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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1999
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 29, 2000, 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.
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TABLE OF CONTENTS
Page
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GLOSSARY.................................................................... 1
PART I
Item 1. Business...................................................... 2
Item 2. Properties.................................................... 11
Item 3. Legal Proceedings............................................. 14
Item 4. Submission of Matters to a Vote of Security Holders........... 14
PART II
Item 5. Market for Registrant's Common Stock and Related Security
Holder Matters................................................ 14
Item 6. Selected Financial Data....................................... 15
Item 7. Financial Review.............................................. 16
Item 7A Quantitative and Qualitative Disclosures about Market Risk.... 21
Item 8. Financial Statements and Supplementary Data................... 22
Item 9. Changes In and Disagreements with Accountants on Accounting
and Financial Disclosure...................................... 51
PART III
Item 10. Directors and Executive Officers of the Registrant............ 51
Item 11. Executive Compensation........................................ 51
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 51
Item 13. Certain Relationships and Related Transactions................ 51
PART IV
Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
and Reports on Form 8-K....................................... 52
SIGNATURES.................................................................. 73
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GLOSSARY
ACC -- Arizona Corporation Commission
ACC STAFF -- Staff of the Arizona Corporation Commission
AFUDC -- Allowance for Funds Used During Construction
ANPP -- Arizona Nuclear Power Project, also known as Palo Verde
APS -- Arizona Public Service Company
CC&N -- Certificate of convenience and necessity
CHOLLA -- Cholla Power Plant
CHOLLA 4 -- Unit 4 of the Cholla Power Plant
COMPANY -- Arizona Public Service Company
CUC -- Citizens Utilities Company
EPA -- United States Environmental Protection Agency
FASB -- Financial Accounting Standards Board
FERC -- Federal Energy Regulatory Commission
FOUR CORNERS -- Four Corners Power Plant
GAAP -- Generally accepted accounting principles
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
NGS -- Navajo Generating Station
NRC -- Nuclear Regulatory Commission
PALO VERDE -- Palo Verde Nuclear Generating Station
PINNACLE WEST -- Pinnacle West Capital Corporation, an Arizona corporation, the
Company's parent
SEC -- Securities and Exchange Commission
SALT RIVER PROJECT -- Salt River Project Agricultural Improvement and Power
District
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PART I
ITEM 1. BUSINESS
THE COMPANY
We were incorporated in 1920 under the laws of Arizona and are engaged
principally in serving electricity in the State of Arizona. Our principal
executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004
(telephone 602-250-1000). Pinnacle West owns all of the outstanding shares of
our common stock.
We are Arizona's largest electric utility, with 827,000 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. During
1999, no single purchaser or user of energy accounted for more than 2% of total
electric revenues. See Note 16 of Notes to Financial Statements for a discussion
of business segments. At December 31, 1999, we employed 6,234 people, which
includes employees assigned to joint projects where we are project manager.
This document contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; our ability to successfully compete outside our traditional
regulated markets; regional economic conditions, which could affect customer
growth; the cost of debt and equity capital; weather variations affecting
customer usage; technological developments in the electric industry; and Year
2000 issues. See "Competition" in this Item for a discussion of some of these
factors.
COMPETITION
RETAIL
The ACC has regulatory authority over us in matters relating to retail
electric rates, the issuance of securities, and the transaction of business with
affiliated parties. See Note 3 of Notes to Financial Statements in Item 8 for a
discussion of the electric industry restructuring in Arizona, including our 1999
Settlement Agreement, ACC rules for the introduction of retail electric
competition, and Arizona legislative initiatives. See also "Financial Review -
Competition and Industry Restructuring" in Item 7. In addition to the
introduction of competition pursuant to the Settlement Agreement and the ACC
rules, we are subject to varying degrees of competition in certain territories
adjacent to or within areas that we serve that are also currently served by
other utilities in our region (such as Tucson Electric Power Company, Southwest
Gas Corporation, and Citizens Utility Company) as well as cooperatives,
municipalities, electrical districts, and similar types of governmental
organizations (principally Salt River Project).
We face competitive challenges from low-cost hydroelectric power and
natural gas fuel, as well as the access of some utilities to preferential
low-priced federal power and other subsidies. In addition, some customers,
particularly industrial and large commercial, may own and operate facilities to
generate their own electric energy requirements. Such facilities may be operated
by the customers themselves or by other entities engaged for such purpose.
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 that competition to sell capacity will remain vigorous. Our rates for
wholesale power sales and transmission services are subject to regulation by the
FERC. During 1999, approximately 23% of our electric operating revenues resulted
from such sales and charges.
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The National Energy Policy Act of 1992 has promoted increased competition
in the wholesale electric power markets. The Energy Act reformed provisions of
the Public Utility Holding Company Act of 1935 (the "1935 Act") and the Federal
Power Act to remove certain barriers to competition for the supply of
electricity. For example, the Energy Act permits the FERC to order transmission
access for third parties to transmission facilities owned by another entity so
that independent suppliers and other third parties can sell at wholesale to
customers wherever located. The Energy Act does not, however, permit the FERC to
issue an order requiring transmission access to retail customers.
Effective July 9, 1996, a FERC decision requires all electric utilities
subject to the FERC's jurisdiction to file transmission tariffs which provide
competitors with access to transmission facilities comparable to the
transmission owners' access for wholesale transactions, establishes information
requirements, and provides for recovery of certain wholesale stranded costs.
Retail stranded costs resulting from a state-authorized retail direct-access
program are the responsibility of the states, unless a state lacks authority to
impose rates to recover such costs, in which case FERC will consider doing so.
We have filed a revised open access tariff in accordance with this decision. We
do not believe that this decision will have a material adverse impact on our
results of operations or financial position.
REGULATORY ASSETS
Our major regulatory assets are deferred income taxes and rate
synchronization cost deferrals. As a result of our September 1999 Settlement
Agreement, we have discontinued the application of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation," for our generation operations. This means that regulatory assets,
unless reestablished as recoverable through ongoing regulated cash flows, were
eliminated and the generation assets were tested for impairment. We determined
that the generation assets were not impaired. Prior to the 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. See Notes 1, 3, and 10 of Notes to Financial
Statements in Item 8 for additional information.
COMPETITIVE STRATEGIES
We are pursuing strategies to maintain and enhance our competitive
position. These strategies include (i) cost management, with an emphasis on the
reduction of variable costs (fuel, operations, and maintenance expenses) and on
increased productivity through technological efficiencies; (ii) a focus on our
core business through customer service, distribution system reliability,
business segmentation, and the anticipation of market opportunities; (iii) an
emphasis on good regulatory relationships; (iv) asset maximization (e.g., higher
capacity factors and lower forced outage rates); (v) strengthening our capital
structure and financial condition; (vi) leveraging core competencies into
related areas, such as energy management products and services; and (vii)
operating a trading floor and implementing a risk management program to provide
for more stability of prices and the ability to retain or grow incremental
margins through more competitive pricing and risk management. Underpinning our
competitive strategies are the strong growth characteristics of our service
territory. As competition in the electric utility industry continues to evolve,
we will continue to evaluate strategies and alternatives that will position us
to compete effectively in a more competitive, restructured industry.
GENERATING FUEL AND PURCHASED POWER
1999 ENERGY MIX
Our sources of energy during 1999 were: coal - 29.9%; nuclear - 22.4%;
purchased power - 43.2%; gas - 4.4%; and other - 0.1%.
COAL SUPPLY
LEASES NGS and Four Corners are located on the Navajo Reservation and held
under easements granted by the federal government as well as leases from the
Navajo Nation. See "Properties- Plant Sites Leased from the
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Navajo Nation" in Item 2. Most of the coal for Cholla is supplied by 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.
Remaining coal requirements are purchased on the spot market. All of the coal
for Four Corners is purchased from a coal supplier with a long-term lease of
coal reserves owned by the Navajo Nation. The coal for NGS comes from a supplier
with a long-term lease with the Navajo Nation and the Hopi Tribe. See Note 12 of
Notes to Financial Statements in Item 8 for information regarding our obligation
for coal mine reclamation.
CONTRACTS Cholla presently has sufficient coal under current contracts to
ensure a reliable fuel supply through 2005. Portions of the fuel supply are bid
on the spot market to take advantage of competitive pricing options. Following
expiration of current contracts, there are numerous competitive fuel supply
options available to ensure continuous plant operation. Cholla also has certain
requirements for low sulfur coal and the current supplier is expected to
continue to provide most of Cholla's low sulfur coal requirements through the
current contract. There are sufficient reserves of low sulfur coal available
from other suppliers to ensure the continued operation of Cholla for its useful
life. The sulfur content of coal at Cholla for 1999 was 0.47%. Average prices
paid for all coal supplied from reserves dedicated under existing contracts were
slightly lower than, but comparable to, 1998. For the years remaining on the
contracts after 2000, prices will be reduced.
Four Corners is a mine-mouth operation which is under contract for coal
through 2004. There are options to extend the contract through the plant site
lease expiration in 2017. The sulfur content of Four Corners coal for 1999 was
0.77%, and the units are equipped with scrubbers. The average price paid for all
coal supplied under the existing contract was slightly lower than, but
comparable to, 1998. The Four Corners lease waives, until July 2001, the
requirement that we, as well as our fuel supplier, pay certain taxes to the
Navajo Nation. In September 1997, a settlement agreement was finalized between
the coal supplier, the Navajo Nation, and Four Corners participants, which
settled certain issues in the lease regarding the obligation of the fuel
supplier to pay taxes prior to the expiration of tax waivers in 2001. Pursuant
to this agreement, the coal supplier currently pays a possessory interest tax to
the Navajo Nation, which is contractually reimbursed by participants. The
parties also agreed to investigate alternative contractual arrangements and
business relationships before 2001 in an effort to permit the electricity
generated at Four Corners to be priced competitively. We anticipate that
additional taxes will be levied by the Navajo Nation upon the expiration of the
tax waivers; however, we cannot currently predict the outcome of this matter or
the amount of the additional taxes.
NGS is under contract with its coal supplier through 2011, with options to
extend through the plant site lease. The sulfur content of coal at NGS for 1999
was 0.53%, and the units are equipped with scrubbers. Average price paid for
coal supplied in 1999 under the existing contract was lower than, but comparable
to, 1998. The NGS 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.
NATURAL GAS SUPPLY
We are a party to contracts with a number of natural gas suppliers that
allow us to purchase natural gas in the method we determine to be most economic.
Currently, we are purchasing the majority of our natural gas requirements from
numerous companies under these contracts. 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:
* the mining and milling of uranium ore to produce uranium concentrates,
* the conversion of uranium concentrates to uranium hexafluoride,
* the enrichment of uranium hexafluoride,
* the fabrication of fuel assemblies,
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* the utilization of fuel assemblies in reactors and
* the storage of spent fuel and the disposal thereof.
The Palo Verde participants have made contractual arrangements to obtain
quantities of uranium concentrates anticipated to be sufficient to meet
operational requirements through 2002. Existing contracts and options could be
utilized to meet approximately 88% of requirements in 2003, 88% of requirements
in 2004, 49% of requirements in 2005, and 16% of requirements in 2006 and
beyond. Spot purchases on the uranium market will be made, as appropriate, in
lieu of any uranium that might be obtained through contractual options.
The Palo Verde participants have contracted for uranium conversion
services. Existing contracts and options could be utilized to meet approximately
70% of requirements in 2000, 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.
