October 11, 1990 and
as of July 8, 1991
10.13 Contract, dated July 21, 1984, 10.31 to Pinnacle West's 2-96386 3-13-85
with DOE providing for the Form S-14 Registration
disposal of nuclear fuel Statement
and/or high-level radioactive
waste, ANPP
10.14 Amendment No. 1 dated 10.3 to 1995 Form 10-K 1-4473 3-29-96
April 5, 1995 to the Long- Report
Term Power Transactions
Agreement and Asset Purchase
and Power Exchange Agree-
ment between PacifiCorp and
the Company
10.15 Restated Transmission 10.4 to 1995 Form 10-K 1-4473 3-29-96
Agreement between Report
PacifiCorp and the Company
dated April 5, 1995
75
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.16 Contract among PacifiCorp, 10.5 to 1995 Form 10-K 1-4473 3-29-96
the Company and United Report
States Department of Energy
Western Area Power
Administration, Salt Lake
Area Integrated Projects
for Firm Transmission
Service dated May 5, 1995
10.17 Reciprocal Transmission 10.6 to 1995 Form 10-K 1-4473 3-29-96
Service Agreement between Report
the Company and PacifiCorp
dated as of March 2, 1994
10.18 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Registration Statement
Four Corners Plant
10.19 Supplemental and Additional 5.02 to Form S-7 2-59644 9-1-77
Indenture of Lease, including Registration Statement
amendments and supplements
to original lease with Navajo
Tribe of Indians, Four
Corners Plant
10.20 Amendment and Supplement 10.36 to Registration 1-8962 7-25-85
No. 1 to Supplemental and Statement on Form 8-B of
Additional Indenture of Pinnacle West
Lease, Four Corners, dated
April 25,1985
10.21 Application and Grant of 5.04 to Form S-7 2-59644 9-1-77
multi-party rights-of-way Registration Statement
and easements, Four
Corners Plant Site
10.22 Application and Amendment 10.37 to Registration 1-8962 7-25-85
No. 1 to Grant of multi-party Statement on Form 8-B of
rights-of-way and easements, Pinnacle West
Four Corners Power Plant
Site, dated April 25, 1985
76
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.23 Four Corners Project 10.7 to Pinnacle West 1-8962 3-14-01
Co-Tenancy Agreement 2000 Form 10-K Report
Amendment No. 6
10.24 Application and Grant of 5.05 to Form S-7 2-59644 9-1-77
Arizona Public Service Registration Statement
Company rights-of-way
and easements, Four
Corners Plant Site
10.25 Application and Amendment 10.38 to Registration 1-8962 7-25-85
No. 1 to Grant of Arizona Statement on Form 8-B of
Public Service Company Pinnacle West
rights-of-way and easements,
Four Corners Power Plant
Site, dated April 25, 1985
10.26 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.27 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70
rights-of-way and ease- Registration Statement
ments, Navajo Plant
10.28 Water Service Contract 5(l) to Form S-7 2-39442 3-16-71
Assignment with the United Registration Statement
States Department of
Interior, Bureau of
Reclamation, Navajo Plant
10.29 Arizona Nuclear Power 10.1 to 1988 Form 10-K 1-4473 3-8-89
Project Participation Agree- Report
ment, dated August 23, 1973,
among the Company, Salt
River Project Agricultural
Improvement and Power
District, Southern California
Edison Company, Public
Service Company of New
Mexico, El Paso Electric
Company, Southern
California Public Power
Authority, and Department
of Water and Power of the
City of Los Angeles, and
amendments 1-12 thereto
77
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.30 Amendment No. 13 dated as 10.1 to March 1991 Form 1-4473 5-15-91
of April 22, 1991, to Arizona 10-Q Report
Nuclear Power Project Partici-
pation Agreement, dated
August 23, 1973, among
the Company, Salt River
Project Agricultural Improve-
ment and Power District,
Southern California Edison
Company, Public Service
Company of New Mexico,
El Paso Electric Company,
Southern California Public
Power Authority, and
Department of Water and
Power of the City of Los
Angeles
10.31 Amendment No. 14, to 10.4 to the Pinnacle West 1-8962 8-14-00
Arizona Nuclear Power June 30, 2000 Form 10-Q
Project Participation Report
Agreement, dated August
23, 1973, among the
Company, Salt River
Project Agricultural Improve-
ment and Power District,
Southern California Edison
Company, Public Service
Company of New Mexico,
El Paso Electric Company,
Southern California Public
Power Authority, and
Department of Water and
Power of the City of
Los Angeles
10.32c Facility Lease, dated as of 4.3 to Form S-3 33-9480 10-24-86
August 1, 1986, between Registration Statement
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and the Company, as Lessee
78
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.33c Amendment No. 1, dated as 10.5 to September 1986 1-4473 12-4-86
of November 1, 1986, to Form 10-Q Report by
Facility Lease, dated as of means of Amendment No.
