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, 1998
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 86-0011170
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(Address of principal executive (602) 250-1000
offices, (Registrant's telephone number,
including zip code) including area code)
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Securities registered pursuant to
Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
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10% Junior Subordinated Deferrable Interest
Debentures, Series A, Due 2025............... New York Stock Exchange
Securities registered pursuant to Section 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 30, 1999, 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.................................................... 3
Item 2. Properties.................................................. 12
Item 3. Legal Proceedings........................................... 15
Item 4. Submission of Matters to a Vote of Security Holders......... 15
Supplemental Item.
Executive Officers of the Registrant........................ 16
PART II
Item 5. Market for Registrant's Common Stock and Related
Security Holder Matters..................................... 18
Item 6. Selected Financial Data..................................... 19
Item 7. Financial Review............................................ 20
Item 7A Quantitative and Qualitative Disclosures about
Market Risk................................................. 27
Item 8. Financial Statements and Supplementary Data................. 28
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure......................... 58
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 58
Item 11. Executive Compensation...................................... 58
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 58
Item 13. Certain Relationships and Related Transactions.............. 58
PART IV
Item 14. Exhibits, Financial Statements, Financial Statement
Schedules, and Reports on Form 8-K.......................... 59
SIGNATURES................................................................ 80
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GLOSSARY
ACC -- Arizona Corporation Commission
ACC STAFF -- Staff of the Arizona Corporation Commission
AFUDC -- Allowance for Funds Used During Construction
AMENDMENTS -- Clean Air Act Amendments of 1990
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
DOE -- United States Department of Energy
EITF -- Emerging Issues Task Force
EITF 97-4 -- Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity -- Issues Related to the Applications of FASB Statements
No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises -- Accounting for the Discontinuation of Application of
FASB Statement No. 71"
EITF 98-10 -- Emerging Issues Task Force Issue No. 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities"
ENERGY ACT -- National Energy Policy Act of 1992
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
MORTGAGE -- Mortgage and Deed of Trust, dated as of July 1, 1946, as
supplemented and amended
MW -- Megawatt, one million watts
MWH -- Megawatt hours, one million watts per hour
1935 ACT -- Public Utility Holding Company Act of 1935
NGS -- Navajo Generating Station
NRC -- Nuclear Regulatory Commission
PACIFICORP -- An Oregon-based utility company
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
SFAS NO. 34 -- Statement of Financial Accounting Standards No. 34,
"Capitalization of Interest Cost"
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SFAS NO. 71 -- Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
SFAS NO. 123 -- Statement of Financial Accounting Standards No. 123, "Accounting
for Stock-Based Compensation"
SFAS NO. 130 -- Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income"
SFAS NO. 133 -- Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities"
SALT RIVER PROJECT -- Salt River Project Agricultural Improvement and Power
District
USEC -- United States Enrichment Corporation
WASTE ACT -- Nuclear Waste Policy Act of 1982, as amended
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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 799,000 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
1998, no single purchaser or user of energy accounted for more than 2% of total
electric revenues. At December 31, 1998, we employed 6,075 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
GENERAL. Under current law, we are not in direct competition with any other
regulated electric utility for electric service in our retail service territory.
Nevertheless, 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.
ARIZONA ELECTRIC INDUSTRY RESTRUCTURING. See Note 3 of Notes to Financial
Statements in Item 8 for a discussion of the electric industry restructuring in
Arizona, including ACC rules for the introduction of retail electric
competition; stranded cost recovery; and Arizona legislative initiatives. See
also "Financial Review - Competition and Industry Restructuring" in Item 7.
WHOLESALE
GENERAL. 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
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vigorous. Our rates for wholesale power sales and transmission services are
subject to regulation by the FERC. During 1998, approximately 16% of our
electric operating revenues resulted from such sales and charges.
The National Energy Policy Act of 1992 (the "Energy Act") 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. These items, combined with miscellaneous
regulatory assets and liabilities, amounted to approximately $900 million at
December 31, 1998. Under a 1996 regulatory agreement, the ACC accelerated the
amortization of substantially all of our regulatory assets to an eight-year
period that will end June 30, 2004. Our existing regulatory orders and the
current regulatory environment support our accounting practices related to
regulatory assets. If rate recovery of these assets is no longer probable,
whether due to competition or regulatory action, we would be required to write
off the remaining balance as an extraordinary charge to expense. This could have
a material impact on our financial statements. 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) expanding our generation
asset base to support growth in the competitive power marketing arena; (vi)
strengthening our capital structure and financial condition; (vii) leveraging
core competencies into related areas, such as energy management products and
services; and (viii) establishing a trading floor and implementing a risk
management program to provide for more stability of prices and the ability to
retain or grow incremental margin 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.
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GENERATING FUEL AND PURCHASED POWER
1998 ENERGY MIX
Our sources of energy during 1998 were: coal - 36.2%; nuclear - 27.5%;
purchased power - 32.3%; and other - 4.0%.
COAL SUPPLY
We believe that Cholla has sufficient reserves of low sulfur coal committed
to the plant through 2005. In 1998, the current supplier agreed to allow Cholla
to test burn coal from other sources, which led to coal purchases on the spot
market. The current supplier is expected to continue to provide substantially
all of Cholla's low sulfur coal requirements. We believe there are sufficient
reserves of low sulfur coal available to allow the continued operation of Cholla
for its useful life. We also believe that Four Corners and NGS have sufficient
reserves of low sulfur coal available for use by those plants to continue
operating them for their useful lives.
The current sulfur content of coal being used at Four Corners, NGS, and
Cholla is approximately 0.77%, 0.54%, and 0.44%, respectively. In 1998, average
prices paid for coal supplied from the reserves dedicated under existing
contracts were slightly lower, but still comparable to 1997. Escalation
components of existing long-term coal contracts impact future coal prices. In
addition, major price adjustments can occur from time to time as a result of
contract renegotiation.
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 Navajo Nation" in Item 2.
We purchase all of the coal which fuels Four Corners from a coal supplier with a
long-term lease of coal reserves owned by the Navajo Nation and for NGS from a
coal supplier with a long-term lease with the Navajo Nation and the Hopi Tribe.
Coal is supplied to Cholla from a coal supplier who mines all of the coal under
a long-term lease of coal reserves owned by the Navajo Nation, the federal
government, and private landholders. See Note 12 of Notes to Financial
Statements in Item 8 for information regarding our obligation for coal mine
reclamation.
NATURAL GAS SUPPLY
We are a party to contracts with a number of natural gas operators and
marketers which 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 25 companies pursuant to 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,
+ 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 2001. Existing contracts and options could be
utilized to meet approximately 93% of requirements in 2002, 62% of requirements
in 2003, 51% of requirements
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in 2004, and 44% of requirements from 2005 through 2007. 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 85% of conversion services
required through 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 2003 for each Palo Verde unit, and through contract options,
approximately fifteen additional years are available.
SPENT NUCLEAR FUEL AND WASTE DISPOSAL. Pursuant to the Nuclear Waste Policy
Act of 1982, as amended in 1987 (the "Waste Act"), DOE is obligated to accept
and dispose of all spent nuclear fuel and other high-level radioactive wastes
generated by all 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. We have done so on our behalf and on behalf of the other
Palo Verde participants. 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 will 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. On July 24,
1998, we filed a Petition for Review regarding DOE's obligation to begin
accepting spent nuclear fuel. ARIZONA PUBLIC SERVICE COMPANY V. DEPARTMENT OF
ENERGY AND UNITED STATES OF AMERICA, No. 98-1346 (D.C. Cir.). 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. We also
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. One way or another, 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.
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.
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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 292 MW January through May 1998, and starting June
1998 increased to 316 MW. In 1998, we received approximately 943,354 MWh of
energy under the contract and paid about $43 million for capacity availability
and energy received. See Note 3 of Notes to Financial Statements for a
discussion of amendments to agreements with Salt River Project.
In September 1990, we entered into certain agreements with PacifiCorp
relating principally to sales and purchases of electric power and electric
utility assets. In July 1991 we sold Cholla 4 to PacifiCorp. As part of the
transaction, PacifiCorp agreed to make a firm system sale to us for thirty years
during our summer peak season. The amount of the sale for the first seven years
was 175 MW and it increases after that at our option, up to a maximum amount of
380 MW. We converted the firm system sales to one-for-one seasonal capacity
exchanges with PacifiCorp on October 31, 1997. On January 1, 1999 our agreements
with PacifiCorp provide for 275 MW capacity exchange and beginning in May 1999,
an additional 205 MW capacity exchange begins. In 1998, we had 275 MW of
generating capacity available from PacifiCorp. We received approximately 281,217
MWh of energy under the exchange.
During 1996, we entered into an agreement with Citizens Utilities Company
to build, own, operate, and maintain a combustion turbine in northwest Arizona.
CUC terminated the combustion turbine project in February 1999. We have notified
CUC that we will retain the rights to the combustion turbine project.
CONSTRUCTION PROGRAM
During the years 1996 through 1998, we incurred approximately $899 million
in capitalized expenditures. Utility capitalized expenditures for the years 1999
through 2001 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 1999 through
2001 have been estimated as follows:
(MILLIONS OF DOLLARS)
BY YEAR BY MAJOR FACILITIES
- ------------------------------ -----------------------------------------
1999 $328 Production $236
2000 317 Transmission and Distribution 564
2001 300 General 113
---- Other Projects 32
Total $945 ----
==== Total $945
====
The amounts for 1999 through 2001 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. We are
considering expanding certain of our operations over the next several years,
which may result in additional expenditures. We currently believe that there
will be opportunities to expand our investment in generating assets in the next
five years. It is expected that these generating assets would be organized in a
newly-created, non-regulated affiliate under Pinnacle West.
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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
1998, the replacement fund requirement amounted to approximately $138 million.
Certain of the bonds we have issued under the Mortgage that are callable prior
to maturity are redeemable at their par value plus accrued interest with cash we
deposit in the replacement fund. 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 1977 amendments 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. Approximately
93% of these capital costs have been incurred through 1998.
The Clean Air Act Amendments of 1990 (the "Amendments") address, 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 Amendments establish 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. On March 5, 1993,
the EPA promulgated rules listing allowance allocations applicable to our
plants. Based on those allocations, we will have sufficient allowances to permit
continued operation of our plants at current levels without installing
additional equipment.
In addition, the Amendments require 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 may require 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. We cannot currently predict how the EPA will respond. However,
based on our initial evaluation, we currently estimate our capital cost of
complying with the rules may be approximately $4 million.
With respect to protection of visibility in certain specified areas, the
Amendments require the EPA to conduct a study concerning visibility impairment
in those areas and to identify sources contributing to such impairment.
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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 Amendments also require 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. The Commission recommended that, beginning in 2000
and every 5 years thereafter, if actual sulfur dioxide emissions from all
stationary sources in an eight-state region (including Arizona, New Mexico,
Utah, Nevada, and California) exceed the projected emissions, which are
projected to decline under the current regulatory scheme, the projected total
emissions will be changed to a "regional emissions cap" and an emissions trading
program would be implemented to limit total sulfur dioxide emissions in the
region. The EPA will consider these recommendations before promulgating final
requirements on a regional haze regulatory program which the EPA proposed in
July 1997 and which is expected to be finalized by mid-1999.
Under EPA's proposed regional haze program, states would be required to
submit plans to meet "presumptive reasonable progress targets" for achieving
perceptible improvements in visibility conditions in Federal Class I areas
(e.g., national parks) every 10-15 years. The proposal also calls for states to
conduct three year "best available retrofit technology" ("BART") reviews on
point sources which became operational between 1962 and 1977 and which may
normally be anticipated to contribute to regional haze visibility impairment.
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. 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 Amendments require 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 in
the next several years concerning the necessity of regulating hazardous air
pollutant emissions from such units under the Amendments. 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 Amendments 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.
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
predecessor, 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, pursuant
to the Amendments. We are currently evaluating the impact of these regulations.
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.