SPENT NUCLEAR FUEL AND WASTE DISPOSAL. Pursuant to the Nuclear Waste Policy
Act of 1982, as amended in 1987, the United States Department of Energy ("DOE")
is obligated to accept and dispose of all spent nuclear fuel and other
high-level radioactive wastes generated by domestic power reactors. The NRC,
pursuant to the Waste Act, requires operators of nuclear power reactors to enter
into spent fuel disposal contracts with DOE. Under the Waste Act, DOE was to
develop the facilities necessary for the storage and disposal of spent nuclear
fuel and to have the first such facility in operation by 1998. That facility was
to be a permanent repository. DOE has announced that such a repository now
cannot be completed before 2010. In July 1996, the United States Court of
Appeals for the District of Columbia Circuit (D.C. Circuit) ruled that the DOE
has an obligation to start disposing of spent nuclear fuel no later than January
31, 1998. By way of letter dated December 17, 1996, DOE informed us and other
contract holders that DOE anticipates that it would be unable to begin
acceptance of spent nuclear fuel for disposal in a repository or interim storage
facility by January 31, 1998. In November 1997, the D.C. Circuit issued a Writ
of Mandamus precluding DOE from excusing its own delay on the grounds that DOE
has not yet prepared a permanent repository or interim storage facility. On May
5, 1998, the D.C. Circuit issued a ruling refusing to order DOE to begin moving
spent nuclear fuel. 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.
Several bills have been introduced in Congress contemplating the
construction of a central interim storage facility; however, there is resistance
to certain features of these bills both in 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 storage capacity in existing fuel storage pools at Palo Verde
which, with certain modifications, could accommodate all fuel expected to be
discharged from normal operation of Palo Verde through about 2002. Construction
of a new facility for on-site dry storage of spent fuel is underway. Once this
facility is completed and approvals are granted, we believe that spent fuel
storage or disposal methods will be available for use by Palo Verde to allow its
continued operation beyond 2002.
A new low-level waste facility was built in 1995 on-site which could store
an amount of waste equivalent to ten years of normal operation at Palo Verde.
Although some low-level waste has been stored on-site, 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.
5
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.
PURCHASED POWER AGREEMENTS
In addition to that available from its own generating capacity (see
"Properties" in Item 2), we purchase electricity from other utilities under
various arrangements. One of the most important of these is a long-term contract
with Salt River Project. This contract may be canceled by Salt River Project on
three years' notice and requires Salt River Project to make available, and us to
pay for, certain amounts of electricity. The amount of electricity 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 316 MW January through May 1999, and starting June
1999 changed to 302 MW. In 1999, we received approximately 1,056,200 MWh of
energy under the contract and paid about $43.9 million for capacity availability
and energy received. See Note 3 of Notes to Financial Statements for a
discussion of amendments to this contract and other agreements with Salt River
Project.
In September 1990, we entered into a thirty year agreement under which we
and PacifiCorp engage in one-for-one seasonal capacity exchanges. We receive
electricity from PacifiCorp during our summer peak season. We will have 480 MW
of generating capacity available to us under the agreements until 2020. In 1999,
we had 480 MW of generating capacity available from PacifiCorp and we received
approximately 572,382 MWh of energy under the capacity exchange.
CONSTRUCTION PROGRAM
During the years 1997 through 1999, we incurred approximately $962 million
in capital expenditures. Utility capital expenditures for the years 2000 through
2002 are expected to be primarily for expanding transmission and distribution
capabilities to meet customer growth, upgrading existing facilities, and for
environmental purposes. Capitalized expenditures, including expenditures for
environmental control facilities, for the years 2000 through 2002 have been
estimated as follows:
(Millions of Dollars)
By Year By Major Facilities
------- -------------------
2000 $ 384 Production $ 255
2001 342 Transmission and Distribution 691
2002 334 General 114
------- -------
Total $ 1,060 Total $ 1,060
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The amounts for 2000 through 2002 exclude capitalized interest costs and
include capitalized property taxes and about $30-$35 million each year for
nuclear fuel. We conduct a continuing review of our construction program.
MORTGAGE REPLACEMENT FUND REQUIREMENTS
So long as any of our first mortgage bonds are outstanding, we are required
for each calendar year to deposit with the trustee under our mortgage cash in a
formularized amount related to net additions to our mortgaged utility plant. We
may satisfy all or any part of this "replacement fund" requirement by utilizing
redeemed or retired bonds, net property additions, or property retirements. For
1999, the replacement fund requirement amounted to approximately $143 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
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replacement fund. This is 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. Pursuant to the Clean Air Act, the EPA adopted regulations that address
visibility impairment in certain federally-protected areas which can be
reasonably attributed to specific sources. In September 1991, the EPA issued a
final rule that limited sulfur dioxide emissions at NGS. One NGS unit had to
comply with this rule in 1997, one in 1998, and the last unit in 1999. Salt
River Project is the NGS operating agent. Salt River Project estimates a capital
cost of $430 million and annual operations and maintenance costs of
approximately $14 million for all three units, for NGS to meet these
requirements. We are required to fund 14% of these expenditures. About all of
these capital costs have been incurred.
The Clean Air Act also 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." Each existing utility unit is granted a certain
number of "allowances." For Phase II plants, which include our plants,
allowances will be required beginning in the year 2000 to operate the 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. These limitations require certain plants to install additional
pollution control equipment. In December 1996, the EPA issued rules for nitrogen
oxides emissions limitations that would have required us to install additional
pollution control equipment at Four Corners by January 1, 2000. On February 14,
1997, we filed a Petition for Review in the United States Court of Appeals for
the District of Columbia. We alleged that the EPA improperly classified Four
Corners Unit 4 in these rules, thereby subjecting Unit 4 to a more stringent
emission limitation. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 97-1091. In February 1998, the Court
vacated the Unit 4 emission limitation and remanded the issue to EPA for
reconsideration. In December 1999, EPA's direct final rule, which classified
Four Corners Unit 4 as we had proposed, became final. We do not currently expect
this rule to have a material impact on our financial position or results of
operations.
With respect to protection of visibility in certain specified areas, the
Clean Air Act requires the EPA to conduct a study concerning visibility
impairment in those areas and to identify sources contributing to such
impairment. Interim findings of this study indicate that any beneficial effect
on visibility as a result of the Amendments would be offset by expected
population and industry growth. The Clean Air Act also requires EPA to establish
a "Grand Canyon Visibility Transport Commission" to complete a study on
visibility impairment in the "Golden Circle of National Parks" in the Colorado
Plateau. NGS, Cholla, and Four Corners are located near the Golden Circle of
National Parks. The 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 containing
requirements to eliminate all man-made emissions causing visibility impairment
in certain specified areas, including the Golden Circle of National Parks in the
Colorado Plateau. The 2008 implementation plans must also include consideration
and potential application of best available retrofit technology ("BART") for
major stationary sources which came into operation between August
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1962 and August 1977, such as the Navajo Generating Station, Cholla Power Plant
and Four Corners Power Plant. The nine western states and tribes that
participated in the Grand Canyon Visibility Transport Commission process will
have the option to follow an alternate implementation plan and schedule for
areas considered by the Commission. Under this option, those states and tribes
would submit implementation plans by 2003, which would incorporate the emission
reduction scheme adopted in the Commission's recommendations and application of
BART by 2018, possibly using an emission trading program. Any states and tribes
that implement this option will also have to submit revised implementation plans
in 2008 to address visibility in certain specified areas that were not
considered by the Commission. Because Arizona and the Navajo Nation have the
discretion to choose between the national or Commission options and a variety of
pollution controls to meet the requirements of the regional haze rules, the
actual impact on us cannot be determined at this time.
Also, in July 1997, EPA promulgated final National Ambient Air Quality
Standards for ozone and particulate matter. Pursuant to the 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. These standards were challenged and the court determined that EPA's
promulgation of the standards violated the constitutional prohibition on
delegation of legislative power. The court remanded the ozone standard, vacated
the coarse particulate matter standard, and invited the parties to brief the
court on vacating or remanding the fine particulate matter standard. We cannot
currently predict EPA's response to this decision. 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 or results of operations.
With respect to hazardous air pollutants emitted by electric utility steam
generating units, the Clean Air Act requires two studies. The results of the
first study indicated an impact from mercury emissions from such units in
certain unspecified areas. The EPA has not yet stated whether or not mercury
emissions limitations will be imposed. Secondly, the EPA will complete a general
study by December 2000 concerning the necessity of regulating hazardous air
pollutant emissions from such units under the Clean Air Act. Because we cannot
speculate as to the ultimate requirements by the EPA, we cannot currently
estimate the capital expenditures, if any, which may be required as a result of
these studies.
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 to have a
material impact on our financial position or results of operations.
FEDERAL IMPLEMENTATION PLAN. In September 1999, the EPA proposed a Federal
Implementation Plan ("FIP") to set air quality standards at certain power
plants, including the Navajo Generating Station and the Four Corners Power
Plant. The comment period on this proposal ended in November 1999. The FIP is
similar to current Arizona regulation of NGS and New Mexico regulation of Four
Corners, with minor modifications. We do not currently expect FIP to have a
material impact on our financial position or results of operations.
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"). 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 or results of
operations.
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:
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* 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 or results of operations.
PURPORTED NAVAJO ENVIRONMENTAL REGULATION
Four Corners and NGS 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 NGS 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 NGS. By separate letters dated
October 12 and October 13, 1995, the Four Corners participants and the NGS
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 NGS. On October 17, 1995, the Four Corners
participants and the NGS 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 NGS and
* the Navajo Nation and its agencies and courts lack adjudicatory
jurisdiction to determine the enforceability of the Acts as applied to
Four Corners and NGS.
On October 18, 1995, the Navajo Nation and the Four Corners and NGS 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.
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. We are one of a number of parties
9
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 is 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 less-utilized 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 recently issued a decision confirming that certain groundwater rights may
be available to the federal government and Indian tribes. We and other parties
have petitioned the U.S. Supreme Court for review of this decision. Another
issue important to the claims is pending on appeal to the Arizona Supreme Court.
No trial date concerning our water rights claims has been set in this matter.
We have also filed claims to water in the Little Colorado River Watershed
in Arizona in an action pending in the Apache County 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.
10
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
---------
Other............................................................. 5,600
---------
Total 3,986,900
=========
- ----------
(1) West Phoenix steam units (108,300 kW) are currently mothballed.
RESERVE MARGIN
Our 1999 peak one-hour demand on our electric system was recorded on August
24, 1999 at 4,934,700 kW, compared to the 1998 peak of 5,027,000 kW recorded on
July 16. Taking into account additional capacity then available to us under
traditional long-term purchase power contracts as well as our own generating
capacity, our capability of meeting system demand on August 24, 1999 amounted to
4,754,600 kW, for an installed reserve margin of (4.4%). 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 1999 peak amounted to 3,587,100 kW, for a
margin of (27.5%). Firm purchases, including short-term seasonal purchases,
totaling 1,643,000 kW were in place at the time of the peak ensuring the ability
to meet the load requirement, with an actual reserve margin of 9.1%.
PLANT SITES LEASED FROM NAVAJO NATION
LEASES NGS 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.
11
TAX AND ROYALTY 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 NGS 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
The NRC recently amended its rules on financial assurance requirements for
the decommissioning of nuclear power plants. The amended rules became effective
on November 23, 1998. The amended rules 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
rules regarding the introduction of retail electric competition in Arizona (see
Note 3 of Notes to Financial Statements) currently 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 2
of Notes to Financial Statements in Item 8 for additional information about our
nuclear decommissioning costs.
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 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.
12
[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.
13
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 ("Peabody"),
Southern California Edison Company and other defendants, and citing various
claims in connection with the renegotiations of the coal royalty and lease
agreements under which Peabody mines coal for the Navajo and Mohave Generating
Stations. 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 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 "Regulatory Matters" in
Note 3 of Notes to Financial Statements in Item 8 for a discussion of
competition and the rules regarding the introduction of retail electric
competition in Arizona 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 its complaints the Company 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.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
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 1999 and 1998.