August 1, 1986, between 1 on December 3, 1986
State Street Bank and Trust Form 8
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and the Company, as Lessee
10.34c Amendment No. 2 dated as 10.3 to 1988 Form 10-K 1-4473 3-8-89
of June 1, 1987 to Facility Report
Lease dated as of August 1,
1986between State Street
Bank and Trust Company,
as successor to The First
National Bank of Boston, as
Lessor, and APS, as Lessee
10.35c Amendment No. 3, dated as 10.3 to 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Facility Lease, dated as
of August 1, 1986, between
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Lessor, and the
Company, as Lessee
10.36 Facility Lease, dated as of 10.1 to November 18, 1986 1-4473 1-20-87
December 15, 1986, between Form 8-K Report
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and the Company, as Lessee
79
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.37 Amendment No. 1, dated as of 4.13 to Form S-3 1-4473 8-24-87
August 1, 1987, to Facility Registration Statement
Lease, dated as of December No. 33-9480 by means of
15, 1986, between State Street August 1, 1987 Form 8-K
Bank and Trust Company, as Report
successor to The First
National Bank of Boston, as
Lessor, and the Company, as
Lessee
10.38 Amendment No. 2, dated as 10.4 to 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Facility Lease, dated as
of December 15, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston,
as Lessor, and the Company,
as Lessee
10.39a Directors' Deferred 10.1 to June 1986 Form 1-4473 8-13-86
Compensation Plan, as 10-Q Report
restated, effective January 1,
1986
10.40a Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Directors'
Deferred Compensation
Plan, effective as of
January 1, 1993
10.41a Third Amendment to the 10.1 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q
Company Directors'
Deferred Compensation
Plan effective as of
May 1, 1993
10.42a Fourth Amendment dated 10.8 to Pinnacle West's 1-8962 3-30-00
December 28, 1999 to the 1999 Form 10-K
Arizona Public Service
Company Directors
Deferred Compensation
Plan
80
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.43a Arizona Public Service 10.4 to 1988 Form 10-K 1-4473 3-8-89
Company Deferred Report
Compensation Plan, as
restated, effective January
1, 1984, and the second and
third amendments thereto,
dated December 22, 1986, and
December 23, 1987, respectively
10.44a Third Amendment to the 10.3 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.45a Fourth Amendment to the 10.2 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q Report
Company Deferred
Compensation Plan effective
as of May 1, 1993
10.46a Fifth Amendment to the 10.3 to 1997 Form 10-K 1-4473 3-28-97
Arizona Public Service Report
Company Deferred
Compensation Plan
10.47a Sixth Amendment to 10.8 to Pinnacle West 1-8962 3-14-01
Arizona Public Service 2000 Form 10-K Report
Company Deferred
Compensation Plan
10.48a Pinnacle West Capital 10.10 to 1995 Form 10-K 1-4473 3-29-96
Corporation, Arizona Public Report
Service Company, SunCor
Development Company
and El Dorado Investment
Company Deferred
Compensation Plan as
amended and restated
effective January 1, 1996
81
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.49a First Amendment effective as 10.6 to Pinnacle West's 1-8962 3-30-00
of January 1, 1999, to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and
El Dorado Investment
Company Deferred Compen-
sation Plan
10.50a Second Amendment effective 10.10 to Pinnacle West's 1-8962 3-30-00
as of January 1, 2000, to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and
El Dorado Investment
Company Deferred Compen-
sation Plan
10.51a Pinnacle West Capital 10.13 to Pinnacle West's 1-8962 3-30-00
Corporation Supplemental 1999 Form 10-K Report
Excess Benefit Retirement
Plan, as amended and
restated, dated December 7,
1999
10.52a Pinnacle West Capital 10.7 to 1994 Form 10-K 1-4473 3-30-95
Corporation and Arizona Report
Public Service Company
Directors' Retirement Plan
effective as of January 1,
1995
10.53a Pinnacle West Capital 99.2 to Pinnacle West's 1-8962 7-3-00
Corporation and Arizona Registration Statement on
Public Service Company Form S-8 No. 333-40796
Directors' Retirement Plan,
as amended and restated on
June 21, 2000
10.54a Arizona Public Service 10.1 to September 1997 1-4473 11-12-97
Company Director Form 10-K Report
Equity Plan
82
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.55a Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95
December 21, 1993, between Report
the Company and William L.