10
<PAGE>
Both groundwater and surface water in areas important to our operations
have been the subject of inquiries, claims, and legal proceedings which will
require a number of years to resolve. We are one of a number of parties in a
proceeding before a state court in New Mexico to adjudicate rights to a stream
system from which water for Four Corners is derived. (STATE OF NEW MEXICO, IN
THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY
OF FARMINGTON, UTAH INTERNATIONAL, INC., ET AL., SAN JUAN COUNTY, NEW MEXICO,
District Court No. 75-184). An agreement reached with the Navajo Nation in 1985,
however, provides that if Four Corners loses a portion of its rights in the
adjudication, the Navajo Nation will provide, for a then-agreed upon cost,
sufficient water from 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. Issues important to
the claims are 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 or results of operations.
11
<PAGE>
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 peak one-hour demand on our electric system was recorded on July 16,
1998 at 5,072,000 kW, compared to the 1997 peak of 4,608,600 kW recorded on
August 22. Taking into account additional capacity then available to us under
purchase power contracts as well as our own generating capacity, our capability
of meeting system demand on July 16, 1998, computed in accordance with accepted
industry practices, amounted to 5,139,600 kW, for an installed reserve margin of
3.1%. 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 1998 peak amounted to
4,862,600 kW, for a margin of (3.9%). Firm purchases from neighboring utilities
totaling 1,467,000 kW were in place at the time of the peak ensuring the ability
to meet the load requirement, with an actual reserve margin of 7.4%.
PLANT SITES LEASED FROM NAVAJO NATION
NGS and Four Corners are located on land held under easements from the
federal government and also under leases from the Navajo Nation. We do not
believe that the risk with respect to enforcement of these easements and leases
is material. The lease for Four Corners waives until 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
to Four Corners, the Navajo Nation, and us which settled certain issues in the
Four Corners lease regarding the obligation of the fuel supplier to pay taxes
prior to the expiration of tax waivers in 2001. Pursuant to the agreement, in
1997 we recognized approximately $14 million of pretax earnings related to a
partial refund of
12
<PAGE>
possessory interest taxes paid by the fuel supplier. The parties also agreed to
renegotiate their business relationship before 2001 in an effort to permit the
electricity generated at Four Corners to be priced competitively. We cannot
currently predict the outcome of this matter. Certain of our transmission lines
and almost all of its contracted coal sources are also located on Indian
reservations. See "Generating Fuel and Purchased Power--Coal Supply" in Item 1.
PALO VERDE NUCLEAR GENERATING STATION
PALO VERDE LEASES
See Note 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.
Proposed ACC rules regarding the introduction of retail electric competition in
Arizona (see Note 3) 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 13 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.
13
<PAGE>
[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.
14
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
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. On February 28, 1997 and October 16, 1998, we filed
lawsuits to protect our legal rights regarding the rules and the amended rules,
respectively, and in each 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 97-03753 (consolidated under CV 97-03748.) ARIZONA
PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-18896. 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.
15
<PAGE>
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS
OF THE REGISTRANT
The Company's executive officers are as follows:
AGE AT
NAME MARCH 1, 1999 POSITION(S) AT MARCH 1, 1999
- ---- ------------- ----------------------------
Richard Snell 68 Chairman of the Board of Directors(1)
William J. Post 48 Chief Executive Officer(1)
Jack E. Davis 52 President, Energy Delivery and Sales(1)
William L. Stewart 55 President, Generation(1)
George A. Schreiber, Jr. 50 Executive Vice President and Chief Financial
Officer(1)
Armando B. Flores 55 Executive Vice President, Corporate Business
Services
James M. Levine 49 Senior Vice President, Nuclear Generation
Jan H. Bennett 51 Vice President, Distribution
John G. Bohon 53 Vice President, Corporate Services and Human
Resources
John R. Denman 56 Vice President, Fossil Generation
Edward Z. Fox 45 Vice President, Environmental/Health/Safety
and New Technology Ventures
William E. Ide 52 Vice President, Nuclear Engineering
Nancy C. Loftin 45 Vice President, Chief Legal Counsel and
Secretary
Gregg R. Overbeck 52 Vice President, Nuclear Production
Chris N. Froggatt 41 Controller
Michael V. Palmeri 40 Treasurer
- ----------
(1) Member of the Board of Directors.
Our executive officers are elected no less often than annually and may be
removed by the Board of Directors at any time. The terms served by the named
officers in their current positions and the principal occupations (in addition
to those stated in the table) of such officers for the past five years have been
as follows:
Mr. Snell was elected to his present position as of February 1990. He was
also elected Chairman of the Board, President and Chief Executive Officer of
Pinnacle West at that time. He retired as President in February 1997 and as
Chief Executive Officer in February 1999. Mr. Snell is also a director of
Pinnacle West, Aztar Corporation, and Central Newspapers, Inc.
Mr. Post was elected President and Chief Executive Officer in February
1997. In October 1998, he resigned as President and maintained the position of
Chief Executive Officer. Prior to that time he was Senior Vice President and
Chief Operating Officer (September 1994 - February 1997) and Senior Vice
President, Planning, Information and Financial Services (June 1993 - September
1994). Mr. Post was President of Pinnacle West (February 1997 - February 1999)
and in February 1999, he became Chief Executive Officer of Pinnacle West. Mr.
Post is also a director of Pinnacle West.
Mr. Davis was elected to his present position in October 1998. Prior to
that time he was Executive Vice President, Commercial Operations (September 1996
- - October 1998) and Vice President, Generation and Transmission (June
1993-September 1996).
16
<PAGE>
Mr. Stewart was elected to his present position in October 1998. Prior to
that time he was Executive Vice President, Generation (September 1996 - October
1998), Executive Vice President, Nuclear (May 1994 - September 1996) and Senior
Vice President--Nuclear for Virginia Power (since 1989).
Mr. Schreiber was elected to his present position in February 1997. Prior
to that time he was Managing Director at PaineWebber, Inc. (since February
1990). Mr. Schreiber was Executive Vice President of Pinnacle West (February
1997 - February 1999), and he is currently President (since February 1999) and
Chief Financial Officer (since February 1997) of Pinnacle West. Mr. Schreiber is
also a director of Pinnacle West.
Mr. Flores was elected to his present position in October 1998. Prior to
that time, he was Senior Vice President, Corporate Business Services (September
1996 - October 1998) and Vice President, Human Resources (1991-1996). Mr. Flores
is a director of Harris Trust Bank.
Mr. Levine was elected to his present position in September 1996. Prior to
that time he was Vice President, Nuclear Production (since September 1989).
Mr. Bennett was elected to his present position in May 1991.
Mr. Bohon was elected to his present position in October 1998. Prior to
that time he was Vice President, Procurement (April 1997 - October 1998) and
Director, Corporate Services (December 1989-April 1997).
Mr. Denman was elected to his present position in April 1997. Prior to that
time he was Director of Fossil Generation (since 1990).
Mr. Fox was elected to his present position in October 1995. Prior to that
time he was Director, Arizona Department of Environmental Quality and Chairman,
Wastewater Management Authority of Arizona (July 1991-September 1995).
Mr. Ide was elected to his present position in September 1996. Prior to
that time he was Director, Palo Verde Operations (1994-1996) and Palo Verde Unit
1 Plant Manager (1988-1994).
Ms. Loftin was elected to the positions of Vice President and Chief Legal
Counsel in September 1996 and has been Secretary since April 1987. Prior to that
time, in addition to Secretary, she was Corporate Counsel (since February 1989).
Mr. Overbeck was elected to his current position in July 1995. Prior to
that time he was Assistant to Vice President of the Company (January 1994-July
1995).
Mr. Froggatt was elected to his present position in July 1997. Prior to
that time he was Director, Accounting Services (since December 1992) of the
Company.
Mr. Palmeri was elected to his present position in July 1997. Prior to that
time he was Assistant Treasurer (February 1994-July 1997) and Manager of Finance
(June 1990-February 1994) of Pinnacle West. He also became Treasurer of Pinnacle
West in July 1997.
17
<PAGE>
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 1998 and 1997.
COMMON STOCK DIVIDENDS
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
QUARTER 1998 1997
- --------------------------------------------------------------------------------
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 Notes 4 and 5 of
Notes to Financial Statements in Item 8 for restrictions on retained earnings
available for the payment of common stock dividends.
18
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
Electric Operating Revenues ............. $2,006,398 $1,878,553 $1,718,272 $1,614,952 $1,626,168
Fuel and Purchased Power ................ 537,501 436,627 325,523 269,798 300,689
Operating Expenses ...................... 1,098,086 1,070,101 1,027,541 963,400 957,046
---------- ---------- ---------- ---------- ----------
Operating Income ..................... 370,811 371,825 365,208 381,754 368,433
Other Income ............................ 20,448 21,586 35,217 25,548 44,510
Interest Deductions -- Net .............. 136,012 141,918 156,954 167,732 169,457
---------- ---------- ---------- ---------- ----------
Net Income ........................... 255,247 251,493 243,471 239,570 243,486
Preferred Dividends .................. 9,703 12,803 17,092 19,134 25,274
---------- ---------- ---------- ---------- ----------
Earnings for Common Stock ............ $ 245,544 $ 238,690 $ 226,379 $ 220,436 $ 218,212
========== ========== ========== ========== ==========
Total Assets ............................ $6,393,299 $6,331,142 $6,423,222 $6,418,262 $6,348,261
========== ========== ========== ========== ==========
Capital Structure:
Common Stock Equity .................. $1,975,755 $1,849,324 $1,729,390 $1,621,555 $1,571,120
Non-Redeemable Preferred Stock ....... 85,840 142,051 165,673 193,561 193,561
Redeemable Preferred Stock ........... 9,401 29,110 53,000 75,000 75,000
Long-Term Debt Less Current
Maturities.......................... 1,876,540 1,953,162 2,029,482 2,132,021 2,181,832
---------- ---------- ---------- ---------- ----------
Total Capitalization ............... 3,947,536 3,973,647 3,977,545 4,022,137 4,021,513
Current Maturities of Long-Term Debt . 164,378 104,068 153,780 3,512 3,428
Commercial Paper ..................... 178,830 130,750 16,900 177,800 131,500
---------- ---------- ---------- ---------- ----------
Total .............................. $4,290,744 $4,208,465 $4,148,225 $4,203,449 $4,156,441
========== ========== ========== ========== ==========
</TABLE>
- ----------
See "Financial Review" in Item 7 for a discussion of certain information in
the foregoing table.
19
<PAGE>
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 1997 to 1998 and from 1996 to
1997
+ the factors impacting our business, including competition and
electric industry restructuring
+ the effects of regulatory agreements on our results
+ our capital needs and resources and
+ Year 2000 technology issues.
Throughout this Financial Review, we refer to specific "Notes" in the Notes to
Financial Statements that begin on page 35. These Notes add further details to
the discussion.
RESULTS OF OPERATIONS
1998 COMPARED WITH 1997 Our 1998 earnings increased $6.9 million - a 2.9%
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, two fuel-related settlements recorded in 1997, and two retail price
reductions. See Note 3 for additional information about the price reductions.
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 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).
Power marketing and trading activities are predominantly short-term opportunity
wholesale sales. The increase in power marketing revenues resulted from higher
prices, increased activity in Western bulk power markets, and increased sales to
large customers in California. The increase in power marketing and trading
revenues was accompanied by related increases in purchased power expenses.
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 $15 million 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.
20
<PAGE>
1997 COMPARED WITH 1996 Our 1997 earnings increased $12.3 million - a 5.4%
increase - over 1996 earnings primarily because of:
+ an increase in customers
+ a $32 million pretax charge in 1996 for a voluntary severance
program
+ two fuel-related settlements in 1997 and
+ lower financing costs.
These positive factors more than offset the effects of our 1996 regulatory
agreement with the Arizona Corporation Commission (ACC), which during 1997
resulted in about $60 million of additional regulatory asset amortization and a
$35 million revenue decrease caused by two retail price reductions. See Note 3
and "Results of Operations ___ Regulatory Agreements" below for additional
information. In addition, we recognized $12 million of income tax benefits in
1996 that were not repeated in 1997.