COMMON STOCK DIVIDENDS
(THOUSANDS OF DOLLARS)
QUARTER 1999 1998
------- ------- -------
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.
14
ITEM 6. SELECTED FINANCIAL DATA
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
Electric Operating Revenues $2,292,798 $2,006,398 $1,878,553 $1,718,272 $1,614,952
Fuel Expenses 795,494 545,297 443,571 329,489 275,487
Operating Expenses 1,108,380 1,090,290 1,063,157 1,023,575 957,711
---------- ---------- ---------- ---------- ----------
Operating Income 388,924 370,811 371,825 365,208 381,754
Other Income 20,990 20,448 21,586 35,217 25,548
Interest Deductions ___ Net 141,592 136,012 141,918 156,954 167,732
---------- ---------- ---------- ---------- ----------
Income Before Extraordinary Charge 268,322 255,247 251,493 243,471 239,570
Extraordinary Charge - Net of Tax 139,885 -- -- -- --
---------- ---------- ---------- ---------- ----------
Net Income 128,437 255,247 251,493 243,471 239,570
Preferred Dividends 1,016 9,703 12,803 17,092 19,134
---------- ---------- ---------- ---------- ----------
Earnings for Common Stock $ 127,421 $ 245,544 $ 238,690 $ 226,379 $ 220,436
========== ========== ========== ========== ==========
Total Assets $6,117,624 $6,393,299 $6,331,142 $6,423,222 $6,418,262
========== ========== ========== ========== ==========
Capital Structure:
Common Stock Equity $1,983,174 $1,975,755 $1,849,324 $1,729,390 $1,621,555
Non-Redeemable Preferred Stock -- 85,840 142,051 165,673 193,561
Redeemable Preferred Stock -- 9,401 29,110 53,000 75,000
Long-Term Debt Less Current Maturities 1,997,400 1,876,540 1,953,162 2,029,482 2,132,021
---------- ---------- ---------- ---------- ----------
Total Capitalization 3,980,574 3,947,536 3,973,647 3,977,545 4,022,137
Commercial Paper 38,300 178,830 130,750 16,900 177,800
Current Maturities of Long-Term Debt 114,711 164,378 104,068 153,780 3,512
---------- ---------- ---------- ---------- ----------
Total $4,133,585 $4,290,744 $4,208,465 $4,148,225 $4,203,449
========== ========== ========== ========== ==========
- ----------
See "Financial Review" in Item 7 for a discussion of certain information in the
foregoing table.
15
ITEM 7. FINANCIAL REVIEW
In this section, we explain our results of operations, general financial
condition, and outlook, including:
* the changes in our earnings from 1998 to 1999 and from 1997 to 1998
* the factors impacting our business, including competition and electric
industry restructuring
* the effects of regulatory agreements on our results and outlook
* our capital needs and resources and
* our management of market risks.
Throughout this Financial Review, we refer to specific "Notes" in the Notes to
Financial Statements that begin on page 30. These Notes add further details to
the discussion.
RESULTS OF OPERATIONS
1999 COMPARED WITH 1998. Our 1999 earnings decreased $118 million from 1998
earnings primarily because of the effects of a $140 million after-tax
extraordinary charge for a regulatory disallowance related to our comprehensive
Settlement Agreement that was approved by the Arizona Corporation Commission
(ACC) in September 1999. See "Regulatory Agreements" below and Notes 1 and 3 for
additional information about the regulatory disallowance and the Settlement
Agreement. Earnings excluding the extraordinary charge increased $21 million - a
9% increase - over 1998 earnings primarily because of increases in the number of
customers and in the average amount of electricity used by customers and lower
financing costs. These positive impacts more than offset the effects of retail
electricity price reductions and higher utility operations and maintenance
expense. See Note 3 for additional information about the price reductions.
In 1999, electric operating revenues increased $286 million primarily because
of:
* increased power marketing and trading revenues ($219 million)
* increases in the number of 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).
The increase in power marketing revenues resulted from higher prices and
increased activity in western U.S. bulk power 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 more than offset by lower employee benefit costs and movement of
certain marketing functions to APS Energy Services in early 1999.
1998 COMPARED WITH 1997. Our 1998 earnings increased $7 million - a 3% increase
- - over 1997 earnings primarily because of an increase in customers, expanded
power marketing and trading activities, and lower financing costs. In the
comparison, these positive factors more than offset the effects of milder
weather, the prior year's benefits of the two fuel-related settlements recorded
in 1997, and retail price reductions. See Note 3 for additional information
about the price reductions.
16
In 1998, electric operating revenues increased $128 million primarily because
of:
* increased power marketing and trading revenues ($94 million)
* increases in the number of customers and the average amount of
electricity used by customers ($77 million) and
* miscellaneous factors ($8 million).
As mentioned above, these positive factors were partially offset by the effects
of milder weather ($33 million) and reductions in retail prices ($18 million).
The increase in power marketing revenues resulted from higher prices and
increased activity in western U.S. bulk power markets. The revenue increases
were accompanied by an increase in purchased power expenses. These activities
contributed positively to earnings in both periods; the contribution in 1998 was
higher than in 1997.
The two fuel-related settlements increased 1997 pretax earnings by about $21
million. The income statement reflects these settlements as reductions in fuel
expense and as other income.
Operations and maintenance expense increased $13 million primarily because of
customer growth, initiatives related to competition, and expansion of our power
marketing and trading function.
Depreciation and amortization expense increased $11 million because we had more
plant in service.
Financing costs decreased by $9 million primarily because of lower amounts of
outstanding debt and preferred stock.
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: 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 included accelerated amortization
of our deferred investment tax credits (ITCs).
As part of the 1999 Settlement Agreement, we reduced our rates for standard
offer service for customers with loads less than 3 megawatts 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 related to the 1996 regulatory agreement (see below). For customers
having loads 3 megawatts or greater, standard offer rates will be reduced in
annual increments that total 5% through 2002.
Also, under the Settlement Agreement a regulatory disallowance removed $234
million before income 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. Before the ACC approved the 1999
Settlement Agreement, we were recovering substantially all of our regulatory
assets through accelerated amortization over an eight-year period that would end
June 30, 2004 under the 1996 agreement. For more details, see Note 1.
The regulatory assets to be recovered under this Settlement Agreement are now
being amortized as follows:
(Millions of Dollars)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
17
Also, 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 the 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, which was included in the July 1, 1999 1.5%
price reduction under the 1999 Settlement Agreement.
CAPITAL NEEDS AND RESOURCES
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 our operations and, to the extent necessary, external financing.
As part of the 1996 regulatory agreement, we received annual cash infusions from
Pinnacle West of $50 million from 1996 through 1999. During the period from 1997
through 1999, we paid for all of our capital expenditures with cash from our
operations. We expect to do so in 2000 through 2002 as well.
Our capital expenditures in 1999 were $332 million. Our projected capital
expenditures for the next three years are: $384 million in 2000; $342 million in
2001; and $334 million in 2002. These amounts include about $30-$35 million each
year for nuclear fuel. In general, most of the projected capital expenditures
are for:
* expanding transmission and distribution capabilities to meet customer
growth
* upgrading existing utility property and
* environmental purposes.
During 1999, we redeemed about $323 million of long-term debt and $96 million of
preferred stock, including premiums, with cash from operations and long- and
short-term debt. We no longer have any outstanding preferred stock. Our
long-term debt redemption requirements and payment obligations on a capitalized
lease for the next three years are approximately: $115 million in 2000; $253
million in 2001; and $125 million in 2002. In addition, we made optional
redemptions of about $89 million of long-term debt in January 2000. 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, 1999, we had credit commitments from various banks totaling
about $350 million, which were available either to support the issuance of
commercial paper or to be used as bank borrowings. At the end of 1999, we had
about $38 million of commercial paper and $50 million of long-term bank
borrowings outstanding.
In February 1999, we issued $125 million of unsecured long-term debt and in
November 1999, we issued $250 million of unsecured long-term debt.
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.
COMPETITION AND INDUSTRY RESTRUCTURING
The electric industry is undergoing significant change. It is moving to a
competitive, market-based structure from a highly-regulated, cost-based
environment in which companies have been entitled to recover their costs and to
18
earn fair returns on their invested capital in exchange for commitments to serve
all customers within designated service territories. See "Results of Operations
- - Regulatory Agreements" and Note 3 for additional information about our
Settlement Agreement with the ACC related to the implementation of retail
electric competition, the ACC rules that provide a framework for the
introduction of retail electric competition in Arizona, and other competitive
developments, including an agreement with Salt River Project.
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 a discussion of legislative developments.
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, or results of operations. 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.
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 our Settlement Agreement (see Note 3), we discontinued the application
of SFAS No. 71 for our generation operations. This meant that the generation
assets were tested for impairment and the portion of the regulatory assets
deemed to be unrecoverable through ongoing regulated cash flows was eliminated.
We determined that the generation assets were not impaired. A regulatory
disallowance ($140 million after income taxes) was reported as an extraordinary
charge on the income statement. See Note 1 for additional information on
regulatory accounting and Note 3 for additional information on the Settlement
Agreement.
YEAR 2000 READINESS DISCLOSURE
Some companies expected to face problems on January 1, 2000 in the case that
computer systems and equipment would not properly recognize calendar dates.
During 1997, we had initiated a comprehensive company-wide Year 2000 program to
review and resolve all Year 2000 issues in mission critical systems in a timely
manner to ensure the reliability of electric service to our customers. We have
spent about $5 million to be Year 2000 ready. To date, we have not experienced
any material Year 2000 related problems, and we do not anticipate any in the
future.
ACCOUNTING MATTERS
We describe a new standard on accounting for derivatives in Note 2. The new
standard on derivatives is effective for us in 2001. We are currently evaluating
what impact it will have on our financial statements. 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.
RISK MANAGEMENT
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, 1999 and December 31, 1998. The interest
19
rates presented in the tables below represent the weighted average interest
rates for the years ended December 31, 1999 and December 31, 1998.
EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
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
======== ======== ==========
EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1998
(THOUSANDS OF DOLLARS)
Short-Term Variable Long-Term Fixed Long-Term
------------------ ------------------ --------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
-------- -------- -------- -------- -------- ----------
1999 5.88% $178,830 -- $ -- 7.24% $ 164,378
2000 -- -- -- -- 5.79% 114,711
2001 -- -- -- -- 7.48% 2,488
2002 -- -- -- -- 8.13% 125,000
2003 -- -- 5.94% 125,000 -- --
Years thereafter -- -- 3.39% 456,860 7.75% 1,058,963
-------- -------- ----------
Total $178,830 $581,860 $1,465,540
======== ======== ==========
Fair value $178,830 $581,860 $1,525,900
======== ======== ==========
COMMODITY PRICE RISK. We are exposed to the impact of market fluctuations in the
price and distribution costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage our 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 these
derivative transactions for trading and to hedge certain natural gas in storage
as well as purchases and sales of electricity, fuels, and emissions
allowances/credits.
As of December 31, 1999, a hypothetical adverse price movement of 10% in the
market price of our commodity derivative portfolio would decrease the fair
market value of these contracts by approximately $6 million. This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying position being hedged with the commodity derivative portfolio.
20
We are exposed to credit losses in the event of non-performance or non-payment
by counterparties. We use a credit management process to assess and monitor our
financial exposure to counterparties. We do not expect counterparty defaults to
materially impact our financial condition, results of operations, or net cash
flow.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; our ability to successfully compete outside our traditional
regulated markets; regional economic conditions, which could affect customer
growth; the cost of debt and equity capital; weather variations affecting
customer usage; technological developments in the electric industry; and Year
2000 issues.
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 "Financial Review" in Item 7 for a discussion of quantitative and
qualitative disclosures about market risk.