Stewart
10.56a Letter Agreement dated 10.8 to 1996 Form 10-K 1-4473 3-28-97
August 16, 1996 between Report
the Company and
William L. Stewart
10.57a Letter Agreement between 10.2 to September 1997 1-4473 11-12-97
the Company and Form 10-Q Report
William L. Stewart
10.58a Letter Agreement dated 10.9 to Pinnacle West's 1-8962 3-30-00
December 13, 1999 between 1999 Form 10-K Report
the Company and
William L. Stewart
10.59a Letter Agreement dated as 10.8 to 1995 Form 10-K 1-4473 3-29-96
of January 1, 1996 between Report
the Company and Robert G.
Matlock & Associates, Inc.
for consulting services
10.60a Letter Agreement dated 10.17 to Pinnacle West's 1-8962 3-30-00
October 3, 1997 between 1999 Form 10-K Report
the Company and James M.
Levine
10.61ad Key Executive Employment 10.1 to Pinnacle West's 1-8962 8-16-99
and Severance Agreement June 1999 Form 10-Q
between Pinnacle West and Report
certain executive officers of
Pinnacle West and its
subsidiaries
10.62a Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option Report
and Incentive Plan
10.63a First Amendment dated 10.11 to Pinnacle West's 1-8962 3-30-00
December 7, 1999 to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation Stock Option
and Incentive Plan
83
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.64a Pinnacle West Capital A to the Proxy Statement 1-8962 4-16-94
Corporation 1994 Long- for the Plan Report
Term Incentive Plan Pinnacle West 1994
effective as of Annual Meeting of
March 23, 1994 Shareholders
10.65a First Amendment dated 10.12 to Pinnacle West's 1-8962 3-30-00
December 7, 1999, to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation 1994 Long-
Term Incentive Plan
10.66a Trust for the Pinnacle West 10.14 to Pinnacle West's 1-8962 3-30-00
Capital Corporation, Arizona 1999 Form 10-K Report
Public Service Company
and SunCor Development
Company Deferred
Compensation Plans
dated August 1, 1996
10.67a First Amendment dated 10.15 to Pinnacle West's 1-8962 3-30-00
December 7, 1999, to the 1999 Form 10-K Report
Trust for the Pinnacle West
Capital Corporation, Arizona
Public Service Company and
SunCor Development
Company Deferred
Compensation Plans
10.68a 2001 Management Variable 10.4 to Pinnacle West's 1-8962 3-14-01
Incentive Plan (APS) 1999 Form 10-K Report
10.69a 2001 Senior Management 10.5 to Pinnacle West's 1-8962 3-14-01
Variable Incentive Plan (APS) 1999 Form 10-K Report
10.70a 2001 Officer Variable 10.6 to Pinnacle West's 1-8962 3-14-01
Incentive Plan (APS) 1999 Form 10-K Report
84
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
10.71 Agreement No. 13904 (Option 10.3 to 1991 Form 10-K 1-4473 3-19-92
and Purchase of Effluent) Report
with Cities of Phoenix,
Glendale, Mesa, Scottsdale,
Tempe, Town of Youngtown,
and Salt River Project
Agricultural Improvement and
Power District, dated April 23,
1973
10.72 Agreement for the Sale and 10.4 to 1991 Form 10-K 1-4473 3-19-92
Purchase of Wastewater Report
Effluent with City of
Tolleson and Salt River
Agricultural Improvement
and Power District, dated
June 12, 1981,including
Amendment No. 1 dated
as of November 12, 1981
and Amendment No. 2
dated as of June 4, 1986
10.73 Territorial Agreement 10.1 to March 1998 1-4473 5-15-98
between the Company Form 10-Q Report
and Salt River Project
10.74 Power Coordination 10.2 to March 1998 1-4473 5-15-98
Agreement between Form 10-Q Report
the Company and Salt
River Project
10.75 Memorandum of Agreement 10.3 to March 1998 1-4473 5-15-98
between the Company and Form 10-Q Report
Salt River Project
10.76 Addendum to Memorandum 10.2 to May 19, 1998 1-4473 6-26-98
of Agreement between the Form 8-K Report
Company and Salt River
Project dated as of May
19, 1998
99.1 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93
among PVNGS II Funding Report
Corp., Inc., the Company and
Chemical Bank, as Trustee
85
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
99.2 Supplemental Indenture to 4.3 to 1992 Form 10-K 1-4473 3-30-93
Collateral Trust Indenture Report
among PVNGS II Funding
Corp., Inc., the Company and
Chemical Bank, as Trustee
99.3c Participation Agreement, 28.1 to September 1992 1-4473 11-9-92
dated as of August 1, 1986, Form 10-Q Report
among PVNGS Funding
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
99.4c Amendment No. 1 dated as 10.8 to September 1986 1-4473 12-4-86
of November 1, 1986, to Form 10-Q Report by
Participation Agreement, means of Amendment No.