In 1997, electric operating revenues increased $160 million primarily because
of:
+ increased power marketing revenues ($128 million)
+ an increase in the number of customers ($58 million) and
+ weather effects ($7 million).
As mentioned above, these positive factors were partially offset by a $35
million revenue decrease caused by retail price reductions. The increase in
power marketing revenues resulted from increased activity in Western bulk power
markets. This did not significantly affect our earnings because the increase was
substantially offset by higher purchased power expenses.
Two fuel-related settlements in 1997 increased pretax earnings by about $21
million. The income statement shows these settlements as reductions in fuel
expense and as other income. About $16 million of the settlements related to
years prior to 1997 and $5 million related to 1997. We expect the total annual
savings from the settlements for at least the next several years to be about $10
million before income taxes. We do not have a fuel adjustment clause as part of
our retail rate structure. As a result, we show changes in fuel and purchased
power expenses in current earnings.
We lowered our operations and maintenance expenses in 1997 by putting in place a
voluntary severance program in late 1996, with related savings reflected in
1997. These savings were partially offset by increased expenses for marketing,
information technology, and power plant maintenance.
We decreased our financing costs by $12 million during 1997 by lowering the
amounts of outstanding debt and preferred stock.
REGULATORY AGREEMENTS Regulatory agreements with the ACC affect the results of
our operations. The following discussion focuses on two agreements: a 1996
agreement to accelerate the amortization of our regulatory assets and a 1994
settlement to accelerate amortization of our deferred investment tax credits
(ITCs).
Under the 1996 agreement with the ACC, we are recovering substantially all of
our present regulatory assets through accelerated amortization. The recovery of
these assets is taking place over an eight-year period that will end June 30,
2004. For more details, see Note 3. This accelerated amortization increased
annual amortization expense by about $120 million ($72 million after taxes).
Also, as part of the 1996 regulatory agreement, we reduced our retail prices by
3.4% effective July 1, 1996. This reduces revenue by about $48.5 million
annually ($29 million after taxes). We also agreed to share future cost savings
with our customers, which resulted in the following additional retail price
reductions:
21
<PAGE>
+ $17.6 million annually ($10.5 million after income taxes), or
1.2%, effective July 1, 1997, and
+ $17 million annually ($10 million after income taxes), or 1.1%,
effective July 1, 1998.
We expect to file with the ACC for another retail price decrease of
approximately $10.8 million annually ($6.5 million after income taxes) to become
effective July 1, 1999. The amount and timing of the price decrease are subject
to ACC approval. This will be the last price decrease under the 1996 regulatory
agreement.
We discuss above, in "Results of Operations," the factors that offset the
earnings impact of the accelerated regulatory asset amortization and the price
decreases.
As part of the 1994 rate settlement, we accelerated amortization of
substantially all deferred ITCs over a five-year period that ends on December
31, 1999. The amortization of ITCs is shown on our income statement as Other
Income ___ Income Taxes. It decreases annual income tax expense by about $28
million. Beginning in 2000, no further benefits will be reflected in income tax
expense. See Note 10.
CAPITAL NEEDS AND RESOURCES
Our capital requirements consist primarily of capital expenditures and optional
and mandatory redemptions of long-term debt and preferred stock. We pay for our
capital requirements with:
+ cash from our operations
+ annual cash payments from Pinnacle West of $50 million from 1996
through 1999 (see Note 3) and
+ to the extent necessary, external financing.
During the period from 1996 through 1998, we paid for all of our capital
expenditures with cash from our operations. We expect to do so in 1999 through
2001 as well.
Our capital expenditures in 1998 were $327 million. Our projected capital
expenditures for the next three years are: 1999, $328 million; 2000, $317
million; and 2001, $300 million. 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.
In addition, we are considering expanding certain of our operations over the
next several years, which may result in additional expenditures. We currently
believe that there will be opportunities to expand our investment in generating
assets in the next five years. It is expected that these generating assets would
be organized in a newly created non-regulated affiliate under Pinnacle West.
During 1998, we redeemed about $145 million of long-term debt and $76 million of
preferred stock, including premiums, with cash from operations and long- and
short-term debt. Our long-term debt and preferred stock redemption requirements
and payment obligations on a capitalized lease for the next three years are:
1999, $260 million; 2000, $115 million; and 2001, $2 million. On March 1, 1999,
we redeemed all $95 million of our outstanding preferred stock. Based on market
conditions and optional call provisions, we may make optional redemptions of
long-term debt from time to time.
22
<PAGE>
As of December 31, 1998, we had credit commitments from various banks totaling
about $400 million, which were available either to support the issuance of
commercial paper or to be used as bank borrowings. At the end of 1998, we had
about $179 million of commercial paper and $125 million of long-term bank
borrowings outstanding.
In 1998, we issued $100 million of unsecured long-term debt and in February
1999, we issued $125 million of unsecured long-term debt.
Although provisions in our first mortgage bond indenture, articles of
incorporation, 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
earn fair returns on their invested capital in exchange for commitments to serve
all customers within designated service territories. In December 1996, the ACC
adopted rules that provide a framework for the introduction of retail electric
competition in Arizona and adopted amendments to the rules in August 1998. On
January 11, 1999, the ACC issued an order which stayed the amended rules and
granted waivers from compliance with the rules to all affected utilities
(including us) pending further ACC decisions. On February 5, 1999, ACC hearing
officers issued recommendations for changes to the amended rules. These
recommended changes were further amended by an ACC Procedural Order dated March
12, 1999. See Note 3 for additional information about these rules and other
competitive developments, including an agreement with Salt River Project
Agricultural Improvement and Power District (Salt River Project). We cannot
currently predict when or if the amended rules will be further modified, when
the stay of the amended rules will be lifted, or when retail electric
competition will be introduced in Arizona with respect to affected utilities.
The rules as recommended indicate that the ACC will allow affected utilities the
opportunity to fully recover unmitigated stranded costs, but do not set forth
the mechanisms for determining and recovering such costs. On June 22, 1998, the
ACC issued an order on stranded cost determination and recovery and on February
5, 1999, an ACC hearing officer issued recommended changes to that order. These
recommended changes were further amended by an ACC Procedural Order dated March
12, 1999. See Note 3 for additional information on proposed modifications to the
stranded cost order.
An Arizona joint legislative committee studied electric utility restructuring
issues in 1996 and 1997. In May 1998, a law was enacted 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 believe that further ACC decisions, legislation at the Arizona and federal
levels, and perhaps amendments to the Arizona Constitution will ultimately be
required before significant implementation of retail electric competition can
lawfully occur in Arizona. Until it has been determined how competition will be
implemented in Arizona, including the manner in which stranded costs will be
addressed, 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. Our
existing regulatory orders and the current regulatory environment support our
accounting practices related to regulatory assets, which amounted to about $900
million at December 31, 1998. Under the 1996 regulatory agreement, the ACC
23
<PAGE>
accelerated the amortization of substantially all of our regulatory assets to an
eight-year period that will end June 30, 2004. If we cease to be cost-based
regulated, we would no longer be able to apply the provisions of SFAS No. 71 to
part or all of our operations, which could have a material impact on our
financial statements. See Note 1 for additional information on regulatory
accounting.
YEAR 2000 READINESS DISCLOSURE
OVERVIEW As the year 2000 approaches, many companies face problems because many
computer systems and equipment will not properly recognize calendar dates
beginning with the year 2000. We are addressing the Year 2000 issue as described
below. We initiated a comprehensive company-wide Year 2000 program during 1997
to review and resolve all Year 2000 issues in mission critical systems (systems
and equipment that are key to business function, health, and safety) in a timely
manner to ensure the reliability of electric service to our customers. This
included a company-wide awareness program of the Year 2000 issue.
The following chart shows Year 2000 readiness of our mission critical systems as
of January 31, 1999:
INVENTORY ASSESSMENT REMEDIATION & TESTING
100% 100% 70%*
* Estimated to be at 100% by June 30, 1999, except one Palo Verde unit as
discussed below.
DISCUSSION We have been actively implementing and replacing systems and
technology since 1995 for general business reasons unrelated to the Year 2000,
and these actions have resulted in substantially all of our major information
technology (IT) systems becoming Year 2000 ready. The major IT systems that
were, and are being, implemented and replaced include the following:
+ Work Management
+ Materials Management
+ Energy Management
+ Payroll
+ Financial
+ Human Resources
+ Trouble Call Management
+ Computer and Communications Network Upgrades
+ Geographic Information Management
+ Customer Information System and
+ Palo Verde Site Work Management.
We have made, and will continue to make, certain modifications to computer
hardware and software systems and applications, including IT and non-IT systems,
in an effort to ensure they are capable of handling changing business needs,
including dates in the year 2000 and thereafter. In addition, we are analyzing
other IT systems and non-IT systems, including embedded technology and real-time
process control systems, for potential modifications.
We have inventoried and assessed essentially all mission critical IT and non-IT
systems and equipment. We are 70% complete with the remediation and testing of
these systems. Remediation and testing is expected to be completed by June 30,
1999, for all mission critical systems, except for those items that can only be
completed during maintenance outages at Palo Verde, which will be completed for
the last unit, which is substantially identical to the other two units, during
the last half of 1999. We have an internal audit/quality review team that is
periodically reviewing the individual Year 2000 projects and their Year 2000
readiness.
24
<PAGE>
We currently estimate that we will spend about $5 million relating to Year 2000
issues, about $3 million of which has been spent to date. This includes an
estimated allocation of payroll costs for our employees working on Year 2000
issues, and costs for consultants, hardware, and software. We do not separately
track other internal costs. This does not include costs incurred since 1995 to
implement and replace systems for reasons unrelated to the Year 2000, as
discussed above. Our cost to address the Year 2000 issue is charged to operating
expenses as incurred and has not had, and is not expected to have, a material
adverse effect on our financial position, cash flows, or results of operations.
We expect to fund this cost with available cash balances and cash provided by
operations.
We are communicating with our significant suppliers, business partners, other
utilities, and large customers to determine the extent to which we may be
affected by these third parties' plans to remediate their own Year 2000 issues
in a timely manner. We have been interfacing with suppliers of systems,
services, and materials in order to assess whether their schedules for analysis
and remediation of Year 2000 issues are timely and to assess their ability to
continue to supply required services and materials.
We are also working with the North American Electric Reliability Council (NERC)
through the Western Systems Coordinating Council (WSCC) to develop operational
plans for stable grid operation that will be used by other utilities and us in
the western United States. These plans are expected to be completed by June 30,
1999. However, we cannot currently predict the effect on us if the systems of
these other companies are not Year 2000 ready.
We currently expect that our most reasonably likely worst case Year 2000
scenario would be intermittent loss of power to customers, similar to an outage
during a severe weather disturbance. In this situation, we would restore power
as soon as possible by, among other things, re-routing power flows. We do not
currently expect that this scenario would have a material adverse effect on our
financial position, cash flows, or results of operations.
We are working to develop our own contingency plans to handle Year 2000 issues,
including the most reasonably likely worst case scenario, discussed above, and
we expect these plans to be completed by June 30, 1999. As discussed above, we
have also been working with NERC and WSCC to develop contingency plans related
to grid operation.
ACCOUNTING MATTERS
We describe two new accounting rules in Note 2. First, the new rule on energy
trading and risk management is effective in 1999. We do not expect it to have a
material impact on our financial results. Secondly, the new standard on
derivatives is effective for us in 2000. We are currently evaluating what impact
it will have on our financial statements. Also, see Note 13 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 the nuclear decommissioning trust
fund. Our policy is to manage interest rates through the use of a combination of
fixed 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 rates.
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, 1998 and December 31, 1997. The weighted
average interest rates for the various debt presented are actual as of December
31, 1998 and December 31, 1997.