21
ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Management....................................................... 23
Independent Auditors' Report............................................... 24
Statements of Income for 1999, 1998, and 1997.............................. 25
Balance Sheets as of December 31, 1999 and 1998............................ 26
Statements of Cash Flows for 1999, 1998, and 1997.......................... 28
Statements of Retained Earnings for 1999, 1998, and 1997................... 29
Notes to Financial Statements.............................................. 30
See Note 14 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.
22
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. Such information was prepared in accordance with generally
accepted accounting principles 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.
Management maintains and relies upon systems of internal accounting controls. A
limiting factor in all systems of internal accounting 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 accounting 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
Chief Executive Officer Vice President and Controller
Pinnacle West Capital Corporation
23
INDEPENDENT AUDITORS' REPORT
We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 1999 and 1998 and the related statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1999. 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 generally accepted auditing
standards. 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 the Company at December 31, 1999 and 1998
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1999 in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 18, 2000
24
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
Year Ended December 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
(Thousands of Dollars)
Electric Operating Revenues .................... $ 2,292,798 $ 2,006,398 $ 1,878,553
----------- ----------- -----------
Fuel Expenses:
Fuel for electric generation ................ 243,849 231,967 201,341
Purchased power ............................. 551,645 313,330 242,230
----------- ----------- -----------
Total ..................................... 795,494 545,297 443,571
----------- ----------- -----------
Operating Revenues Less Fuel Expenses .......... 1,497,304 1,461,101 1,434,982
----------- ----------- -----------
Other Operating Expenses:
Operations and maintenance excluding
fuel expenses ............................. 437,729 419,433 406,025
Depreciation and amortization (Note 1)....... 382,057 376,574 365,671
Income taxes (Note 10) ...................... 192,015 192,207 184,737
Other taxes ................................. 96,579 102,076 106,724
----------- ----------- -----------
Total ..................................... 1,108,380 1,090,290 1,063,157
----------- ----------- -----------
Operating Income ............................... 388,924 370,811 371,825
----------- ----------- -----------
Other Income (Deductions):
Income taxes (Note 10) ...................... 32,527 32,751 31,413
Other -- net ................................ (11,537) (12,303) (9,827)
----------- ----------- -----------
Total ..................................... 20,990 20,448 21,586
----------- ----------- -----------
Income Before Interest Deductions .............. 409,914 391,259 393,411
----------- ----------- -----------
Interest Deductions:
Interest on long-term debt .................. 132,676 137,214 140,931
Interest on short-term borrowings ........... 8,272 7,481 9,404
Debt discount, premium and expense .......... 7,323 7,580 7,791
Capitalized interest ........................ (6,679) (16,263) (16,208)
----------- ----------- -----------
Total ..................................... 141,592 136,012 141,918
----------- ----------- -----------
Income Before Extraordinary Charge ............. 268,322 255,247 251,493
Extraordinary Charge - net of income
taxes of $94,115 (Note 1) ................... 139,885 -- --
----------- ----------- -----------
Net Income ..................................... 128,437 255,247 251,493
Preferred Stock Dividend Requirements .......... 1,016 9,703 12,803
----------- ----------- -----------
Earnings for Common Stock ...................... $ 127,421 $ 245,544 $ 238,690
=========== =========== ===========
See Notes to Financial Statements.
25
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS
December 31,
-------------------------
1999 1998
----------- -----------
(Thousands of Dollars)
Utility Plant (Notes 5, 8 and 9):
Electric plant in service and held for
future use ...................................... $ 7,545,575 $ 7,265,604
Less accumulated depreciation and amortization ... 3,026,041 2,814,762
----------- -----------
Total .......................................... 4,519,534 4,450,842
Construction work in progress .................... 184,764 228,643
Nuclear fuel, net of amortization of $66,357
and $68,569 .................................... 49,114 51,078
----------- -----------
Utility Plant -- net ........................... 4,753,412 4,730,563
----------- -----------
Investments and Other Assets (Note 13) ............ 208,457 183,549
----------- -----------
Current Assets:
Cash and cash equivalents ........................ 7,477 5,558
Accounts receivable:
Service customers .............................. 201,704 205,999
Other .......................................... 35,684 23,213
Allowance for doubtful accounts ................ (1,538) (1,725)
Accrued utility revenues ......................... 72,919 67,740
Materials and supplies (at average cost) ......... 69,977 69,074
Fossil fuel (at average cost) .................... 21,869 13,978
Deferred income taxes (Note 10) .................. 8,163 3,999
Other ............................................ 30,885 26,695
----------- -----------
Total Current Assets ........................... 447,140 414,531
----------- -----------
Deferred Debits:
Regulatory assets (Note 1) ....................... 613,729 980,084
Unamortized debt issue costs ..................... 15,172 14,916
Other ............................................ 79,714 69,656
----------- -----------
Total Deferred Debits .......................... 708,615 1,064,656
----------- -----------
Total .......................................... $ 6,117,624 $ 6,393,299
=========== ===========
See Notes to Financial Statements.
26
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES
December 31,
------------------------
1999 1998
---------- ----------
(Thousands of Dollars)
Capitalization (Notes 4 and 5):
Common stock ...................................... $ 178,162 $ 178,162
Additional paid - in capital ...................... 1,246,804 1,195,625
Retained earnings ................................. 558,208 601,968
---------- ----------
Common stock equity ............................. 1,983,174 1,975,755
Non-redeemable preferred stock .................... -- 85,840
Redeemable preferred stock ........................ -- 9,401
Long-term debt less current maturities ............ 1,997,400 1,876,540
---------- ----------
Total Capitalization ............................ 3,980,574 3,947,536
---------- ----------
Current Liabilities:
Commercial paper (Note 6) ......................... 38,300 178,830
Current maturities of long-term debt (Note 5) ..... 114,711 164,378
Accounts payable .................................. 170,662 145,139
Accrued taxes ..................................... 62,858 59,827
Accrued interest .................................. 32,299 31,218
Customer deposits ................................. 24,682 26,815
Other ............................................. 26,248 16,755
---------- ----------
Total Current Liabilities ....................... 469,760 622,962
---------- ----------
Deferred Credits and Other:
Deferred income taxes (Note 10) ................... 1,178,085 1,312,007
Deferred investment tax credit (Note 10) .......... 4,839 32,465
Unamortized gain -- sale of utility
plant (Note 9) ................................... 73,212 77,787
Customer advances for construction ................ 38,150 31,451
Other ............................................. 373,004 369,091
---------- ----------
Total Deferred Credits and Other ................ 1,667,290 1,822,801
---------- ----------
Commitments and Contingencies (Note 12)
Total ............................................. $6,117,624 $6,393,299
========== ==========
27
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
Year Ended December 31,
-----------------------------------
1999 1998 1997
--------- --------- ---------
(Thousands of Dollars)
Cash Flows from Operations:
Net income ............................................ $ 128,437 $ 255,247 $ 251,493
Items not requiring cash:
Depreciation and amortization ....................... 382,057 376,574 365,671
Nuclear fuel amortization ........................... 31,371 32,856 32,702
Deferred income taxes -- net ........................ (29,654) (26,374) (55,278)
Deferred investment tax credit -- net ............... (27,626) (27,628) (27,630)
Extraordinary Charge -- net of income taxes ......... 139,885 -- --
Changes in certain current assets and liabilities:
Accounts receivable -- net .......................... (8,363) (56,490) (11,069)
Accrued utility revenues ............................ (5,179) (9,181) (3,089)
Materials, supplies and fossil fuel ................. (8,794) (2,797) 7,793
Other current assets ................................ (4,190) (2,166) (1,762)
Accounts payable .................................... 22,992 33,731 (56,710)
Accrued taxes ....................................... 3,031 (26,059) (441)
Accrued interest .................................... 1,081 (442) (7,455)
Other current liabilities ........................... 7,833 (4,654) (3,997)
Other -- net .......................................... (4,922) (29,641) 46,625
--------- --------- ---------
Net cash provided ................................... 627,959 512,976 536,853
--------- --------- ---------
Cash Flows from Investing:
Capital expenditures .................................. (322,547) (319,142) (307,876)
Capitalized interest .................................. (6,679) (16,263) (16,208)
Other ................................................. (8,173) (8,593) (15,982)
--------- --------- ---------
Net cash used ....................................... (337,399) (343,998) (340,066)
--------- --------- ---------
Cash Flows from Financing:
Long-term debt ........................................ 392,952 126,245 109,906
Short-term borrowings -- net .......................... (140,530) 48,080 113,850
Common equity infusion from parent .................... 50,000 50,000 50,000
Dividends paid on common stock ........................ (170,000) (170,000) (170,000)
Dividends paid on preferred stock ..................... (1,393) (10,279) (13,307)
Repayment of preferred stock .......................... (96,499) (75,517) (47,201)
Repayment and reacquisition of long-term debt ......... (323,171) (144,501) (240,004)
--------- --------- ---------
Net cash used ....................................... (288,641) (175,972) (196,756)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents..... 1,919 (6,994) 31
Cash and cash equivalents at beginning of year .......... 5,558 12,552 12,521
--------- --------- ---------
Cash and cash equivalents at end of year ................ $ 7,477 $ 5,558 $ 12,552
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest (excluding capitalized interest) ........... $ 132,995 $ 128,627 $ 141,991
Income taxes ........................................ $ 189,002 $ 235,475 $ 236,676
See Notes to Financial Statements.
28
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
------------------------------
1999 1998 1997
-------- -------- --------
(Thousands of Dollars)
Retained earnings at beginning of year ......... $601,968 $528,798 $460,106
Add: Net income ................................ 128,437 255,247 251,493
-------- -------- --------
Total ........................................ 730,405 784,045 711,599
-------- -------- --------
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 12,801
Other ........................................ 1,181 2,374 --
-------- -------- --------
Total deductions ........................... 172,197 182,077 182,801
-------- -------- --------
Retained earnings at end of year ............... $558,208 $601,968 $528,798
======== ======== ========
See Notes to Financial Statements.
29
APS
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS. We are Arizona's largest electric utility, with
approximately 827,000 customers. We provide 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, sell and deliver electricity and energy-related
products and services to wholesale and retail customers in the western United
States.
ACCOUNTING RECORDS. Our accounting records are maintained in accordance with
generally accepted accounting principles (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 Federal Energy
Regulatory Commission (FERC). The accompanying financial statements reflect the
rate-making policies of these commissions. For our regulated operations, 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.
During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (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.
In September 1999, our Settlement Agreement was approved by the ACC (see Note 3
for a discussion of the agreement). We have discontinued the application of SFAS
No. 71 for our generation operations. This means that the generation assets were
tested for impairment and the portion of regulatory assets that were deemed to
be unrecoverable through ongoing regulated cash flows was eliminated. We
determined that the generation assets were not impaired. 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. Prior to the 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 this Settlement Agreement are now
being amortized as follows:
(Millions of Dollars)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
The majority of our regulatory assets relate to deferred income taxes (see Note
10) and rate synchronization cost deferrals (see "Rate Synchronization Cost
Deferrals" in this Note).
30
APS
NOTES TO FINANCIAL STATEMENTS
The balance sheets include the amounts listed below for generation assets not
subject to SFAS No. 71:
(Thousands of Dollars)
December 31, December 31,
1999 1998
----------- -----------
Electric plant in service and held for future use .. $ 3,770,234 $ 3,680,482
Accumulated depreciation and amortization .......... (1,817,589) (1,681,099)
Construction work in progress ...................... 67,306 107,324
Nuclear fuel, net of amortization .................. 49,114 51,078
COMMON STOCK All of the outstanding shares of our common stock are owned by
Pinnacle West (see Note 4).
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.