dated as of August 1,1986, 1, on December 3, 1986
among PVNGS Funding Form 8
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
86
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
99.5c Amendment No. 2, dated as 28.4 to 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Participation Agreement,
dated as of August 1, 1986,
among PVNGS Funding
Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and
as Indenture Trustee, the
Company, and the Equity
Participant named therein
99.6c Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86
Security Agreement and Registration Statement
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.7c Supplemental Indenture No. 10.6 to September 1986 1-4473 12-4-86
1, dated as of November 1, Form 10-Q Report by
1986 to Trust Indenture, means of Amendment No.
Mortgage, Security Agree- 1 on December 3, 1986
ment and Assignment of Form 8
Facility Lease, dated as of
August 1, 1986, between
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Owner Trustee,
and Chemical Bank, as
Indenture Trustee
87
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
99.8c Supplemental Indenture No. 2 4.4 to 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture, Mortgage, Report
Security Agreement and
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.9c Assignment, Assumption and 28.3 to Form S-3 33-9480 10-24-86
Further Agreement, dated as Registration Statement
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.10c Amendment No. 1, dated 10.10 to September 1986 1-4473 12-4-86
as of November 1, 1986, to Form 10-Q Report by
Assignment, Assumption and means of Amendment No.
Further Agreement, dated as 1 on December 3, 1986
of August 1, 1986, between Form 8
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.11c Amendment No. 2, dated 28.6 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
88
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
99.12 Participation Agreement, 28.2 to September 1992 1-4473 11-9-92
dated as of December 15, Form 10-Q Report
1986, among PVNGS
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor
to The First National Bank
of Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank,
in its individual capacity
and as Indenture Trustee
under a Trust Indenture,
the Company, and the
Owner Participant named
therein
99.13 Amendment No. 1, dated 28.20 to Form S-3 1-4473 8-10-87
as of August 1, 1987, to Registration Statement
Participation Agreement, No. 33-9480 by means of a
dated as of December 15, November 6, 1986 Form
1986, among PVNGS 8-K Report
Funding Corp., Inc. as
Funding Corporation, State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Owner Trustee,
Chemical Bank, as Indenture
Trustee, the Company, and
the Owner Participant named
therein
89
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
99.14 Amendment No. 2, dated 28.5 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS Fund-
ing Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and
as Indenture Trustee, the
Company, and the Owner
Participant named therein
99.15 Trust Indenture, Mortgage, 10.2 to November 18, 1986 1-4473 1-20-87
Security Agreement and Form 8-K Report
Assignment of Facility
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to
The First National Bank
of Boston, as Owner
Trustee, and Chemical
Bank, as Indenture Trustee
99.16 Supplemental Indenture No. 4.13 to Form S-3 1-4473 8-24-87
1, dated as of August 1, 1987, Registration Statement
to Trust Indenture, Mortgage, No. 33-9480 by means of
Security Agreement and August 1, 1987 Form 8-K
Assignment of Facility Report
Lease, dated as of December
15, 1986, between State
Street Bank and Trust
Company, as successor to
The First National Bank
of Boston, as Owner
Trustee, and Chemical Bank,
as Indenture Trustee
90
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
99.17 Supplemental Indenture 4.5 to 1992 Form 10-K 1-4473 3-30-93
No. 2 to Trust Indenture, Report
Mortgage, Security Agree-
ment and Assignment of
Facility Lease, dated as of
December 15, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston,
as Owner Trustee, and
Chemical Bank, as Indenture
Trustee
99.18 Assignment, Assumption and 10.5 to November 18, 1986 1-4473 1-20-87
Further Agreement, dated as Form 8-K Report
of December 15, 1986,
between the Company and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
99.19 Amendment No. 1, dated 28.7 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993, to Report
Assignment, Assumption
and Further Agreement,
dated as of December 15, 1986,
between the Company and State
Street Bank and Trust Company,
as successor to The First