25
<PAGE>
EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1998
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
SHORT-TERM VARIABLE LONG-TERM FIXED LONG-TERM
------------------- ------------------- -------------------
INTEREST INTEREST INTEREST
RATES AMOUNT RATES AMOUNT RATES AMOUNT
------------------- ------------------- -------------------
<S> <C> <C> <C> <C> <C> <C>
1999 6.21% $ 178,830 -- $ -- 7.24% $ 164,378
2000 -- -- -- -- 5.79% 114,711
2001 -- -- -- -- 7.48% 2,488
2002 -- -- -- -- 8.13% 125,000
2003 -- -- 5.69% 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
========== ========== ==========
</TABLE>
EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1997
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
SHORT-TERM VARIABLE LONG-TERM FIXED LONG-TERM
------------------- ------------------- -------------------
INTEREST INTEREST INTEREST
RATES AMOUNT RATES AMOUNT RATES AMOUNT
------------------- ------------------- -------------------
<S> <C> <C> <C> <C> <C>
1998 6.27% $ 130,750 -- $ -- 7.62% $ 104,068
1999 -- -- -- -- 7.25% 164,378
2000 -- -- -- -- 5.83% 104,711
2001 -- -- -- -- 7.48% 2,488
2002 -- -- 6.25% 150,000 8.13% 125,000
Years thereafter -- -- 3.62% 439,990 7.92% 973,628
---------- ---------- ----------
Total $ 130,750 $ 589,990 $1,474,273
========== ========== ==========
Fair Value $ 130,750 $ 589,990 $1,504,417
========== ========== ==========
</TABLE>
COMMODITY PRICE RISK We utilize a variety of derivative instruments including
exchange-traded futures, options, and swaps as part of our overall risk
management strategies and for trading purposes. In order to reduce the risk of
adverse price fluctuations in the electricity and natural gas markets, we enter
into futures and/or option transactions to hedge certain natural gas held in
storage as well as certain expected purchases and sales of natural gas and
electricity. The changes in market value of such contracts have a high
correlation to the price changes in the hedged commodity. Gains and losses
related to derivatives that qualify as hedges of expected transactions are
recognized in income when the underlying hedged physical transaction closes
(deferral method). Gains and losses on derivatives utilized for trading are
recognized in income on a current basis (the mark to market method).
26
<PAGE>
We have prepared a sensitivity analysis to estimate our exposure to the market
risk of our derivative position for natural gas and electricity. With respect to
these derivatives, a potential adverse price movement of 10% in the market price
of natural gas and electricity from the December 31, 1998 levels would decrease
the fair value of these instruments by approximately $1 million. This analysis
does not include the favorable impact that the same hypothetical price movement
would have on expected physical purchases and sales of natural gas and
electricity.
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 the
financial viability of counterparties. We do not expect counterparty defaults to
materially impact our financial condition, results of operations, or net cash
flows.
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.
27
<PAGE>
ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Management...................................................... 29
Independent Auditors' Report.............................................. 30
Statements of Income for 1998, 1997, and 1996............................. 31
Balance Sheets as of December 31, 1998 and 1997........................... 32
Statements of Cash Flows for 1998, 1997, and 1996......................... 34
Statements of Retained Earnings for 1998, 1997, and 1996.................. 35
Notes to Financial Statements............................................. 35
See Note 14 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.
28
<PAGE>
REPORT OF MANAGEMENT
The primary responsibility for the integrity of the Company's 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. Materiality was given
due consideration. 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 the Company's system provides the appropriate balance between such costs
and benefits.
Periodically the internal accounting control system is reviewed by both the
Company's internal auditors and its 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 Review Committee of
the Board of Directors and the independent auditors on a timely basis.
The Audit Review 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 Review Committee, without management
present, to discuss the results of their audit work.
Management believes that the Company's 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 George A. Schreiber, Jr.
William J. Post George A. Schreiber, Jr.
Chief Executive Officer Executive Vice President
and Chief Financial Officer
29
<PAGE>
INDEPENDENT AUDITORS' REPORT
We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 1998 and 1997 and the related statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1998. 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, 1998 and 1997
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1998 in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
March 4, 1999
30
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
-------------------------------------
1998 1997 1996
---------- ---------- ----------
(THOUSANDS OF DOLLARS)
Electric Operating Revenues ............. $2,006,398 $1,878,553 $1,718,272
---------- ---------- ----------
Fuel Expenses:
Fuel for electric generation ......... 231,967 201,341 230,393
Purchased power ...................... 305,534 235,286 95,130
---------- ---------- ----------
Total .............................. 537,501 436,627 325,523
---------- ---------- ----------
Operating Revenues Less Fuel Expenses ... 1,468,897 1,441,926 1,392,749
---------- ---------- ----------
Other Operating Expenses:
Operations and maintenance excluding
fuel expenses ...................... 414,041 399,434 430,714
Depreciation and amortization (Note 1) 376,574 365,671 297,210
Income taxes (Note 10) ............... 192,207 184,737 178,513
Other taxes .......................... 115,264 120,259 121,104
---------- ---------- ----------
Total .............................. 1,098,086 1,070,101 1,027,541
---------- ---------- ----------
Operating Income ........................ 370,811 371,825 365,208
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used during
construction ....................... -- -- 5,209
Income taxes (Note 10) ............... 32,751 31,413 45,552
Other -- net ......................... (12,303) (9,827) (15,544)
---------- ---------- ----------
Total .............................. 20,448 21,586 35,217
---------- ---------- ----------
Income Before Interest Deductions ....... 391,259 393,411 400,425
---------- ---------- ----------
Interest Deductions:
Interest on long-term debt ........... 137,214 140,931 147,666
Interest on short-term borrowings .... 7,481 9,404 10,621
Debt discount, premium and expense ... 7,580 7,791 8,176
Capitalized interest ................. (16,263) (16,208) (9,509)
---------- ---------- ----------
Total .............................. 136,012 141,918 156,954
---------- ---------- ----------
Net Income .............................. 255,247 251,493 243,471
Preferred Stock Dividend Requirements ... 9,703 12,803 17,092
---------- ---------- ----------
Earnings for Common Stock ............... $ 245,544 $ 238,690 $ 226,379
========== ========== ==========
See Notes to Financial Statements.
31
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS
DECEMBER 31,
-------------------------
1998 1997
----------- -----------
(THOUSANDS OF DOLLARS)
Utility Plant (Notes 5, 8 and 9):
Electric plant in service and held for
future use...................................... $ 7,265,604 $ 7,009,059
Less accumulated depreciation and amortization .. 2,814,762 2,620,607
----------- -----------
Total ......................................... 4,450,842 4,388,452
Construction work in progress ................... 228,643 237,492
Nuclear fuel, net of amortization of $68,569
and $66,081 ................................... 51,078 51,624
----------- -----------
Utility Plant -- net .......................... 4,730,563 4,677,568
----------- -----------
Investments and Other Assets (Note 13) ............. 183,549 164,906
----------- -----------
Current Assets:
Cash and cash equivalents ....................... 5,558 12,552
Accounts receivable:
Service customers ............................. 205,999 141,022
Other ......................................... 23,213 31,313
Allowance for doubtful accounts ............... (1,725) (1,338)
Accrued utility revenues ........................ 67,740 58,559
Materials and supplies (at average cost) ........ 69,074 70,634
Fossil fuel (at average cost) ................... 13,978 9,621
Deferred income taxes (Note 10) ................. 3,999 3,496
Other ........................................... 26,695 24,529
----------- -----------
Total Current Assets .......................... 414,531 350,388
----------- -----------
Deferred Debits:
Regulatory asset for income taxes (Note 10) ..... 400,795 458,369
Rate synchronization cost deferral .............. 303,660 358,871
Unamortized costs of reacquired debt ............ 53,744 63,501
Unamortized debt issue costs .................... 14,916 15,303
Other ........................................... 291,541 242,236
----------- -----------
Total Deferred Debits ......................... 1,064,656 1,138,280
----------- -----------
Total ......................................... $ 6,393,299 $ 6,331,142
=========== ===========
See Notes to Financial Statements.
32
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES
DECEMBER 31,
-----------------------
1998 1997
---------- ----------
(THOUSANDS OF DOLLARS)
Capitalization (Notes 4 and 5):
Common stock ...................................... $ 178,162 $ 178,162
Additional paid--in capital ....................... 1,195,625 1,142,364
Retained earnings ................................. 601,968 528,798
---------- ----------
Common stock equity ............................. 1,975,755 1,849,324
Non-redeemable preferred stock .................... 85,840 142,051
Redeemable preferred stock ........................ 9,401 29,110
Long-term debt less current maturities ............ 1,876,540 1,953,162
---------- ----------
Total Capitalization ............................ 3,947,536 3,973,647
---------- ----------
Current Liabilities:
Commercial paper (Note 6) ......................... 178,830 130,750
Current maturities of long-term debt (Note 5) ..... 164,378 104,068
Accounts payable .................................. 145,139 107,423
Accrued taxes ..................................... 59,827 85,886
Accrued interest .................................. 31,218 31,660
Customer deposits ................................. 26,815 29,116
Other ............................................. 16,755 19,588
---------- ----------
Total Current Liabilities ....................... 622,962 508,491
---------- ----------
Deferred Credits and Other:
Deferred income taxes (Note 10) ................... 1,312,007 1,345,177
Deferred investment tax credit (Note 10) .......... 32,465 60,093
Unamortized gain--sale of utility plant (Note 9)... 77,787 82,363
Customer advances for construction ................ 31,451 29,294
Other ............................................. 369,091 332,077
---------- ----------
Total Deferred Credits and Other ................ 1,822,801 1,849,004
---------- ----------
Commitments and Contingencies (Note 12)
Total ............................................. $6,393,299 $6,331,142
========== ==========
33
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Cash Flows from Operations:
Net income .......................................... $ 255,247 $ 251,493 $ 243,471
Items not requiring cash:
Depreciation and amortization ..................... 376,574 365,671 297,210
Nuclear fuel amortization ......................... 32,856 32,702 33,566
Allowance for equity funds used during
construction..................................... -- -- (5,209)
Deferred income taxes -- net ...................... (26,374) (55,278) (12,717)
Deferred investment tax credit -- net ............. (27,628) (27,630) (27,630)
Changes in certain current assets and liabilities:
Accounts receivable -- net ........................ (56,490) (11,069) (33,044)
Accrued utility revenues .......................... (9,181) (3,089) (1,951)
Materials, supplies and fossil fuel ............... (2,797) 7,793 11,945
Other current assets .............................. (2,166) (1,762) (4,928)
Accounts payable .................................. 33,731 (56,710) 68,788
Accrued taxes ..................................... (26,059) (441) 3,500
Accrued interest .................................. (442) (7,455) (2,565)
Other current liabilities ......................... (4,654) (3,997) (522)
Other -- net ........................................ (29,641) 46,625 7,616
--------- --------- ---------
Net cash provided ................................. 512,976 536,853 577,530
--------- --------- ---------
Cash Flows from Investing:
Capital expenditures ................................ (319,142) (307,876) (258,598)
Capitalized interest ................................ (16,263) (16,208) (9,509)
Other ............................................... (8,593) (15,982) (102)
--------- --------- ---------
Net cash used ..................................... (343,998) (340,066) (268,209)
--------- --------- ---------
Cash Flows from Financing:
Long-term debt ...................................... 126,245 109,906 205,830
Short-term borrowings--net .......................... 48,080 113,850 (160,900)
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 ................... (10,279) (13,307) (17,416)
Repayment of preferred stock ........................ (75,517) (47,201) (50,360)
Repayment and reacquisition of long-term debt ....... (144,501) (240,004) (172,343)
--------- --------- ---------
Net cash used ..................................... (175,972) (196,756) (315,189)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents ... (6,994) 31 (5,868)
Cash and cash equivalents at beginning of year ......... 12,552 12,521 18,389
--------- --------- ---------
Cash and cash equivalents at end of year ............... $ 5,558 $ 12,552 $ 12,521
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest (excluding capitalized interest) ......... $ 128,627 $ 141,991 $ 150,603
Income taxes ...................................... $ 235,475 $ 236,676 $ 158,553
</TABLE>
See Notes to Financial Statements.