UTILITY PLANT AND DEPRECIATION Utility plant is the term we use to describe the
business property and equipment that supports electric service. We report
utility plant at its original cost, which includes:
* material and labor
* contractor costs
* construction overhead costs (where applicable) and
* capitalized interest or an allowance for funds used during
construction.
We charge retired utility plant, plus removal costs less salvage realized, to
accumulated depreciation. See Note 2 for information on a proposed accounting
standard that impacts accounting for removal costs.
We record depreciation on utility property on a straight-line basis. For the
years 1997 through 1999 the rates, as prescribed by our regulators, ranged from
a low of 1.51% to a high of 20%. The weighted-average rate for 1999 was 3.34%.
We depreciate non-utility property and equipment over the estimated useful lives
of the related assets, ranging from 3 to 50 years.
CAPITALIZED INTEREST Capitalized interest represents the cost of debt funds used
to finance construction of utility plant. 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 6.65% for 1999, 6.88% for 1998, and 7.25% for 1997.
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 expect to produce with that fuel.
We then multiply that rate by
31
APS
NOTES TO FINANCIAL STATEMENTS
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 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.
CASH AND CASH EQUIVALENTS For purposes of reporting cash flows, we define cash
equivalents as highly liquid investments that will mature in three months or
less.
RECLASSIFICATIONS We reclassified certain prior year amounts for comparison
purposes with the 1999 presentation.
2. ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which is
effective for us in 2001. 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. The standard also provides specific guidance
for accounting for derivatives designated as hedging instruments. We are
currently evaluating what impact this standard will have on our financial
statements.
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 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
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 Settlement Agreement, with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement Agreement. One of the parties questioned
the authority of the ACC to approve the Settlement Agreement and both parties
challenged several specific provisions of the Settlement Agreement.
32
APS
NOTES TO FINANCIAL STATEMENTS
The following are the major provisions of the Settlement Agreement, as approved:
* We will reduce rates for standard offer service for customers with
loads less than 3 megawatts 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) includes the July 1, 1999 retail
price decrease of approximately $11 million annually ($7 million after
income taxes) related to the 1996 regulatory agreement. See "1996
Regulatory Agreement" below. For customers having loads 3 megawatts or
greater, standard offer rates will be reduced in annual increments
that total 5% through 2002.
* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the Settlement Agreement, retroactive to July 1, 1999, and
also will be 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 the Company 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 our "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 will be 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), with an
additional 140 megawatts being made available to eligible
non-residential customers. Unless subject to judicial or regulatory
restraint, we will open our distribution system to retail access for
all customers on January 1, 2001.
* Prior to the Settlement Agreement, we were recovering substantially
all of our regulatory assets through July 1, 2004, pursuant to the
1996 regulatory agreement. In addition, the 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 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 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 that 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. 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.
33
APS
NOTES TO FINANCIAL STATEMENTS
* When the 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 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 Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," 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 (Rules). If any of the Rules conflict with the
Settlement Agreement, the terms of the Settlement Agreement govern. 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 and the adoption or amendment of the Rules,
but two related cases filed by other utilities have been partially decided in a
manner adverse to those utilities' positions. On January 14, 2000, a special
action was filed requesting the Arizona Supreme Court to enjoin implementation
of the Rules and decide whether the ACC can allow the competitive marketplace,
rather than the ACC, to set just and reasonable rates under the Arizona
Constitution. The issue of competitively set rates has been decided by lower
Arizona courts in favor of the ACC in four separate lawsuits, two of which
relate to telecommunications companies. The Supreme Court denied to hear the
case as a special action on March 17, 2000. The lower court litigation will
continue.
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.
* The Rules require each affected utility, including us, to make
available at least 20% of its 1995 system retail peak demand for
competitive generation supply beginning when the ACC makes a final
decision on each utility's stranded costs and unbundled rates (Final
Decision Date) or January 1, 2001, whichever is earlier, and 100%
beginning January 1, 2001. Under the Settlement Agreement, the Company
will provide retail access to customers representing the minimum 20%
required by the ACC and an additional 140 megawatts of non-residential
load in 1999, and to all customers as of January 1, 2001, or such
other dates as approved by the ACC.
* Subject to the 20% requirement, all utility customers with single
premise loads of one megawatt or greater will be eligible for
competitive electric services on the Final Decision Date, which for
the Company's customers was the approval of the Settlement Agreement.
Customers may also aggregate smaller loads to meet this one megawatt
requirement.
* When effective, residential customers will be phased in at 1.25% per
quarter calculated beginning on January 1, 1999, subject to the 20%
requirement above.
* Electric service providers that get Certificates of Convenience and
Necessity (CC&Ns) 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.
34
APS
NOTES TO FINANCIAL STATEMENTS
* 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 Settlement Agreement, the
Company received a waiver to allow transfer of its competitive
generation assets and services to affiliates no later than December
31, 2002.
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 of
approximately $49 million ($29 million after income taxes), or 3.4%, effective
July 1, 1996; approximately $18 million ($11 million after income taxes), or
1.2%, effective July 1, 1997; approximately $17 million ($10 million after
income taxes), or 1.1%, effective July 1, 1998; and approximately $11 million
($7 million after income taxes), or 0.7%, effective as of July 1, 1999. The July
1, 1999 rate decrease was included in the first rate reduction under the
Settlement Agreement discussed above. The regulatory agreement also required
Pinnacle West to 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:
* 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 megawatt (and that are eligible for competitive generation
services), and thereafter for all customers receiving competitive electric
generation.
In addition, the Arizona legislature will review and make recommendations for
the 1999-2000 legislative session on certain competitive issues.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, or results of operation. 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 Energy Policy Act of 1992 and recent rulemakings by FERC have promoted
increased competition in the wholesale electric power markets. We do not expect
these rules to have a material impact on our financial statements.
35
APS
NOTES TO FINANCIAL STATEMENTS
Several electric utility industry restructuring bills have been introduced
during the 106th Congress. Several of these bills are written to allow consumers
to choose their electricity suppliers beginning in 2000 and beyond. These bills,
other bills that 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.
AGREEMENT WITH SALT RIVER PROJECT
On April 25, 1998, we entered into a Memorandum of Agreement with Salt River
Project in anticipation of, and to facilitate, the opening of the Arizona
electric industry. The ACC approved the Agreement on February 18, 1999. The
Agreement contains the following major components:
* Both parties amended the Territorial Agreement to remove any barriers
to the provision of competitive electricity supply and
non-distribution services.
* Both parties amended the Power Coordination Agreement to lower the
price that we pay Salt River Project for purchased power. During 1999,
the price we paid Salt River Project for purchased power was reduced
by approximately $3 million (pretax) and we estimate the decrease to
be approximately $16 million (pretax) in 2000 and annual lesser
amounts through 2006.
* Both parties agreed on certain legislative positions regarding
electric utility restructuring at the state and federal levels.
Certain provisions of the Agreement (including those relating to the amendments
of the Territorial Agreement and the Power Coordination Agreement) became
effective upon the introduction of competition. See "Settlement Agreement" and
"ACC Rules" above.
36
APS
NOTES TO FINANCIAL STATEMENTS
4. COMMON AND PREFERRED STOCKS
On March 1, 1999, we redeemed all of our preferred stock. Common and preferred
stock balances at December 31, 1999 and 1998 are shown below:
Number
of Shares Par Par Value
Outstanding Value Outstanding
-------------------------- Per -----------------------
Authorized 1999 1998 Share 1999 1998
----------- ----------- ------------ ------- ---------- ----------
(Thousands of Dollars)
Common Stock................. 100,000,000 71,264,947 71,264,947 $ 2.50 $ 178,162 $ 178,162
=========== ============ ========== ==========
Preferred Stock:
Non-Redeemable:
$1.10..................... 160,000 -- 139,030 $ 25.00 $ -- $ 3,476
$2.50..................... 105,000 -- 86,440 50.00 -- 4,322
$2.36..................... 120,000 -- 32,520 50.00 -- 1,626
$4.35..................... 150,000 -- 62,986 100.00 -- 6,299
Serial preferred.......... 1,000,000
$2.40 Series A......... -- 200,587 50.00 -- 10,029
$2.625 Series C......... -- 214,895 50.00 -- 10,745
$2.275 Series D......... -- 90,691 50.00 -- 4,534
$3.25 Series E......... 304,475 50.00 -- 15,224
Serial preferred.......... 4,000,000
Adjustable rate --
Series Q.............. -- 295,851 100.00 -- 29,585
----------- ------------ ---------- ----------
Total................. -- 1,427,475 $ -- $ 85,840
=========== ============ ========== ==========
Redeemable:
Serial preferred:
$10.00 Series U........ -- 94,011 $100.00 $ -- $ 9,401
=========== ============ ========== ==========
Redeemable preferred stock transactions during each of the three years in the
period ended December 31, 1999 are as follows:
Number of Shares Par Value
Outstanding Outstanding
------------------------------ ------------------------------
(Thousands of Dollars)
Description 1999 1998 1997 1999 1998 1997
----------- -------- -------- -------- -------- -------- --------
Balance, January 1............... 94,011 291,098 530,000 $ 9,401 $ 29,110 $ 53,000
Retirements:
$10.00 Series U............. (94,011) (197,087) (118,902) (9,401) (19,709) (11,890)
$7.875 Series V............. -- -- (120,000) -- -- (12,000)
-------- -------- -------- -------- -------- --------
Balance, December 31............. -- 94,011 291,098 $ -- $ 9,401 $ 29,110
======== ======== ======== ======== ======== ========
37
APS
NOTES TO FINANCIAL STATEMENTS
5. LONG-TERM DEBT
The following table presents the components of long-term debt outstanding at
December 31, 1999 and December 31, 1998:
December 31
-----------------------
Maturity Dates Interest 1999 1998
-------------- -------- ---------- ----------
(A) Rates (Thousands of Dollars)
First mortgage bonds 1999 7.625% $ -- $ 100,000
2000 5.75% 100,000 100,000
2002 8.125% 125,000 125,000
2004 6.625% 80,000 85,000
2020 10.25% 100,550 100,550
2021 9.5% 45,140 45,140
2021 9% 72,370 72,370
2023 7.25% 70,650 91,900
2024 8.75% 121,668 121,668
2025 8% 47,075 88,300
2028 5.5% 25,000 25,000
2028 5.875% 154,000 154,000
Unamortized discount and premium (5,860) (6,482)
Pollution control bonds 2024-2034 Adjustable 476,860 456,860
rate (b)
Funds held in trust account for certain
pollution control bonds (1,236) --
Collateralized loan 1999-2000 5.375% - 10,000 20,000
6.125%
Unsecured notes 2005 6.25% 100,000 100,000
Unsecured notes 2004 5.875% 125,000 --
Floating rate notes 2001 Adjustable 250,000
rate (c)
Senior notes(d) 1999 6.72% -- 50,000
Senior notes(d) 2006 6.75% 83,695 100,000
Debentures 2025 10% 75,000 75,000
Bank loans 2003 Adjustable 50,000 125,000
rate (e)
Capitalized lease obligation 1999-2001 7.48% (f) 7,199 11,612
---------- ----------
Total long-term debt 2,112,111 2,040,918
Less current maturities 114,711 164,378
---------- ----------
Total long-term debt less current maturities $1,997,400 $1,876,540
========== ==========
- ----------
(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, 1999 was 3.15%
And for December 31, 1998 was 3.39%. Changes in short-term interest rates
would affect the costs associated with this debt.
38
APS
NOTES TO FINANCIAL STATEMENTS
(c) The weighted average rate for the year ended 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, 1999 was 5.50%
And for December 31, 1998 was 5.94%. Changes in short-term interest rates
would affect the costs associated with this debt.
(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 (see Note 9).
Principal payments due on total long-term debt and sinking fund requirements
over the next five years are approximately:
* $115 million in 2000
* $253 million in 2001
* $125 million in 2002
* $50 million in 2003 and
* $205 million in 2004.