National Bank of Boston, as
Owner Trustee
99.20c Indemnity Agreement dated 28.3 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993 by the Report
Company
99.21 Extension Letter, dated as of 28.20 to Form S-3 1-4473 8-10-87
August 13, 1987, from the Registration Statement
signatories of the No. 33-9480 by means of a
Participation Agreement to November 6, 1986 Form
Chemical Bank 8-K Report
91
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.b DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
99.22 Arizona Corporation 28.1 to 1991 Form 10-K 1-4473 3-19-92
Commission Order dated Report
December 6, 1991
99.23 Arizona Corporation 10.1 to June Form 10-Q 1-4473 8-12-94
Commission Order dated Report
June 1, 1994
99.24 Rate Reduction Agreement 10.1 to December 4, 1995 1-4473 12-14-95
dated December 4, 1995 Form 8-K Report
between the Company and
the ACC Staff
99.25 Arizona Corporation 10.1 to March 1996 1-4473 5-14-96
Commission Order Form 10-Q Report
dated April 24, 1996
99.26 Arizona Corporation 99.1 to 1996 Form 10-K 1-4473 3-28-97
Commission Order, Report
Decision No. 59943,
dated December 26, 1996,
including the Rules regard-
ing the introduction of retail
competition in Arizona
99.27 Retail Electric Competition 10.1 to June 1998 1-4473 8-14-98
Rules Form 10-Q Report
99.28 Arizona Corporation 10.1 to September 1999 1-4473 11-15-99
Commission Order, 10-Q Report
Decision No. 61973, dated
October 6, 1999, approving
our Settlement Agreement
99.29 Arizona Corporation 10.2 to September 1999 1-4473 11-15-99
Commission Order, 10-Q Report
Decision No. 61969, dated
September 29, 1999, includ-
ing the Retail Electric
Competition Rules
99.30 Addendum to Settlement 10.1 to Pinnacle West 1-8962 11-14-00
Agreement September 2000 10-Q
92
- ----------
(a) Management contract or compensatory plan or arrangement to be filed as an
exhibit pursuant to Item 14(c) of Form 10-K.
(b) Reports filed under File No. 1-4473 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
(c) An additional document, substantially identical in all material respects to
this Exhibit, has been entered into, relating to an additional Equity
Participant. Although such additional document may differ in other respects
(such as dollar amounts, percentages, tax indemnity matters, and dates of
execution), there are no material details in which such document differs
from this Exhibit.
(d) Additional agreements, substantially identical in all material respects to
this Exhibit have been entered into with additional officers and key
employees of the Company. Although such additional documents may differ in
other respects (such as dollar amounts and dates of execution), there are
no material details in which such agreements differ from this Exhibit.
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 November 27, 2000, regarding (i) the Court of Appeals
affirming the ACC's approval of the 1999 Settlement Agreement; (ii) a Maricopa
County Superior Court judge's final judgment related to the Rules; (iii) the
proposed timing of the transfer of generation assets; and (iv) the issues
related to generation expansion.
93
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(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 Officer March 13, 2001
- ----------------------------- and Director
(William J. Post, Chairman
of the Board of Directors and
Chief Executive Officer)
Jack E. Davis Principal Accounting Officer, March 13, 2001
- ----------------------------- President and Director
(Jack E. Davis, President)
Michael V. Palmeri Principal Financial Officer March 13, 2001
- -----------------------------
(Michael V. Palmeri,
Vice President, Finance)
Edward N. Basha, Jr. Director March 13, 2001
- -----------------------------
(Edward N. Basha, Jr.)
Michael L. Gallagher Director March 13, 2001
- -----------------------------
(Michael L. Gallagher)
Pamela Grant Director March 13, 2001
- -----------------------------
(Pamela Grant)
94
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)
95
Commission File Number 1-4473
================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
EXHIBITS TO
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
----------
Arizona Public Service Company
(Exact name of registrant as specified in charter)
================================================================================
INDEX TO EXHIBITS
Exhibit No. Description
- ----------- -----------
12.1 -- Computation of Ratio of Earnings to Fixed Charges
23.1 -- Consent of Deloitte & Touche LLP
For a description of the Exhibits incorporated in this filing by reference, see
Part IV, Item 14.