34
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF RETAINED EARNINGS
YEAR ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(THOUSANDS OF DOLLARS)
Retained earnings at beginning of year .......... $528,798 $460,106 $403,843
Add: Net income ................................ 255,247 251,493 243,471
-------- -------- --------
Total ........................................ 784,045 711,599 647,314
-------- -------- --------
Deduct:
Dividends:
Common stock (Notes 4 and 5) ................. 170,000 170,000 170,000
Preferred stock (at required rates) (Note 4).. 9,703 12,801 17,092
Other .......................................... 2,374 -- 116
-------- -------- --------
Total deductions ............................. 182,077 182,801 187,208
-------- -------- --------
Retained earnings at end of year ................ $601,968 $528,798 $460,106
======== ======== ========
See Notes to Financial Statements.
APS
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS We are Arizona's largest electric utility, with 799,000
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.
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 Arizona Corporation Commission
(ACC) and the Federal Energy Regulatory Commission (FERC). The accompanying
financial statements reflect the rate-making policies of these commissions. 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.
Our major regulatory assets are deferred income taxes (see Note 10) and rate
synchronization cost deferrals (see "Rate Synchronization Cost Deferrals" in
this Note). These items, combined with miscellaneous regulatory assets and
liabilities, amounted to approximately $900 million at December 31, 1998 and
$1.0 billion at December 31, 1997. Most of these items are included in "Deferred
Debits" on the Balance Sheets. 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 will end June 30, 2004. We record the
accelerated portion of the regulatory asset amortization, approximately $120
million pretax in 1998 and 1997 and $60 million pretax in 1996, in depreciation
and amortization expense on the Statements of Income.
35
<PAGE>
APS
NOTES TO 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.
Although rules have been proposed for transitioning generation services to
competition, there are many unresolved issues. We continue to apply SFAS No. 71
to our generation operations. If rate recovery of regulatory assets is no longer
probable, whether due to competition or regulatory action, we would be required
to write off the remaining balance as an extraordinary charge to expense.
COMMON STOCK All of the outstanding shares of our common stock are owned by
Pinnacle West. See Note 4.
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 13 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 1996 through 1998 the rates, as prescribed by our regulators, ranged from
a low of 1.51% to a high of 20%. The weighted-average rate for 1998 was 3.32%.
We depreciate non-utility property and equipment over the estimated useful lives
of the related assets, ranging from 3 to 50 years.
CAPITALIZED INTEREST In 1997 we began capitalizing interest in accordance with
SFAS No. 34, "Capitalization of Interest Cost." Capitalized interest represents
the cost of debt funds used to finance construction of utility plant. Plant
construction costs, including capitalized interest, are recovered in authorized
rates 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 for 1998 was 6.88% and for 1997 was
7.25%.
Prior to 1997 we accrued an allowance for funds used during construction
(AFUDC). AFUDC represented the cost of debt and equity funds used to finance
construction of utility plant. AFUDC did not represent current cash earnings.
AFUDC has been calculated using a composite rate of 7.75% for 1996.
REVENUES We record electric operating revenues on the accrual basis, which
includes estimated amounts for service rendered but unbilled at the end of each
accounting period.
RATE SYNCHRONIZATION COST DEFERRALS As authorized by the ACC, operating costs
(excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred
from the commercial operation dates (September 1986 for Unit 2 and January 1988
for Unit 3) until the date the units were included in a rate order (April 1988
for Unit 2 and December 1991 for Unit 3). Beginning July 1, 1996, the deferrals
are being amortized over an eight-year period in
36
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
accordance with the 1996 regulatory agreement (see Note 3). Prior to July 1,
1996, the deferrals were amortized over thirty-five year periods. 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 the number of thermal units that we produce within
the current period. This provides us with 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. In addition, Note 13 has information on nuclear decommissioning costs.
REACQUIRED DEBT COSTS When we incur gains or losses on debt that we retire prior
to maturity, we amortize those gains and losses over the remaining original life
of the debt. In accordance with the 1996 regulatory agreement (see Note 3), the
ACC accelerated our amortization of the regulatory asset for reacquired debt
costs to 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 debt instruments that will mature in three months
or less.
RECLASSIFICATIONS We have reclassified certain prior year amounts for comparison
purposes with 1998.
2. ACCOUNTING MATTERS
In 1998 we adopted SFAS No. 130, "Reporting Comprehensive Income." This standard
changes the reporting of certain items previously reported in the common stock
equity section of the balance sheet. The effects of adopting SFAS No. 130 were
not material to our financial statements.
In November 1998, the Financial Accounting Standards Board's Emerging Issues
Task Force issued EITF 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," which is effective for us in 1999. 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. We have evaluated the impact
of this rule and believe the effects are not material to our financial
statements.
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 2000. 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.
37
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE In December 1996, the ACC adopted rules that provide a framework for the
introduction of retail electric competition in Arizona. The rules, as amended,
became effective on August 10, 1998, and on December 10, 1998, the ACC adopted
the amended rules without any modifications that would have a significant impact
on us. We believe that certain provisions of the 1996 ACC rules and the amended
rules are deficient and we have filed lawsuits to protect our legal rights
regarding the 1996 rules and the amended rules. These lawsuits are pending but
two related cases filed by other utilities have been partially decided in a
manner adverse to those utilities' positions.
On January 11, 1999, the ACC issued an order which stayed the amended rules,
granted reconsideration of the decision to make the rules permanent, and
directed the hearing division of the ACC to establish a procedural order for
further action on these rules. The order also granted waivers from compliance
with the rules for us, and all affected utilities.
On February 5, 1999, the ACC Hearing Division issued recommendations for changes
to the amended rules. The recommended changes to the amended rules were further
modified by a Procedural Order of the ACC Hearing Division dated March 12, 1999.
The recommended rules include the following major provisions:
+ They would apply to virtually all Arizona electric utilities
regulated by the ACC, including APS.
+ Each utility must make at least 20% of its 1995 retail peak
demand available for competitive generation supply.
+ The rules become effective when the ACC makes a final decision on
each utility's stranded costs and unbundled rates (Final Decision
Date) or January 1, 2001, whichever comes first.
+ 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.
Customers with single premise loads of 40 kilowatts or greater
may aggregate loads to meet this one megawatt requirement.
+ When effective, residential customers will be phased in at 1 1/4%
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 with separate pricing
for electric services provided for noncompetitive services.
+ ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs (see "Stranded Costs" below).
38
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
+ Absent an ACC waiver, prior to January 1, 2001, each affected
utility must transfer all competitive generation assets and
services either to an unaffiliated party or to a separate
corporate affiliate.
+ Affiliate transaction rules prohibit a utility and its
competitive electric affiliates from sharing certain assets,
employees, and information.
If approved by the ACC, the rules would be subject to the formal rulemaking
process under Arizona statute. In compliance with statutory procedural
requirements, ACC oral proceedings on the matter would be scheduled no sooner
than 30 days after the proposed rules are published by the Secretary of State.
We cannot currently predict when or if the amended rules will be further
modified, when the stay of the amended rules will be lifted, or when retail
electric competition will be introduced in Arizona.
STRANDED COSTS On June 22, 1998, the ACC issued an Order on stranded
cost determination and recovery. We believe that certain provisions of the
stranded cost order are deficient and in August 1998, we filed two lawsuits to
protect our legal rights relating to the order.
On February 5, 1999, the ACC Hearing Division issued recommended changes to the
June 1998 stranded cost order. These recommended changes were further amended by
an ACC Procedural Order dated March 12, 1999. The recommended changes to the
stranded cost order would be effective upon approval of the ACC. The recommended
order, as amended on March 12, 1999, allows each affected utility to choose from
five options for the recovery of stranded costs:
+ Net Revenues Lost Methodology is the difference between
generation revenues under traditional regulation and generation
revenues under competition. This option provides for declining
recovery percentages for stranded costs over a five-year recovery
period. Regulatory assets are to be fully recovered under their
presently authorized amortization schedule. In accordance with a
1996 regulatory agreement, the ACC accelerated the amortization
of substantially all of our regulatory assets to an eight-year
period that ends June 30, 2004.
+ Divestiture/Auction Methodology allows a utility to divest all or
substantially all of its generating assets, including regulatory
assets associated with generation, in order to collect 100
percent of the difference between net sales price and book value
of generating assets divested over a ten-year period, with no
return on the unamortized balance.
+ Financial Integrity Methodology allows a utility "sufficient
revenues to meet minimum financial ratios" for a period of ten
years.
+ Settlement Methodology allows a settlement to be agreed upon by
the ACC and a utility.
+ Any combination of the above if shown to be in the best interests
of all affected parties.
LEGISLATIVE INITIATIVES An Arizona joint legislative committee studied
electric utility industry restructuring issues in 1996 and 1997. In conjunction
with that study, the Arizona legislative counsel prepared memoranda in late 1997
related to the legal authority of the ACC to deregulate the Arizona electric
utility industry. The memoranda raise a question as to the degree to which the
ACC may, under the Arizona Constitution, deregulate any portion of the electric
utility industry and allow rates to be determined by market forces. This latter
39
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
issue has been subsequently decided by lower courts in favor of the ACC in four
separate lawsuits, two of which are unrelated.
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 legislature on certain competitive issues.
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 Agreement contains
the following major components:
+ Both parties would amend the Territorial Agreement to remove any
barriers to the provision of competitive electricity supply and
non-distribution services.
+ Both parties would amend the Power Coordination Agreement to
lower the price that we will pay Salt River Project for purchased
power by approximately $17 million (pretax) during the first full
year that the Agreement is effective and by lesser annual amounts
during the next seven years.
+ Both parties agreed on certain legislative positions regarding
electric utility restructuring at the state and federal level.
Certain provisions of the Agreement (including those relating to the amendments
of the Territorial Agreement and the Power Coordination Agreement) are affected
by the timing of the introduction of competition. See "ACC Rules" above. On
February 18, 1999, the ACC approved the Agreement.
GENERAL We believe that further ACC decisions, legislation at the
Arizona and federal levels, and perhaps amendments to the Arizona Constitution
(which would require a vote of the people) will ultimately be required before
significant implementation of retail electric competition can lawfully occur in
Arizona. Until the manner of implementation of competition, including addressing
stranded costs, is determined, we cannot accurately predict the impact of full
retail competition on our financial position, cash flows, or results of
operation.
40
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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.
Several electric utility reform bills have been introduced during recent
congressional sessions, which as currently written would allow consumers to
choose their electricity suppliers by 2000 or 2003. 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
substantial restructuring of the electric utility industry can occur.
1996 REGULATORY AGREEMENT
In April 1996, the ACC approved a regulatory agreement between the ACC Staff and
us. The major provisions of this agreement are:
+ An annual rate reduction of approximately $48.5 million ($29
million after income taxes), or 3.4% on average for all customers
except certain contract customers, effective July 1, 1996.
+ Recovery of substantially all of our present regulatory assets
through accelerated amortization over an eight-year period that
will end June 30, 2004, increasing annual amortization by
approximately $120 million ($72 million after income taxes). See
Note 1.
+ A formula for sharing future cost savings between customers and
shareholders (price reduction formula), referencing a return on
equity (as defined) of 11.25%.
+ A moratorium on filing for permanent rate changes prior to July
2, 1999, except under the price reduction formula and under
certain other limited circumstances.
+ Infusion of $200 million of common equity into us by Pinnacle
West, in annual payments of $50 million starting in 1996.
Based on the price reduction formula, the ACC approved retail price decreases of
approximately $17.6 million ($10.5 million after income taxes), or 1.2%,
effective July 1, 1997, and approximately $17 million ($10 million after income
taxes), or 1.1%, effective July 1, 1998. We expect to file with the ACC for
another retail price decrease of approximately $10.8 million annually ($6.5
million after income taxes) to become effective July 1, 1999. The amount and
timing of the price decrease are subject to ACC approval. This will be the last
price decrease under the 1996 regulatory agreement.