First mortgage bondholders share a lien on substantially all utility plant
assets (other than nuclear fuel, transportation equipment, and the combined
cycle plant). The mortgage bond indenture restricts the payment of common stock
dividends under certain conditions. These conditions did not exist at December
31, 1999.
6. LINES OF CREDIT
We had committed lines of credit with various banks of $350 million at December
31, 1999 and $400 million at December 31, 1998, which were available either to
support the issuance of commercial paper or to be used for bank borrowings. The
commitment fees at December 31, 1999 and 1998 for these lines of credit ranged
from 0.07% to 0.125% per annum. We had long-term bank borrowings of $50 million
outstanding at December 31, 1999 and $125 million outstanding at December 31,
1998.
Our commercial paper borrowings outstanding were $38 million at December 31,
1999 and $179 million at December 31, 1998. The weighted average interest rate
on commercial paper borrowings was 5.33% for the year ended December 31, 1999
and 5.88% for December 31, 1998. 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, 1999 and
1998 due to their short maturities. We hold investments in debt and equity
securities for purposes other than trading. The December 31, 1999 and 1998 fair
values of such
39
APS
NOTES TO FINANCIAL STATEMENTS
investments, which we determine by using quoted market values or by discounting
cash flows at rates equal to our cost of capital, approximate their carrying
amounts.
The carrying value of our long-term debt (excluding a capitalized lease
obligation) was $2.10 billion on December 31, 1999, with an estimated fair value
of $2.08 billion. On December 31, 1998, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.03 billion, with an estimated
fair value of $2.11 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, 1999. Our share of operating and maintaining these
facilities is included in the income statement in operations and maintenance
expense.
Percent Construction
Owned by Plant in Accumulated Work in
Company Service Depreciation Progress
------- ------- ------------ --------
(Thousands of Dollars)
Generating Facilities:
Palo Verde Nuclear Generating Station
Units 1 and 3 29.1% $1,829,633 $751,567 $ 7,220
Palo Verde Nuclear Generating Station
Unit 2 (see Note 9) 17.0% 572,574 240,696 17,145
Four Corners Steam Generating Station
Units 4 and 5 15.0% 139,209 71,333 364
Navajo Steam Generating Station
Units 1, 2, and 3 14.0% 230,536 94,332 4,555
Cholla Steam Generating Station
Common Facilities (a) 62.8%(b) 68,643 38,068 1,679
Transmission Facilities:
ANPP 500KV System 35.8%(b) 68,133 21,446 7
Navajo Southern System 31.4%(b) 27,364 17,550 42
Palo Verde-Yuma 500KV System 23.9%(b) 11,728 4,388 36
Four Corners Switchyards 27.5%(b) 3,071 1,855 --
Phoenix-Mead System 17.1%(b) 36,434 1,768 --
- ----------
(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
40
APS
NOTES TO FINANCIAL STATEMENTS
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 $46 million in 2000 and approximately $49 million per year in
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. The accelerated amortization is included in
depreciation and amortization expense on the Statements of Income. The balance
of this regulatory asset at December 31, 1999 was $43 million. Lease expense was
approximately $42 million in each of the years 1997 through 1999.
We have a capital lease on a combined cycle plant, which we sold and leased
back. The lease requires semiannual payments of $3 million through June 2001,
and includes renewal and purchase options based on fair market value. The plant
is included in plant in service at its original cost of $54 million; accumulated
amortization at December 31, 1999 was $51 million.
In addition, we lease certain land, buildings, equipment, and miscellaneous
other items through operating rental agreements with varying terms, provisions,
and expiration dates.
Miscellaneous lease expense was approximately $7 million in 1999, $10 million in
1998 and $8 million in 1997.
Estimated future minimum lease commitments, excluding the Palo Verde and
combined cycle leases, are as follows:
Year (Dollars in Millions)
----
2000 $ 13
2001 14
2002 14
2003 14
2004 14
Thereafter 82
-----
Total future commitments $ 151
=====
10. 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 investment tax credits
(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
41
APS
NOTES TO FINANCIAL STATEMENTS
construction. We amortize this amount as the differences reverse. In accordance
with the 1999 Settlement Agreement, we are continuing to accelerate the
amortization of the regulatory asset for income taxes over an eight-year period
that will end on June 30, 2004. We have included this accelerated amortization
in depreciation and amortization expense on the Statements of Income.
The components of income tax expense for income before the extraordinary charge
are as follows:
Year Ended December 31,
-----------------------------------
1999 1998 1997
--------- --------- ---------
(Thousands of dollars)
Current:
Federal .............................. $ 175,227 $ 170,806 $ 187,701
State ................................ 41,541 42,652 48,531
--------- --------- ---------
Total current ...................... 216,768 213,458 236,232
Deferred ................................ (29,654) (26,374) (55,278)
Investment tax credit amortization ...... (27,626) (27,628) (27,630)
--------- --------- ---------
Total expense ...................... $ 159,488 $ 159,456 $ 153,324
========= ========= =========
The following chart compares pretax income at the 35% federal income tax rate to
income tax expense:
Year Ended December 31,
-----------------------------------
1999 1998 1997
--------- --------- ---------
(Thousands of Dollars)
Federal income tax expense at 35% statutory rate ....... $ 149,710 $ 145,146 $ 141,686
Increases (reductions) in tax expense resulting from:
Tax under book depreciation ......................... 14,575 17,848 14,694
Investment tax credit amortization .................. (27,626) (27,628) (27,630)
State income tax -- net of federal
income tax benefit................................. 24,135 23,024 23,160
Other ............................................... (1,306) 1,066 1,414
--------- --------- ---------
Income tax expense ................................ $ 159,488 $ 159,456 $ 153,324
========= ========= =========
The components of the net deferred income tax liability were as follows:
December 31,
-----------------------
1999 1998
---------- ----------
(Thousands of Dollars)
Deferred tax assets:
Deferred gain on Palo Verde Unit 2 sale/leaseback .. $ 29,446 $ 31,285
Other .............................................. 139,518 159,432
---------- ----------
Total deferred tax assets ........................ 168,964 190,717
---------- ----------
Deferred tax liabilities:
Plant related ...................................... 1,104,769 1,117,253
Regulatory assets .................................. 234,117 381,472
---------- ----------
Total deferred tax liabilities ................... 1,338,886 1,498,725
---------- ----------
Deferred income taxes -- net .......................... $1,169,922 $1,308,008
========== ==========
42
APS
NOTES TO FINANCIAL STATEMENTS
11. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLAN. Through 1999, we sponsored a defined benefit pension plan for our
employees. As of January 1, 2000, this plan is now sponsored by Pinnacle West. A
defined benefit plan specifies the amount of benefits a plan participant is to
receive using information about the participant. The plan covers nearly all of
our employees. Our employees do not contribute to this plan. Generally, we
calculate the benefits under this plan based on age, years of service, and pay.
We fund the plan by contributing at least the minimum amount required under
Internal Revenue Service regulations but no more than the maximum tax-deductible
amount. The assets in the plan at December 31, 1999 were mostly domestic and
international common stocks and bonds and real estate. Pension expense,
including administrative costs, was:
* $4 million in 1999
* $10 million in 1998 and
* $9 million in 1997.
The following table shows the components of net pension cost before
consideration of amounts capitalized or billed to others:
1999 1998 1997
-------- -------- --------
(Thousands of Dollars)
Service cost -- benefits earned during the period...... $ 24,266 $ 24,126 $ 19,881
Interest cost on projected benefit obligation ......... 52,208 50,863 47,824
Expected return on plan assets ........................ (67,528) (53,883) (47,422)
Amortization of:
Transition asset .................................... (3,216) (3,216) (3,216)
Prior service cost .................................. 2,063 2,063 2,063
-------- -------- --------
Net periodic pension cost ............................. $ 7,793 $ 19,953 $ 19,130
======== ======== ========
The following table shows a reconciliation of the funded status of the plan to
the amounts recognized in the balance sheets:
1999 1998
-------- --------
(Thousands of Dollars)
Funded status -- Pension plan assets more than
(less than) projected benefit obligation .............. $ 37,784 $(38,957)
Unrecognized net transition asset ....................... (19,943) (23,159)
Unrecognized prior service cost ......................... 20,499 22,562
Unrecognized net actuarial gains ........................ (99,602) (38,916)
-------- --------
Net pension liability recognized in the balance sheets .. $(61,262) $(78,470)
======== ========
43
APS
NOTES TO FINANCIAL STATEMENTS
The following table sets forth the defined benefit pension plan's change in
projected benefit obligation for the plan years 1999 and 1998:
1999 1998
--------- ---------
(Thousands of Dollars)
Projected pension benefit obligation
at beginning of year ............................... $ 721,229 $ 699,600
Service cost ......................................... 24,266 24,126
Interest cost ........................................ 52,208 50,863
Benefit payments ..................................... (29,444) (29,384)
Actuarial gains ...................................... (35,348) (23,976)
--------- ---------
Projected pension benefit obligation
at end of year ..................................... $ 732,911 $ 721,229
========= =========
The following table sets forth the defined benefit pension plan's change in the
fair value of plan assets for the plan years 1999 and 1998:
1999 1998
--------- ---------
(Thousands of Dollars)
Fair value of pension plan assets at
beginning of year ................................... $ 682,272 $ 612,392
Actual return on plan assets ......................... 92,867 85,764
Employer contributions ............................... 25,000 13,500
Benefit payments ..................................... (29,444) (29,384)
--------- ---------
Fair value of pension plan assets at end of year ..... $ 770,695 $ 682,272
========= =========
We made the assumptions below to calculate
the pension liability:
Discount rate .................................... 7.75% 7.00%
Rate of increase in compensation levels .......... 4.25% 3.50%
Expected long-term rate of return on assets ...... 10.00% 10.00%
EMPLOYEE SAVINGS PLAN BENEFITS. Through 1999, we sponsored a defined
contribution savings plan for nearly all of our employees. As of January 1,
2000, this plan is now sponsored by Pinnacle West and covers nearly all of our
employees. In a defined contribution plan, the benefits a participant will
receive result from regular contributions they make to a participant account.
Under this plan, we make matching contributions to participant accounts. We
recorded expenses for this plan of approximately $4 million for each of the last
three years (1997-1999).
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.
44
APS
NOTES TO FINANCIAL STATEMENTS
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:
* $6 million for 1999
* $9 million for 1998 and
* $9 million for 1997.