41
<PAGE>
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, 1998 and 1997 are shown below:
<TABLE>
<CAPTION>
NUMBER
OF SHARES PAR PAR VALUE CALL
OUTSTANDING VALUE OUTSTANDING PRICE
----------------------- PER --------------------- PER
AUTHORIZED 1998 1997 SHARE 1998 1997 SHARE(A)
---------- ---------- ---------- -------- --------- --------- ---------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C> <C>
Common Stock .......... 100,000,000 71,264,947 71,264,947 $ 2.50 $ 178,162 $ 178,162 --
========== ========== ========= =========
Preferred Stock:
Non-Redeemable:
$1.10 ................ 160,000 139,030 145,559 $ 25.00 $ 3,476 $ 3,639 $ 27.50
$2.50 ................ 105,000 86,440 97,252 50.00 4,322 4,863 51.00
$2.36 ................ 120,000 32,520 38,506 50.00 1,626 1,925 51.00
$4.35 ................ 150,000 62,986 68,386 100.00 6,299 6,839 102.00
Serial preferred ..... 1,000,000
$2.40 Series A ..... 200,587 234,839 50.00 10,029 11,742 50.50
$2.625 Series C .... 214,895 231,572 50.00 10,745 11,579 51.00
$2.275 Series D .... 90,691 164,101 50.00 4,534 8,205 50.50
$3.25 Series E ..... 304,475 312,991 50.00 15,224 15,649 51.00
Serial preferred ..... 4,000,000(b)
Adjustable rate --
Series Q ......... 295,851 352,851 100.00 29,585 35,285 (c)
Serial preferred ..... 10,000,000
$1.8125 Series W ... -- 1,693,016 25.00 -- 42,325
---------- ---------- --------- ---------
Total ............ 1,427,475 3,339,073 $ 85,840 $ 142,051
========== ========== ========= =========
Redeemable:
Serial preferred:
$10.00 Series U .... 94,011 291,098 $ 100.00 $ 9,401 $ 29,110
========== ========== ========= =========
</TABLE>
- ----------
(a) The actual call price per share is the indicated amount plus any accrued
dividends.
(b) This authorization also covers all outstanding redeemable preferred stock.
(c) Dividend rate adjusted quarterly to 2% below that of certain United States
Treasury securities, but in no event less than 6% or greater than 12% per
annum. Redeemable at par.
42
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
We cannot pay common stock dividends or acquire shares of common stock if
preferred stock dividends or sinking fund requirements are in arrears.
Redeemable preferred stock transactions during each of the three years in the
period ended December 31, 1998 are as follows:
<TABLE>
<CAPTION>
NUMBER OF SHARES PAR VALUE
OUTSTANDING OUTSTANDING
----------------------------- ------------------------------
(THOUSANDS OF DOLLARS)
DESCRIPTION 1998 1997 1996 1998 1997 1996
- -------------------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, January 1...... 291,098 530,000 750,000 $ 29,110 $ 53,000 $ 75,000
Retirements:
$10.00 Series U...... (197,087) (118,902) (90,000) (19,709) (11,890) (9,000)
$7.875 Series V...... -- (120,000) (130,000) -- (12,000) (13,000)
-------- -------- -------- -------- -------- --------
Balance, December 31.... 94,011 291,098 530,000 $ 9,401 $ 29,110 $ 53,000
======== ======== ======== ======== ======== ========
</TABLE>
43
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
5. LONG-TERM DEBT
The following table presents long-term debt outstanding:
DECEMBER 31
MATURITY INTEREST -----------------------
DATES (a) RATES 1998 1997
--------- ----- ---- ----
(THOUSANDS OF DOLLARS)
First mortgage bonds 1998 7.625% $ -- $100,000
1999 7.625% 100,000 100,000
2000 5.75% 100,000 100,000
2002 8.125% 125,000 125,000
2004 6.625% 85,000 85,000
2020 10.25% 100,550 109,550
2021 9.5% 45,140 45,140
2021 9% 72,370 72,370
2023 7.25% 91,900 97,150
2024 8.75% 121,668 121,918
2025 8% 88,300 88,500
2028 5.5% 25,000 25,000
2028 5.875% 154,000 154,000
Unamortized discount
and premium (6,482) (7,033)
Pollution control bonds 2024-2033 Adjustable 456,860 439,990
rate (b)
Collateralized loan 1999-2000 5.375% - 20,000 10,000
6.125%
Unsecured note 2005 6.25% 100,000 --
Senior notes(c) 1999 6.72% 50,000 50,000
Senior notes(c) 2006 6.75% 100,000 100,000
Debentures 2025 10% 75,000 75,000
Bank loans 2003 Adjustable 125,000 150,000
rate (d)
Capitalized lease
obligation 1998-2001 7.48% (e) 11,612 15,645
---------- ----------
Total long-term debt 2,040,918 2,057,230
Less current maturities 164,378 104,068
---------- ----------
Total long-term debt less current maturities $1,876,540 $1,953,162
========== ==========
- ----------
(a) This schedule does not reflect the timing of redemptions that may occur
prior to maturity.
(b) The weighted-average rate for the years ended December 31, 1998 was 3.39%
and for December 31, 1997 was 3.62%. Changes in short-term interest rates
would affect the costs associated with this debt.
44
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
(c) We issued $150 million of first mortgage bonds ("senior note mortgage
bonds") 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.
(d) The weighted-average rate at December 31, 1998 was 5.69% and at December
31, 1997 was 6.25%. Changes in short-term interest rates would affect the
costs associated with this debt.
(e) 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:
+ $164.4 million in 1999
+ $114.7 million in 2000
+ $2.5 million in 2001
+ $125 million in 2002 and
+ $125 million in 2003.
First mortgage bondholders have 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, 1998.
6. LINES OF CREDIT
We had committed lines of credit with various banks of $400 million at December
31, 1998 and 1997, which were available either to support the issuance of
commercial paper or to be used for bank borrowings. The commitment fees at
December 31, 1998 and 1997 for these lines of credit ranged from .07% to .15%
per annum. We had long-term bank borrowings of $125 million outstanding at
December 31, 1998, and $150 million outstanding at December 31, 1997.
Our commercial paper borrowings outstanding were $178.8 million at December 31,
1998, and $130.8 million at December 31, 1997. The weighted average interest
rate on commercial paper borrowings was 6.21% on December 31, 1998 and 6.27% on
December 31, 1997. 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, 1998 and
1997 due to their short maturities. We hold investments in debt and equity
securities for purposes other than trading. The December 31, 1998 and 1997 fair
values of these 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.
45
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The carrying value of our long-term debt (excluding a capitalized lease
obligation) was $2.03 billion on December 31, 1998, with an estimated fair value
of $2.11 billion. On December 31, 1997, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.04 billion, with an estimated
fair value of $2.08 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.
8. JOINTLY-OWNED FACILITIES
We share ownership of some of our generating and transmission facilities with
other companies. The following table shows our interest in those jointly-owned
facilities at December 31, 1998. 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% $1,821,620 $670,403 $20,152
Palo Verde Nuclear Generating
Station Unit 2 (see Note 9) 17.0% 568,184 224,502 9,839
Four Corners Steam Generating
Station Units 4 and 5 15.0% 150,165 69,764 312
Navajo Steam Generating Station
Units 1, 2, and 3 14.0% 203,356 90,237 25,560(a)
Cholla Steam Generating Station
Common Facilities (b) 62.8%(c) 67,513 37,096 267
Transmission Facilities:
ANPP 500KV System 35.8%(c) 66,547 20,282 1,384
Navajo Southern System 31.4%(c) 26,918 17,285 21
Palo Verde-Yuma 500KV System 23.9%(c) 11,376 4,215 -
Four Corners Switchyards 27.5%(c) 3,071 1,780 143
Phoenix-Mead System 17.1%(c) 36,324 536 -
- ----------
(a) The construction costs at Navajo are primarily related to the installation
of scrubbers required by environmental legislation.
(b) Pacificorp owns Cholla Unit 4 and we operate the unit for them. The common
facilities at the Cholla Plant are jointly-owned.
(c) Weighted average of interests.
46
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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 $140.2 million was
deferred and is being amortized to operations expense over 29.5 years, the
original term of the leases. There are options to renew the leases for two
additional years and to purchase the property for fair market value at the end
of the lease terms. Consistent with the ratemaking treatment, an amount equal to
the annual lease payments is included in rent expense. A regulatory asset is
recognized for the difference between lease payments and rent expense calculated
on a straight-line basis.
The average amounts to be paid for the Palo Verde Unit 2 leases are as follows:
YEAR (IN MILLIONS)
- ----
1999 $40.1
2000 46.3
2001-2015 49.0
In accordance with the 1996 regulatory agreement (see Note 3), the ACC
accelerated our amortization of the regulatory asset for leases to 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, 1998 was $48.5 million. Lease expense
was approximately $42 million in each of the years 1996 through 1998.
We have a capital lease on a combined cycle plant, which we sold and leased
back. The lease requires semiannual payments of $2.6 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 $54.4 million;
accumulated amortization at December 31, 1998 was $48.6 million.
In addition, we lease certain land, buildings, equipment, and miscellaneous
other items through operating rental agreements with varying terms, provisions,
and expiration dates.
Approximate miscellaneous lease expense was:
+ $9.6 million in 1998
+ $7.8 million in 1997 and
+ $9.7 million in 1996.
47
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
Estimated future minimum lease commitments, excluding the Palo Verde and
combined cycle leases, are as follows:
YEAR (IN MILLIONS)
- ----
1999 $ 13
2000 13
2001 14
2002 14
2003 13
Thereafter 91
-------
Total future commitments $ 158
=======
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 are
amortizing almost all of our investment tax credits (ITCs) over 5 years
(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 on our Balance Sheet in accordance with SFAS
No. 71. This regulatory asset is for certain temporary differences, primarily
AFUDC equity. We amortize this amount as the differences reverse. We have been
able to accelerate the amortization of the regulatory asset for income taxes to
an eight-year period that will end June 30, 2004. This is a result of a 1996
regulatory agreement with the ACC. We are including this accelerated
amortization in depreciation and amortization expense on the Statements of
Income.
The components of income tax expense are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
--------- --------- ---------
(THOUSANDS OF DOLLARS)
Current:
Federal .............................. $ 170,806 $ 187,701 $ 137,531
State ................................ 42,652 48,531 35,777
--------- --------- ---------
Total current ...................... 213,458 236,232 173,308
Deferred ................................ (26,374) (55,278) (869)
Change in valuation allowance ........... -- -- (11,848)
Investment tax credit amortization ...... (27,628) (27,630) (27,630)
--------- --------- ---------
Total expense ...................... $ 159,456 $ 153,324 $ 132,961
========= ========= =========
48
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
Multiplying income before income taxes by the statutory federal income tax rate
does not equal the amount recorded as income tax expense because of the
following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1998 1997 1996
-------- -------- --------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Federal income tax expense at 35% statutory rate ....... $145,146 $141,686 $131,751
Increases (reductions) in tax expense resulting from:
Tax under book depreciation ......................... 17,848 14,694 19,229
Investment tax credit amortization .................. (27,628) (27,630) (27,630)
State income tax -- net of federal income tax benefit 23,024 23,160 20,790
Change in valuation allowance ....................... -- -- (10,269)
Other ............................................... 1,066 1,414 (910)
-------- -------- --------
Income tax expense ................................ $159,456 $153,324 $132,961
======== ======== ========
</TABLE>
The components of the net deferred income tax liability were as follows:
DECEMBER 31,
-----------------------
1998 1997
---------- ----------
(THOUSANDS OF DOLLARS)
Deferred tax assets:
Deferred gain on Palo Verde Unit 2 sale/leaseback $ 31,285 $ 33,257
Other ........................................... 74,292 77,412
---------- ----------
Total deferred tax assets ..................... 105,577 110,669
---------- ----------
Deferred tax liabilities:
Plant related ................................... 1,112,897 1,096,222
Regulatory asset for income taxes ............... 161,836 185,084
Rate synchronization deferrals .................. 122,130 144,908
Other ........................................... 16,722 26,136
---------- ----------
Total deferred tax liabilities ................ 1,413,585 1,452,350
---------- ----------
Deferred income taxes -- net ....................... $1,308,008 $1,341,681
========== ==========
11. RETIREMENT PLANS AND OTHER BENEFITS
VOLUNTARY SEVERANCE PLAN We sponsored a voluntary severance plan in 1996. There
was a pretax charge of $31.7 million in 1996 recorded mostly as operations and
maintenance expense. This pretax charge included additional pension and
postretirement benefit expense. Employees who participated in the plan were
credited with an additional year of age and service when their pension and
postretirement benefits were calculated. The additional expenses recorded in
1996 for this plan were $2.3 million for pension and $5.4 million for
postretirement benefits.