The following table shows the components of net periodic postretirement benefit
costs before consideration of amounts capitalized or billed to others:
1999 1998 1997
-------- -------- --------
(Thousands of Dollars)
Service cost -- benefits earned during
the period ..................................... $ 8,676 $ 7,676 $ 6,865
Interest cost on accumulated benefit
obligation ..................................... 17,188 15,610 14,315
Expected return on plan assets .................. (18,454) (12,001) (8,706)
Amortization of:
Transition obligation ....................... 7,652 7,652 7,652
Net actuarial gains ......................... (5,095) (2,927) (2,647)
-------- -------- --------
Net periodic postretirement benefit cost ........ $ 9,967 $ 16,010 $ 17,479
======== ======== ========
The following table shows a reconciliation of the funded status of the plan to
the amounts recognized in the balance sheets:
1999 1998
--------- ---------
(Thousands of Dollars)
Funded status -- postretirement plan assets more than
(less than) accumulated benefit obligation ......... $ 27,930 $ (21,912)
Unrecognized net obligation at transition ............ 99,482 107,134
Unrecognized net actuarial gains ..................... (127,338) (86,131)
--------- ---------
Net postretirement amount recognized
in the balance sheets .............................. $ 74 $ (909)
========= =========
The following table sets forth the postretirement benefit plan's change in
accumulated benefit obligation for the plan years 1999 and 1998:
1999 1998
--------- ---------
(Thousands of Dollars)
Accumulated postretirement benefit
obligation at beginning of year .................... $ 235,322 $ 197,581
Service cost ......................................... 8,675 7,676
Interest cost ........................................ 17,188 15,610
Benefit payments ..................................... (8,761) (10,347)
Actuarial (gains) losses ............................. (22,816) 24,802
--------- ---------
Accumulated postretirement benefit
obligation at end of year .......................... $ 229,608 $ 235,322
========= =========
45
APS
NOTES TO FINANCIAL STATEMENTS
The following table sets forth the postretirement benefit plan's change in the
fair value of plan assets for the plan years 1999 and 1998:
1999 1998
--------- ---------
(Thousands of Dollars)
Fair value of postretirement plan
assets at beginning of year ........................ $ 213,410 $ 151,146
Actual return on plan assets ......................... 42,975 47,284
Employer contributions ............................... 9,914 25,327
Benefit payments ..................................... (8,761) (10,347)
--------- ---------
Fair value of postretirement plan
assets at end of year .............................. $ 257,538 $ 213,410
========= =========
We made the assumptions below to calculate the postretirement liability:
Discount rate........................................................... 7.75% 7.00%
Expected long-term rate of return on assets-after tax................... 8.77% 8.73%
Initial health care cost trend rate - under age 65...................... 7.00% 7.50%
Initial health care cost trend rate - age 65 and over................... 6.00% 6.50%
Ultimate health care cost trend rate (reached in the year 2002) ........ 5.00% 5.00%
Assuming a 1% increase in the health care cost trend rate, the 1999 cost of
postretirement benefits other than pensions would increase by approximately $5
million and the accumulated benefit obligation as of December 31, 1999 would
increase by approximately $37 million.
Assuming a 1% decrease in the health care cost trend rate, the 1999 cost of
postretirement benefits other than pensions would decrease by approximately $4
million and the accumulated benefit obligations as of December 31, 1999 would
decrease by approximately $29 million.
12. COMMITMENTS AND CONTINGENCIES
LITIGATION. We are a 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.
PALO VERDE NUCLEAR GENERATING STATION. Under the Nuclear Waste Policy Act, DOE
was to develop the facilities necessary for the storage and disposal of spent
fuel and to have the first such facility in operation by 1998. That facility was
to be a permanent repository, but DOE has announced that such a repository now
cannot be completed before 2010. In response to lawsuits filed over DOE's
obligation to accept used nuclear fuel, the United States Court of Appeals for
the D.C. Circuit has ruled that DOE had an obligation to begin accepting used
nuclear fuel in 1998. However, the Court refused to issue an order compelling
DOE to begin moving used fuel. Instead, the Court ruled that any damages to
utilities should be sought under the standard contract signed between DOE and
utilities, including us. The United States Supreme Court has refused to grant
review of the D.C. Circuit's decision.
We have capacity in existing fuel storage pools at Palo Verde which, with
certain modifications, could accommodate all fuel expected to be discharged from
normal operation of Palo Verde through about 2002, and believe we could augment
that wet storage with new facilities for on-site dry storage of spent fuel for
an indeterminate period of operation beyond 2002, subject to obtaining any
required governmental approvals. We currently estimate that we will incur $113
million (in 1999 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,
1999, we had recorded a liability and regulatory asset of $37 million for
on-site interim nuclear fuel storage costs related to nuclear fuel
46
APS
NOTES TO FINANCIAL STATEMENTS
burned to date. We currently believe that spent fuel storage or disposal methods
will be available for use by Palo Verde to allow its continued operation beyond
2002.
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 29.1%
interest in the three Palo Verde units, our maximum potential assessment per
incident for all three units is approximately $77 million, with an annual
payment limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
FUEL AND PURCHASED POWER COMMITMENTS. We are a party to various fuel and
purchased power contracts with terms expiring from 2000 through 2020 that
include required purchase provisions. We estimate our 2000 contract requirements
to be about $177 million. 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 $57 million at December 31, 1999 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 approved by 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, 1999 was about $41 million.
CONSTRUCTION PROGRAM. Total capital expenditures in 2000 are estimated at $384
million.
13. NUCLEAR DECOMMISSIONING COSTS
We recorded $11 million for decommissioning expense in each of the years 1999,
1998, and 1997. We estimate it will cost about $1.8 billion ($472 million in
1999 dollars) to decommission our 29.1% 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 include them in the accumulated depreciation balance
until each unit is retired. Nuclear decommissioning costs are recovered in
rates.
Our current estimates are based on a 1998 site-specific study for Palo Verde
that assumes the prompt removal/dismantlement method of decommissioning. An
independent consultant prepared this study for us. 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 trusts in accordance with Nuclear Regulatory Commission (NRC)
regulations. The trust accounts are reported in "Investments and Other Assets"
in our Balance Sheets at their market value of $176 million at December 31, 1999
and $146 million at
47
APS
NOTES TO FINANCIAL STATEMENTS
December 31, 1998. 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 1999 and 1998 is as follows:
Electric Earnings/
Operating Operating Net Income/ (Loss) for
Quarter Ended Revenues Income (a) (Loss) (b) Common Stock
- ------------- -------- ---------- ---------- ------------
(Thousands of Dollars)
1999
March 31 $413,983 $ 66,956 $ 33,795 $ 32,779
June 30 511,434 98,503 69,542 69,542
September 30 867,504 150,914 (10,377) (10,377)
December 31 499,877 72,551 35,477 35,477
1998
March 31 $380,423 $ 63,541 $ 31,935 $ 29,057
June 30 441,715 81,299 52,184 49,749
September 30 740,734 155,079 133,193 130,846
December 31 443,526 70,892 37,935 35,892
- ----------
(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 ended September 30, 1999 includes an 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 most recent plan provides for the granting of new options (which may be
non-qualified stock options or incentive stock options) of up to 3.5 million
shares at a price per option not less than the fair market value on the date the
option is granted. The plan also provides for the granting of any combination of
restricted stock, stock appreciation rights or dividend equivalents. The awards
outstanding under the incentive plans at December 31, 1999 approximate 1,441,124
non-qualified stock options, 159,837 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. This statement encourages, but does not
require, that a company record compensation expense based on the fair value
method. We continue to recognize expense based on Accounting Principles Board
Opinion No. 25,
48
APS
NOTES TO FINANCIAL STATEMENTS
"Accounting for Stock Issued to Employees." 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:
1999 1998 1997
-------- -------- --------
(Thousands of Dollars)
Net income
As reported.......................... $128,437 $255,247 $251,493
Pro forma (fair value method)........ $127,658 $254,640 $251,142
We did not consider compensation costs for stock options granted before January
1, 1995. Therefore, future reported net income may not be representative of this
compensation cost calculation.
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:
1999 1998 1997
-------- -------- --------
Risk-free interest rate................ 5.68% 4.54% 5.66%
Dividend yield......................... 3.33% 3.03% 4.50%
Volatility............................. 20.50% 18.80% 15.63%
Expected life (months)................. 60 60 60
16. BUSINESS SEGMENTS
Historically, we reported our operations as a single, integrated business
segment due to our regulated operating environment. The ACC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover the Company's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the 1999 Settlement Agreement, our generation operations are now
deregulated for accounting purposes. For the purposes of complying with SFAS No.
131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS
No. 131), we are required to disclose information about our business segments
separately. Accordingly, we have separately identified expenses between the two
segments and allocated revenues and other expenses using a study that identifies
the portion of our base rates related to generation and delivery. We then used
that information to develop the financial information of the business segments
for each of the three years ended December 31, 1999 (or as of December 31, 1999
and 1998, with respect to assets).
Beginning in 1999, we have two principal business segments (determined by
products, services and regulatory environment) which consist of the generation
of electricity (generation business segment) and the transmission and
distribution of electricity (delivery business segment). Intercompany
eliminations primarily relate to intercompany sales of electricity. Financial
data for business segments is provided as follows:
49
APS
NOTES TO FINANCIAL STATEMENTS
Business Segments
-----------------------
Generation Delivery Eliminations Total
---------- ---------- ---------- ----------
(Thousands of Dollars)
YEAR ENDED DECEMBER 31, 1999
Operating Revenues ........................ $ 853,755 $2,292,798 $ (853,755) $2,292,798
Operating Expenses ........................ 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
---------- ---------- ---------- ----------
Pre-Tax 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 .............................. $2,321,778 $3,795,846 $ -- $6,117,624
========== ========== ========== ==========
Capital Expenditures ...................... $ 90,285 $ 241,469 $ -- $ 331,754
========== ========== ========== ==========
YEAR ENDED DECEMBER 31, 1998
Operating Revenues ........................ $ 858,340 $2,006,398 $ (858,340) $2,006,398
Operating Expenses ........................ 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
---------- ---------- ---------- ----------
Pre-Tax 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 $3,993,740 $ -- $6,393,300
========== ========== ========== ==========
Capital Expenditures ...................... $ 85,767 $ 241,638 $ -- $ 327,405
========== ========== ========== ==========
YEAR ENDED DECEMBER 31, 1997
Operating Revenues ........................ $ 803,647 $1,878,553 $ (803,647) $1,878,553
Operating Expenses ........................ 471,992 1,297,802 (803,647) 966,147
---------- ---------- ---------- ----------
Operating Margin ........................ 331,655 580,751 -- 912,406
Depreciation and Amortization ............. 131,684 233,987 -- 365,671
Interest and Preferred Stock Dividend
Requirements ............................ 50,311 104,410 -- 154,721
---------- ---------- ---------- ----------
Pre-Tax Margin .......................... 149,660 242,354 -- 392,014
Income Taxes .............................. 44,898 108,426 -- 153,324
---------- ---------- ---------- ----------
Earnings for Common Stock ............... $ 104,762 $ 133,928 $ -- $ 238,690
========== ========== ========== ==========
Capital Expenditures ...................... $ 84,960 $ 217,047 $ -- $ 302,007
========== ========== ========== ==========
50
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.
51
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
27.1 -- Financial Data Schedule
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
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
52
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
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 of Report
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
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
53
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
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 Indenture 4.10 to Registration 1-4473 4-9-97
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
54
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
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
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
55
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.7 First Amendment to Amended 10.2 to 1992 Form 10-K 1-4473 3-30-93
and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2),
dated as of November 1, 1992
10.8 Amendment No. 2 to Amended 10.3 to 1994 Form 10-K 1-4473 3-30-95
and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2)
dated as of November 1, 1994
10.9 Amendment No. 3 to Amended 10.1 to June 1996 Form 1-4473 8-9-96
and Restated 10-Q Report
Decommissioning Trust
Agreement (PVNGS Unit 2)
dated as of January 31, 1992
10.10 Amendment No. 4 to Amended 10.5 to 1996 Form 10-K 1-4473 3-28-97
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 10.2 to June 1991 Form 1-4473 8-8-91
Transactions 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 and/or Statement
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-Term Report
Power Transactions Agreement
and Asset Purchase and Power
Exchange Agreement between
PacifiCorp and the Company
56
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.15 Restated Transmission 10.4 to 1995 Form 10-K 1-4473 3-29-96
Agreement between PacifiCorp Report
and the Company dated
April 5, 1995
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, Four Registration Statement
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 Lease, Pinnacle West
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 and Registration Statement
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
57
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.23 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
10.24 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
10.25 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.26 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70
rights-of-way and easements, Registration Statement
Navajo Plant
10.27 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
10.28 Arizona Nuclear Power 10.1 to 1988 Form 10-K 1-4473 3-8-89
Project Participation Report
Agreement, 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
58
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.29 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
Participation Agreement,
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
10.30(c) Facility Lease, dated as of 4.3 to Form S-3 33-9480 10-24-86
August 1, 1986, between Registration Statement
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor, and
the Company, as Lessee
10.31(c) Amendment No. 1, dated as of 10.5 to September 1986 1-4473 12-4-86
November 1, 1986, to Facility Form 10-Q Report by
Lease, dated as of August 1, means of Amendment No.