PENSION PLAN We sponsor a defined benefit pension plan for our employees. 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 APS
employees. Our employees do not contribute to this plan. Generally, we calculate
the benefits under this
49
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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, 1998 were mostly domestic and international common stocks and bonds
and real estate. Pension expense, including administrative and severance costs,
was:
+ $9.8 million in 1998
+ $8.7 million in 1997 and
+ $14.9 million in 1996.
The following table shows the components of net pension cost before
consideration of amounts capitalized or billed to others and excluding severance
costs of $2.9 million in 1996:
1998 1997 1996
-------- -------- --------
(THOUSANDS OF DOLLARS)
Service cost -- benefits earned during
the period................................ $ 24,126 $ 19,881 $ 22,861
Interest cost on projected benefit
obligation ............................... 50,863 47,824 44,602
Expected return on plan assets ............. (53,883) (47,422) (41,958)
Amortization of:
Transition asset ...................... (3,216) (3,216) (3,216)
Prior service cost .................... 2,063 2,063 1,727
Net actuarial losses .................. -- -- 721
-------- -------- --------
Net periodic pension cost .................. $ 19,953 $ 19,130 $ 24,737
======== ======== ========
The following table shows a reconciliation of the funded status of the plan to
the amounts recognized in the balance sheets:
1998 1997
-------- --------
(THOUSANDS OF DOLLARS)
Funded status -- Pension plan assets less than
projected benefit obligation .................... $(38,957) $(87,208)
Unrecognized net transition asset ................. (23,159) (26,376)
Unrecognized prior service cost ................... 22,562 24,625
Unrecognized net actuarial losses/(gains) ......... (38,916) 16,989
-------- --------
Net pension amount recognized in the balance
sheets........................................... $(78,470) $(71,970)
======== ========
50
<PAGE>
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 1998 and 1997:
1998 1997
--------- ---------
(THOUSANDS OF DOLLARS)
Projected pension benefit obligation
at beginning of year ............................ $ 699,600 $ 601,094
Service cost ...................................... 24,126 19,881
Interest cost ..................................... 50,863 47,824
Benefit payments .................................. (29,384) (29,741)
Plan amendments ................................... -- 5,537
Actuarial losses/(gains) .......................... (23,976) 55,005
--------- ---------
Projected pension benefit obligation
at end of year................................... $ 721,229 $ 699,600
========= =========
The following table sets forth the defined benefit pension plan's change in the
fair value of plan assets for the plan years 1998 and 1997:
1998 1997
--------- ---------
(THOUSANDS OF DOLLARS)
Fair value of pension plan assets
at beginning of year ............................ $ 612,392 $ 533,444
Actual return on plan assets ...................... 85,764 87,583
Employer contributions ............................ 13,500 21,106
Benefit payments .................................. (29,384) (29,741)
--------- ---------
Fair value of pension plan assets
at end of year .................................. $ 682,272 $ 612,392
========= =========
We made the assumptions below to calculate the pension liability:
Discount rate .................................. 7.00% 7.25%
Rate of increase in compensation levels ........ 3.50% 4.50%
Expected long-term rate of return on assets..... 10.00% 9.00%
EMPLOYEE SAVINGS PLAN BENEFITS We also sponsor a defined contribution savings
plan that is offered to nearly all APS employees. In a defined contribution
plan, the benefits a participant is to receive result from regular contributions
to a participant account. Under this plan, we make matching contributions to
participant accounts. We recorded expenses for this plan of:
+ $3.9 million in 1998
+ $3.7 million in 1997 and
+ $3.4 million in 1996.
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,
51
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
retirees do not make contributions to cover a portion of the plan costs. We
retain the right to change or eliminate these benefits.
Funding is based upon actuarially determined contributions that take tax
consequences into account. Plan assets consist primarily of domestic stocks and
bonds. The postretirement benefit expense was:
+ $8.7 million for 1998
+ $9.4 million for 1997 and
+ $15.8 million for 1996.
The following table shows the components of net periodic postretirement benefit
costs before consideration of amounts capitalized or billed to others and
excluding severance costs of $9.6 million in 1996:
1998 1997 1996
-------- -------- --------
(THOUSANDS OF DOLLARS)
Service cost -- benefits earned during
the period.................................. $ 7,676 $ 6,865 $ 7,974
Interest cost on accumulated benefit
obligation ................................. 15,610 14,315 13,395
Expected return on plan assets ............... (12,001) (8,706) (6,696)
Amortization of:
Transition obligation .................... 7,652 7,652 8,223
Net actuarial gains ...................... (2,927) (2,647) (1,344)
-------- -------- --------
Net periodic postretirement benefit cost ..... $ 16,010 $ 17,479 $ 21,552
======== ======== ========
The following table shows a reconciliation of the funded status of the plan to
the amounts recognized in the balance sheets:
1998 1997
--------- ---------
(THOUSANDS OF DOLLARS)
Funded status -- postretirement plan assets less
than accumulated benefit obligation ................ $ (21,912) $ (46,435)
Unrecognized net obligation at transition ............ 107,134 114,787
Unrecognized net actuarial gains ..................... (86,131) (78,209)
--------- ---------
Net postretirement amount recognized
in the balance sheets .............................. $ (909) $ (9,857)
========= =========
52
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The following table sets forth the postretirement benefit plan's change in
accumulated benefit obligation for the plan years 1998 and 1997:
1998 1997
--------- ---------
(THOUSANDS OF DOLLARS)
Accumulated postretirement benefit obligation
at beginning of year ............................... $ 197,581 $ 179,550
Service cost ......................................... 7,676 6,865
Interest cost ........................................ 15,610 14,315
Benefit payments ..................................... (10,347) (6,732)
Actuarial losses ..................................... 24,802 3,583
--------- ---------
Accumulated postretirement benefit obligation
at end of year ..................................... $ 235,322 $ 197,581
========= =========
The following table sets forth the postretirement benefit plan's change in the
fair value of plan assets for the plan years 1998 and 1997:
1998 1997
--------- ---------
(THOUSANDS OF DOLLARS)
Fair value of postretirement plan assets
at beginning of year ............................... $ 151,146 $ 109,763
Actual return on plan assets ......................... 47,284 30,846
Employer contributions ............................... 25,327 17,269
Benefit payments ..................................... (10,347) (6,732)
--------- ---------
Fair value of postretirement plan assets
at end of year ..................................... $ 213,410 $ 151,146
========= =========
We made the assumptions below to calculate the postretirement liability:
Discount rate ............................................ 7.00% 7.25%
Expected long-term rate of return on assets - after tax .. 8.73% 7.75%
Initial health care cost trend rate - under age 65........ 7.50% 8.00%
Initial health care cost trend rate - age 65 and over..... 6.50% 7.00%
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 1998 cost of
postretirement benefits other than pensions would increase by approximately $5
million and the accumulated benefit obligation as of December 31, 1998 would
increase by approximately $37 million.
Assuming a 1% decrease in the health care cost trend rate, the 1998 cost of
postretirement benefits other than pensions would decrease by approximately $4
million and the accumulated benefit obligations as of December 31, 1998 would
decrease by approximately $32 million.
53
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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 APS. The United States Supreme Court has refused to grant
review of the D.C. Circuit's decision. In July 1998, we filed a Petition for
Review regarding DOE's obligation to begin accepting spent nuclear fuel.
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 1998 dollars) over the life of Palo Verde for our share of the costs
related to the on-site interim storage of spent nuclear fuel. Beginning in 1999,
we will accrue these costs as a component of fuel expense, meaning the charges
will be accrued as the fuel is burned. During 1998, we recorded a liability and
a regulatory asset of $35 million for on-site interim nuclear fuel storage costs
related to nuclear fuel burned prior to 1999. 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 1999 through 2020 that
include required purchase provisions. We estimate our 1999 contract requirements
to be about $132 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.
54
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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 $62 million at December 31, 1998 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 1996 regulatory agreement (see Note 3), the ACC began accelerated
amortization of our regulatory asset for coal mine reclamation costs 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, 1998 was about $51 million.
CONSTRUCTION PROGRAM Total capital expenditures in 1999 are estimated at $328
million.
13. NUCLEAR DECOMMISSIONING COSTS
We recorded $11.4 million for decommissioning expense in each of the years 1998,
1997, and 1996. We estimate it will cost about $1.8 billion ($452 million in
1998 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 $145.6 million at December 31,
1998 and $124.6 million at December 31, 1997. We invest the trust funds
primarily in fixed-income securities and domestic stock and classify them as
available for sale. Realized and unrealized gains and losses are reflected in
accumulated depreciation.
In 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 has indicated that a revised exposure draft
will be issued in 1999.
55
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial information for 1998 and 1997 is as follows:
ELECTRIC EARNINGS
OPERATING OPERATING NET FOR
QUARTER ENDED REVENUES INCOME(a) INCOME COMMON STOCK
- ------------- --------- --------- ------ ------------
(THOUSANDS OF DOLLARS)
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
1997
March 31 $379,021 $61,439 $28,645 $25,019
June 30 458,751 99,706 69,493 66,298
September 30 632,821 150,892 129,699 126,715
December 31 407,960 59,788 23,656 20,658
- ----------
(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.
56
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
15. STOCK OPTIONS
Our parent company, Pinnacle West Capital Corporation, offers several stock
incentive plans for our officers, our parent company's officers, and key
employees.
The plans provide for the granting of new options or awards of up to 3.5 million
shares at a price per option not less than fair market value on the date the
option is granted. The plans also provide for the granting of any combination of
stock appreciation rights or dividend equivalents. The awards outstanding under
the various incentive plans at December 31, 1998 approximate 1,497,012
non-qualified stock options, 158,121 restricted shares, and no dividend
equivalent shares, incentive stock options, or stock appreciation rights.
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, "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:
1998 1997 1996
-------- -------- --------
(THOUSANDS OF DOLLARS)
Net income
As reported....................... $255,247 $251,493 $243,471
Pro forma (fair value method)..... $254,640 $251,142 $243,291
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:
1998 1997 1996
------ ------ -------
Risk-free interest rate............. 4.54% 5.66% 5.77%
Dividend growth..................... 3.03% 4.50% 4.50%
Volatility.......................... 18.80% 15.63% 17.10%
Expected life (months).............. 60 60 58
57
<PAGE>
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.
58
<PAGE>
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 on page 28.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION
- ----------- -----------
10.1(a) -- 1999 Management Variable Incentive Plan
10.2(a) -- 1999 Senior Management Variable Incentive Plan
10.3(a) -- 1999 Officers Variable Incentive Plan
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:
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
3.4 Certificates pursuant to 4.3 to Form S-3 1-4473 9-29-93
Sections 10-152.01 and Registration Nos.
10-016, Arizona Revised 33-33910 and 33-55248 by
Statutes, establishing Series A means of September 24,
through V of the Company's 1993 Form 8-K Report
Serial Preferred Stock
</TABLE>
59
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
3.5 Certificate pursuant to 4.4 to Form S-3 1-4473 9-29-93
Section 10-016, Arizona Registration Nos.
Revised Statutes, establishing 33-33910 and 33-55248 by
Series W of the Company's means of September 24,
Serial Preferred Stock 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
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
</TABLE>
60
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
</TABLE>
61
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
4.18 Agreement of Resignation, 4.1 to September 25, 1995 1-4473 10-24-95
Appointment, Acceptance and Form 8-K Report
Assignment dated as of
August 18, 1995 by and
among the Company, Bank of
America National Trust and
Savings Association and The
Bank of New York
10.4 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
10.5 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
10.6 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
10.7 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
10.8 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
</TABLE>
62
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.9 Amended and Restated 10.1 to Pinnacle West 1-8962 3-26-92
Decommissioning Trust 1991 Form 10-K Report
Agreement (PVNGS Unit 2)
dated as of January 31, 1992,
among the Company, Mellon
Bank, N.A., as
Decommissioning Trustee, and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
under two separate Trust
Agreements, each with a
separate Equity Participant,
and as Lessor under two
separate Facility Leases, each
relating to an undivided
interest in PVNGS Unit 2
10.10 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
10.11 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
10.12 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
10.13 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
10.14 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
</TABLE>
63
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.15 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
10.16 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
10.17 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
10.18 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
10.19 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
10.20 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
10.21 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Four Registration Statement
Corners Plant
10.22 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
</TABLE>
64
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.23 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
10.24 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
10.25 Application and Amendment 10.37 to Registration 1-8962 7-25-85
No. 1 to Grant of multi-party Statement on Form 8-B of
rights-of-way and easements, Pinnacle West
Four Corners Power Plant
Site, dated April 25, 1985
10.26 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
10.27 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
10.28 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.29 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70
rights-of-way and easements, Registration Statement
Navajo Plant
10.30 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
</TABLE>
65
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.31 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
10.32 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
10.33(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
</TABLE>
66
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.34(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
10.35(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
10.36(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
10.37 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
10.38 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
</TABLE>
67
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.39 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
10.40(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
10.41(a) Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Directors' Deferred
Compensation Plan, effective
as of January 1, 1993
10.42(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
10.43(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
10.44(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
10.45(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
</TABLE>
68
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.46(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
10.47(a) Pinnacle West Capital 10.10 to 1995 Form 10-K 1-4473 3-29-96
Corporation, Arizona Public Report
Service Company, SunCor
Development Company
and El Dorado Investment
Company Deferred
Compensation Plan as
amended and restated
effective January 1, 1996
10.48(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 10.7 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
10.50(a) Arizona Public Service 10.1 to September 1997 1-4473 11-12-97
Company Director Form 10-K Report
Equity Plan
10.51(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
10.52(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
10.53(a) Letter Agreement between 10.2 to September 1997 1-4473 11-12-97
the Company and Form 10-Q Report
William L. Stewart
</TABLE>
69
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.54(a) Letter Agreement, dated April 10.7 to 1988 Form 10-K 1-4473 3-8-89
3, 1978, between the Company Report
and O. Mark DeMichele,
regarding certain retirement
benefits granted to Mr.
DeMichele
10.55(a) Letter Agreement dated 10.9 to 1996 Form 10-K 1-4473 3-28-97
November 27, 1996 between Report
the Company and
George A. Schreiber, Jr.
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)(d) Key Executive Employment 10.3 to 1989 Form 10-K 1-4473 3-8-90
and Severance Agreement Report
between the Company and
certain executive officers of
the Company
10.58(a)(d) Revised form of Key Executive 10.5 to 1993 Form 10-K 1-4473 3-30-94
Employment and Severance Report
Agreement between the
Company and certain
executive officers of the
Company
10.59(a)(d) Second revised form of Key 10.9 to 1994 Form 10-K 1-4473 3-30-95
Executive Employment and Report
Severance Agreement between
the Company and certain
executive officers of the
Company
10.60(a)(d) Key Executive Employment 10.4 to 1989 Form 10-K 1-4473 3-8-90
and Severance Agreement Report
between the Company and
certain managers of the
Company
</TABLE>
70
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.61(a)(d) Revised form of Key Executive 10.4 to 1993 Form 10-K 1-4473 3-30-94
Employment and Severance Report
Agreement between the
Company and certain key
employees of the Company
10.62(a)(d) Second revised form of Key 10.8 to 1994 Form 10-K 1-4473 3-30-95
Executive Employment and Report
Severance Agreement between
the Company and certain key
employees of the Company
10.63(a) Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option and Report
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 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
10.66 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
10.67 Territorial Agreement 10.1 to March 1998 1-4473 5-15-98
between the Company Form 10-Q Report
and Salt River Project
</TABLE>
71
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.68 Power Coordination 10.2 to March 1998 1-4473 5-15-98
Agreement between Form 10-Q Report
the Company and Salt
River Project
10.69 Memorandum of Agreement 10.3 to March 1998 1-4473 5-15-98
between the Company and Form 10-Q Report
Salt River Project
10.70 Addendum to Memorandum of 10.2 to May 19, 1998 1-4473 6-26-98
Agreement between the Form 8-K Report
Company and Salt River
Project dated as of May
19, 1998
99.1 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93
among PVNGS II Funding Report
Corp., Inc., the Company and
Chemical Bank, as Trustee
99.2 Supplemental Indenture to 4.3 to 1992 Form 10-K 1-4473 3-30-93
Collateral Trust Indenture Report
among PVNGS II Funding
Corp., Inc., the Company and
Chemical Bank, as Trustee
99.3(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92
dated as of August 1, 1986, Form 10-Q Report
among PVNGS Funding
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
</TABLE>
72
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
</TABLE>
73
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
</TABLE>
74
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
</TABLE>
75
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
</TABLE>
76
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
</TABLE>
77
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
</TABLE>
78
<PAGE>
- ---------------
(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, 1998 and the period ended March 30,
1999, the Company filed the following Report on Form 8-K:
Report dated December 1, 1998 relating to an order by the Arizona Supreme
Court staying ACC hearings regarding our settlement agreement with the ACC
Staff.
Report dated December 9, 1998 relating to (1) a Notice of Withdrawal of
Settlement filed by the ACC Staff, (2) terms of expiration of a memorandum of
understanding, (3) ACC adoption of the amended rules, and (4) issues affecting
the agreement with Salt River Project.
Report dated January 11, 1999 relating to (i) the ACC hearing officers'
recommended changes to the amended rules regarding the introduction of retail
electric competition in Arizona and to the June 1998 stranded cost order and
(ii) action by the Arizona Supreme Court vacating its order staying ACC hearings
on the proposed settlement agreement and dismissing the Attorney General's
action.
Report dated February 18, 1999 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-27551 and 333-58445) relating to
the Company's offering of $125 million of Notes.
79
<PAGE>
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 30, 1999 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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
WILLIAM J. POST Principal Executive Officer March 30, 1999
- ----------------------------------------- and Director
(William J. Post, Chief Executive Officer)
GEORGE A SCHREIBER, JR. Principal Accounting Officer, March 30, 1999
- ----------------------------------------- Principal Financial Officer
(George A. Schreiber, Jr.) and Director
JACK E. DAVIS President and Director March 30, 1999
- -----------------------------------------
(Jack E. Davis)
O. MARK DEMICHELE Director March 30, 1999
- -----------------------------------------
(O. Mark DeMichele)
MICHAEL L. GALLAGHER Director March 30, 1999
- -----------------------------------------
(Michael L. Gallagher)
MARTHA O. HESSE Director March 30, 1999
- -----------------------------------------
(Martha O. Hesse)
MARIANNE M. JENNINGS Director March 30, 1999
- -----------------------------------------
(Marianne M. Jennings)
ROBERT E. KEEVER Director March 30, 1999
- -----------------------------------------
(Robert E. Keever)
</TABLE>
80
<PAGE>
<TABLE>
<S> <C> <C>
ROBERT G. MATLOCK Director March 30, 1999
- -----------------------------------------
(Robert G. Matlock)
BRUCE J. NORDSTROM Director March 30, 1999
- -----------------------------------------
(Bruce J. Nordstrom)
JOHN R. NORTON III Director March 30, 1999
- -----------------------------------------
(John R. Norton III)
DONALD M. RILEY Director March 30, 1999
- -----------------------------------------
(Donald M. Riley)
QUENTIN P. SMITH, JR. Director March 30, 1999
- -----------------------------------------
(Quentin P. Smith, Jr.)
WILLIAM L. STEWART President and Director March 30, 1999
- -----------------------------------------
(William L. Stewart)
RICHARD SNELL Director March 30, 1999
- -----------------------------------------
(Richard Snell)
DIANNE C. WALKER Director March 30, 1999
- -----------------------------------------
(Dianne C. Walker)
BEN F. WILLIAMS JR. Director March 30, 1999
- -----------------------------------------
(Ben F. Williams, Jr.)
</TABLE>
81
<PAGE>
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, 1998
-----------------
Arizona Public Service Company
(Exact name of registrant as specified in charter)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
INDEX TO EXHIBITS
Exhibit No. Description
- ----------- -----------
10.1a ___ 1999 Management Variable Incentive Plan
10.2a ___ 1999 Senior Management Variable Incentive Plan
10.3a ___ 1999 Officers Variable Incentive Plan
23.1 ___ Consent of Deloitte & Touche LLP
27.1 ___ Financial Data Schedule
- ---------------
(a) Management contract or compensatory plan or arrangement required to
be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
For a description of the Exhibits incorporated in this filing by
reference, see Part IV, Item 14.
Exhibit 10.1a
Under the Company's 1999 Management Variable Incentive Plan, the Chief Executive
Officer of the Company, with the approval of the Human Resources Committee of
the Board of Directors, annually designates employees to participate in the
program, establishes their participation level, and establishes certain
financial and operational goals for the Company which must be satisfied in order
for variable pay awards to be made. The impact, if any, of each employee's
performance on his or her variable pay award is determined by his or her
officer. Subject to final approval by the Human Resources Committee of the Board
of Directors, the Chief Executive Officer of the Company also determines at
year-end the degree to which those goals have been satisfied and the amount of
variable pay to be awarded to participating employees, if any.
Exhibit 10.2a
Under the Company's 1999 Senior Management Variable Incentive Plan, the Chief
Executive Officer of the Company, with the approval of the Human Resources
Committee of the Board of Directors, annually designates employees to
participate in the program, establishes their participation level, and
establishes certain financial and operational goals for the Company which must
be satisfied in order for variable pay awards to be made. The impact, if any, of
each employee's performance on his or her variable pay award is determined by
his or her officer. Subject to final approval by the Human Resources Committee
of the Board of Directors, the Chief Executive Officer of the Company also
determines at year-end the degree to which those goals have been satisfied and
the amount of variable pay to be awarded to participating employees, if any.
Exhibit 10.3a
Under the Company's 1999 Officers Variable Incentive Plan, the Chief Executive
Officer of the Company, with the approval of the Human Resources Committee of
the Board of Directors, annually designates the officers who will participate in
the program, establishes their participation level, and establishes certain
financial and operational goals for the Company which must be satisfied in order
for variable pay awards to be made. The impact, if any, of each officer's
performance on his or her variable pay award is determined by the Chief
Executive Officer of the Company, with the approval of the Human Resources
Committee. Subject to final approval by the Human Resources Committee of the
Board of Directors, the Chief Executive Officer also determines at year-end the
degree to which those goals have been satisfied and the amount of variable pay
to be awarded to participating officers, if any.
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-51085, 33-57822, 333-27551 and 333-58445 of Arizona Public Service Company on
Form S-3 and in Registration Statement No. 333-46161 of Arizona Public Service
Company on Form S-8 of our report dated March 4, 1999, appearing in this Annual
Report on Form 10-K of Arizona Public Service Company for the year ended
December 31, 1998.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
March 26, 1999
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<MULTIPLIER> 1,000
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<S> <C>
<PERIOD-TYPE> 12-MOS
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<PERIOD-START> JAN-01-1998
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<TOTAL-NET-UTILITY-PLANT> 4,730,563
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<TOTAL-DEFERRED-CHARGES> 1,064,656
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<TOTAL-ASSETS> 6,393,299
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9,401
85,840
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0
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<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,102,555
<TOT-CAPITALIZATION-AND-LIAB> 6,393,299
<GROSS-OPERATING-REVENUE> 2,006,398
<INCOME-TAX-EXPENSE> 192,207
<OTHER-OPERATING-EXPENSES> 1,443,380
<TOTAL-OPERATING-EXPENSES> 1,635,587
<OPERATING-INCOME-LOSS> 370,811
<OTHER-INCOME-NET> 20,448
<INCOME-BEFORE-INTEREST-EXPEN> 391,259
<TOTAL-INTEREST-EXPENSE> 136,012
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<EARNINGS-AVAILABLE-FOR-COMM> 245,544
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<TOTAL-INTEREST-ON-BONDS> 116,213
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