1986, between State Street 1 on December 3, 1986
Bank and Trust Company, as Form 8
successor to The First
National Bank of Boston, in
its capacity as Owner Trustee,
as Lessor, and the Company,
as Lessee
10.32(c) Amendment No. 2 dated as of 10.3 to 1988 Form 10-K 1-4473 3-8-89
June 1, 1987 to Facility Lease Report
dated as of August 1, 1986
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and APS, as Lessee
59
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.33(c) Amendment No. 3, dated as of 10.3 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and the Company, as
Lessee
10.34 Facility Lease, dated as of 10.1 to November 18, 1986 1-4473 1-20-87
December 15, 1986, between Form 8-K Report
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor, and
the Company, as Lessee
10.35 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
10.36 Amendment No. 2, dated as of 10.4 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of December
15, 1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and the Company, as
Lessee
10.37(a) Directors' Deferred 10.1 to June 1986 Form 1-4473 8-13-86
Compensation Plan, as 10-Q Report
restated, effective January 1,
1986
10.38(a) Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Directors' Deferred
Compensation Plan, effective
as of January 1, 1993
60
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.39(a) Third Amendment to the 10.1 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q
Company Directors' Deferred
Compensation Plan effective
as of May 1, 1993
10.40(a) Fourth Amendment dated 10.8 to Pinnacle West's 1-8962 3-30-00
December 28, 1999 to the 1999 Form 10-K
Arizona Public Service
Company Directors Deferred
Compensation Plan
10.41(a) Arizona Public Service 10.4 to 1988 Form 10-K 1-4473 3-8-89
Company Deferred Report
Compensation Plan, as
restated, effective January 1,
1984, and the second and
third amendments thereto,
dated December 22, 1986, and
December 23, 1987, respectively
10.42(a) Third Amendment to the 10.3 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.43(a) Fourth Amendment to the 10.2 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q Report
Company Deferred
Compensation Plan effective
as of May 1, 1993
10.44(a) Fifth Amendment to the 10.3 to 1997 Form 10-K 1-4473 3-28-97
Arizona Public Service Report
Company Deferred
Compensation Plan
10.45(a) Pinnacle West Capital 10.10 to 1995 Form 10-K 1-4473 3-29-96
Corporation, Arizona Public Report
Service Company, SunCor
Development Company
and El Dorado Investment
Company Deferred
Compensation Plan as
amended and restated
effective January 1, 1996
61
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.46(a) First Amendment effective as 10.6 to Pinnacle West's 1-8962 3-30-00
of January 1, 1998, 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
10.47(a) Second Amendment effective as 10.10 to Pinnacle West's 1-8962 3-30-00
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
10.48(a) Arizona Public Service 10.11 to 1995 Form 10-K 1-4473 3-29-96
Company Supplemental Report
Excess Benefit Retirement
Plan as amended and
restated on December 20, 1995
10.49(a) Pinnacle West Capital 10.13 to Pinnacle West's 1-8962 3-30-00
Corporation Supplemental 1999 Form 10-K Report
Excess Benefit Retirement
Plan, as amended and
restated, dated December 7, 1999
10.50(a) Pinnacle West Capital 10.7 to 1994 Form 10-K 1-4473 3-30-95
Corporation and Arizona Report
Public Service Company
Directors' Retirement Plan
effective as of January 1, 1995
10.51(a) Arizona Public Service 10.1 to September 1997 1-4473 11-12-97
Company Director Form 10-K Report
Equity Plan
10.52(a) Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95
December 21, 1993, between Report
the Company and William L.
Stewart
62
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.53(a) Letter Agreement dated 10.8 to 1996 Form 10-K 1-4473 3-28-97
August 16, 1996 between Report
the Company and
William L. Stewart
10.54(a) Letter Agreement between 10.2 to September 1997 1-4473 11-12-97
the Company and Form 10-Q Report
William L. Stewart
10.55(a) Letter Agreement dated 10.9 to Pinnacle West's 1-8962 3-30-00
December 13, 1999 between 1999 Form 10-K Report
the Company and
William L. Stewart
10.56(a) Letter Agreement dated as 10.8 to 1995 Form 10-K 1-4473 3-29-96
of January 1, 1996 between Report
the Company and Robert G.
Matlock & Associates, Inc.
for consulting services
10.57(a) Letter Agreement dated 10.17 to Pinnacle West's 1-8962 3-30-00
October 3, 1997 between 1999 Form 10-K Report
the Company and James M.
Levine
10.58(a) Employment Agreement, 10.1 to Pinnacle West's 1-8962 3-28-91
effective as of February 5, 1990 Form 10-K
1990, between Richard Snell
and Pinnacle West
10.59(a) First Amendment to 10.2 to Pinnacle West's 1-8962 4-1-96
Employment Agreement, 1995 Form 10-K Report
effective March 31, 1995,
between Richard Snell and
Pinnacle West
10.60(a) Second Amendment to 10.2 to Pinnacle West's 1-8962 3-31-97
Employment Agreement, 1996 Form 10-K Report
effective February 5, 1997,
between Richard Snell and
Pinnacle West
10.61(a)(d) Key Executive Employment and 10.1 to Pinnacle West's 1-8962 8-16-99
Severance Agreement between June 1999 Form 10-Q
Pinnacle West and certain Report
executive officers of Pinnacle
West and its subsidiaries
10.62(a) Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option and Report
Incentive Plan
63
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
10.63(a) First Amendment dated 10.11 to Pinnacle West's 1-8962 3-30-00
December 7, 1999 to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation Stock Option
and Incentive Plan
10.64(a) Pinnacle West Capital A to the Proxy Statement 1-8962 4-16-94
Corporation 1994 Long-Term for the Plan Report
Incentive Plan effective as of Pinnacle West 1994
March 23, 1994 Annual Meeting of
Shareholders
10.65(a) First Amendment dated 10.12 to Pinnacle West's 1-8962 3-30-00
December 7, 1999 to the 1999 Form 10-K Report
Pinnacle West Capital
Corporation 1994 Long-Term
Incentive Plan
10.66 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
10.67 First Amendment dated 10.15 to Pinnacle West's 1-8962 3-30-00
December 7, 1999 to the Trust 1999 Form 10-K Report
for the Pinnacle West Capital
Corporation, Arizona Public
Service Company and SunCor
Development Company
Deferred Compensation Plans
10.68(a) 2000 Management Variable 10.4 to Pinnacle West's 1-8962 3-30-00
Incentive Plan (APS) 1999 Form 10-K Report
10.69(a) 2000 Senior Management 10.5 to Pinnacle West's 1-8962 3-30-00
Variable Incentive Plan (APS) 1999 Form 10-K Report
10.70(a) 2000 Officer Variable 10.6 to Pinnacle West's 1-8962 3-30-00
Incentive Plan (APS) 1999 Form 10-K Report
64
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
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
65
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
99.3(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92
dated as of August 1, 1986, Form 10-Q Report
among PVNGS Funding
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
99.4(c) Amendment No. 1 dated as of 10.8 to September 1986 1-4473 12-4-86
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
66
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
99.5(c) Amendment No. 2, dated as of 28.4 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of August 1, 1986,
among PVNGS Funding
Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in its
individual capacity and as
Indenture Trustee, the
Company, and the Equity
Participant named therein
99.6(c) Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86
Security Agreement and Registration Statement
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.7(c) Supplemental Indenture No. 10.6 to September 1986 1-4473 12-4-86
1, dated as of November 1, Form 10-Q Report by
1986 to Trust Indenture, means of Amendment No.
Mortgage, Security Agreement 1 on December 3, 1986
and Assignment of Facility Form 8
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
67
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
99.8(c) Supplemental Indenture No. 2 4.4 to 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture, Mortgage, Report
Security Agreement and
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.9(c) Assignment, Assumption and 28.3 to Form S-3 33-9480 10-24-86
Further Agreement, dated as Registration Statement
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.10(c) Amendment No. 1, dated as of 10.10 to September 1986 1-4473 12-4-86
November 1, 1986, to Form 10-Q Report by
Assignment, Assumption and means of Amendment No.
Further Agreement, dated as 1 on December 3, 1986
of August 1, 1986, between Form 8
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.11(c) Amendment No. 2, dated as of 28.6 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
68
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 as of 28.20 to Form S-3 1-4473 8-10-87
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 Funding 8-K Report
Corp., Inc. as Funding
Corporation, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, Chemical
Bank, as Indenture Trustee,
the Company, and the Owner
Participant named therein
99.14 Amendment No. 2, dated as of 28.5 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS Funding
Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in its
individual capacity and as
Indenture Trustee, the
Company, and the Owner
Participant named therein
69
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
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 Lease, Report
dated as of December 15,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.17 Supplemental Indenture No. 2 4.5 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 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
70
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
99.19 Amendment No. 1, dated as of 28.7 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of December 15, 1986,
between the Company and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
99.20(c) Indemnity Agreement dated 28.3 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993 by the Report
Company
99.21 Extension Letter, dated as of 28.20 to Form S-3 1-4473 8-10-87
August 13, 1987, from the Registration Statement
signatories of the No. 33-9480 by means of a
Participation Agreement to November 6, 1986 Form
Chemical Bank 8-K Report
99.22 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 regarding
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
71
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
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, including
the Retail Electric Competition
Rules
- ----------
(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, 1999 and the period ended March 29,
2000, the Company filed the following Reports on Form 8-K:
Report dated November 2, 1999 comprised of Exhibits to our Registration
Statement (Registration No. 333-58445) relating to our offering of $250 million
of Notes.
72
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 29, 2000 William J. Post
------------------------------------------
(William J. Post, 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 29, 2000
- ---------------------------- Principal Accounting Officer
(William J. Post, and Director
Chief Executive Officer)
Michael V. Palmeri Principal Financial Officer March 29, 2000
- ----------------------------
(Michael V. Palmeri,
Vice President, Finance)
Jack E. Davis President and Director March 29, 2000
- ----------------------------
(Jack E. Davis)
Michael L. Gallagher Director March 29, 2000
- ----------------------------
(Michael L. Gallagher)
Martha O. Hesse Director March 29, 2000
- ----------------------------
(Martha O. Hesse)
Marianne M. Jennings Director March 29, 2000
- ----------------------------
(Marianne M. Jennings)
Robert E. Keever Director March 29, 2000
- ----------------------------
(Robert E. Keever)
Robert G. Matlock Director March 29, 2000
- ----------------------------
(Robert G. Matlock)
Kathryn L. Munro Director March 29, 2000
- ----------------------------
(Kathryn L. Munro)
73
Bruce J. Nordstrom Director March 29, 2000
- ----------------------------
(Bruce J. Nordstrom)
Donald M. Riley Director March 29, 2000
- ----------------------------
(Donald M. Riley)
Quentin P. Smith, Jr. Director March 29, 2000
- ----------------------------
(Quentin P. Smith, Jr.)
Richard Snell Director March 29, 2000
- ----------------------------
(Richard Snell)
William L. Stewart President and Director March 29, 2000
- ----------------------------
(William L. Stewart)
Dianne C. Walker Director March 29, 2000
- ----------------------------
(Dianne C. Walker)
Ben F. Williams, Jr. Director March 29, 2000
- ----------------------------
(Ben F. Williams, Jr.)
74
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, 1999
-----------------
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
27.1 -- Financial Data Schedule
For a description of the Exhibits incorported in this filing by reference, see
Part IV, Item 14.