Document/Exhibit Description Pages Size
1: 10-K Annual Report for the Year Ended 12/31/1999 84 442K
2: EX-10.1.A 2000 Management Variable Incentive Plan 1 7K
11: EX-10.10.A Second Amendment to Deferred Compensation Plan 4 19K
12: EX-10.11.A First Amendment to Stock Option and Incent. Plan 3 15K
13: EX-10.12A First Amendment to 1994 Long-Term Incentive Plan 3 14K
14: EX-10.13A Supplemental Excess Benefit Retirement Plan 14 42K
15: EX-10.14A Trust for Deferred Comp. Plans Dated 08/01/1996 14 47K
16: EX-10.15A First Amendment Dated 12/07/1999 2 10K
17: EX-10.16A Letter Agreement Dated 7/28/95 - Flores 1 11K
18: EX-10.17A Letter Agreement Dated 10/3/97 - Levine 1 9K
3: EX-10.2.A 2000 Sr. Mgmt Variable Incentive Plan 1 7K
4: EX-10.3.A 2000 Officer Variable Incentive Plan 1 7K
5: EX-10.4.A 2000 Mgmt Variable Incentive Plan (Aps) 1 7K
6: EX-10.5.A 2000 Sr. Mgmt Variable Incentive Plan (Aps) 1 7K
7: EX-10.6.A 2000 Officers Variable Incentive Plan (Aps) 1 7K
8: EX-10.7.A First Amendment Effective as of 01/01/1998 2 11K
9: EX-10.8.A Fourth Amendment Effective Dated 12/28/1999 2± 12K
10: EX-10.9.A Letter Agreement Dated 12/13/1999 7 35K
19: EX-21 Subsidiaries of Pinnacle West Capital Corporation 2± 9K
20: EX-23.1 Consent of Deloitte & Touche LLP 1 8K
21: EX-27.1 Financial Data Schedule 1 9K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______ TO ______
COMMISSION FILE NUMBER 1-8962.
PINNACLE WEST CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
ARIZONA 86-0512431
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
400 East Van Buren Street, Suite 700 (602) 379-2500
Phoenix, Arizona 85004 (Registrant's telephone number,
(Address of principal executive including area code)
offices, including zip code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
================================================================================
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
--------------------------------------------------------------------------------
Common Stock, ........................................ New York Stock Exchange
No Par Value Pacific Stock Exchange
================================================================================
AGGREGATE MARKET VALUE
OF SHARES HELD BY
TITLE OF EACH CLASS SHARES OUTSTANDING AS NON-AFFILIATES AS OF
OF VOTING STOCK OF MARCH 27, 2000 MARCH 27, 2000
--------------------------------------------------------------------------------
Common Stock, No Par Value ...... 84,722,640 $2,271,625,785(a)
----------
(a) Computed by reference to the closing price on the composite tape on March
27, 2000, as reported by the Wall Street Journal.
================================================================================
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
================================================================================
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 17, 2000 are incorporated by reference
into Part III hereof.
================================================================================
TABLE OF CONTENTS
Page
----
GLOSSARY ................................................................. 1
PART I
Item 1. Business...................................................... 2
Item 2. Properties.................................................... 13
Item 3. Legal Proceedings............................................. 17
Item 4. Submission of Matters to a Vote of
Security Holders............................................ 17
Supplemental Item.
Executive Officers of the Registrant.......................... 18
PART II
Item 5. Market for Registrant's Common Stock and
Related Security Holder Matters.............................. 20
Item 6. Selected Consolidated Financial Data........................... 21
Item 7. Financial Review............................................... 23
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..... 30
Item 8. Financial Statements and Supplementary Data.................... 37
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................................................................ 78
i
GLOSSARY
ACC -- Arizona Corporation Commission
ACC STAFF -- Staff of the Arizona Corporation Commission
AFUDC -- Allowance for Funds Used During Construction
ANPP -- Arizona Nuclear Power Project, also known as Palo Verde
APS -- Arizona Public Service Company
APSES-- APS Energy Services Company, Inc.
CC&N -- Certificate of convenience and necessity
CHOLLA -- Cholla Power Plant
CHOLLA 4 -- Unit 4 of the Cholla Power Plant
COMPANY -- Pinnacle West Capital Corporation
EL DORADO -- El Dorado Investment Company
EPA -- United States Environmental Protection Agency
FASB -- Financial Accounting Standards Board
FERC -- Federal Energy Regulatory Commission
FOUR CORNERS -- Four Corners Power Plant
GAAP -- Generally accepted accounting principles
ITC -- Investment tax credit
KW -- Kilowatt, one thousand watts
KWH -- Kilowatt-hour, one thousand watts per hour
MW -- Megawatt hours, one million watts
MWH -- Megawatt hours, one million watts per hour
NGS -- Navajo Generating Station
NRC -- Nuclear Regulatory Commission
PALO VERDE -- Palo Verde Nuclear Generating Station
PINNACLE WEST ENERGY -- Pinnacle West Energy Corporation
SEC -- Securities and Exchange Commission
SALT RIVER PROJECT -- Salt River Project Agricultural Improvement and Power
District
SUNCOR -- SunCor Development Company
1
PART I
ITEM 1. BUSINESS
THE COMPANY
GENERAL
We were incorporated in 1985 under the laws of the State of Arizona and are
engaged, through our subsidiaries, in the generation, transmission, and
distribution of electricity and selling energy, products and services; in real
estate development; and in venture capital investment. Our principal executive
offices are located at 400 East Van Buren Street, Suite 700, Phoenix, Arizona
85004 (telephone 602-379-2500).
At December 31, 1999, we employed about 7,534 people, including the
employees of our subsidiaries. Of these employees, 6,234 were employees of our
major subsidiary, APS, and employees assigned to joint projects of APS where APS
serves as a project manager, and about 1,300 were our employees and employees of
our other subsidiaries.
Our other subsidiaries, in addition to APS, include SunCor, El Dorado, APS
Energy Services and Pinnacle West Energy. See "Business of SunCor Development
Company," "Business of El Dorado Investment Company," "Business of APS Energy
Services Company, Inc.," and "Business of Pinnacle West Energy Corporation" in
this Item for further information regarding these businesses.
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; the ability of APS to successfully compete outside its 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; Year 2000
issues; the strength of the stock market (particularly the technology sector)
and the strength of the real estate market. See "Business of Arizona Public
Service Company -- Competition" for a discussion of some of these factors.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
Following is a discussion of the business of APS, our major subsidiary.
GENERAL
APS was incorporated in 1920 under the laws of Arizona and is 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). We own all of the outstanding shares of APS' common
stock.
APS is Arizona's largest electric utility, with 827,000 customers. APS
provides wholesale or retail electric service to the entire state of Arizona,
with the exception of Tucson and about one-half of the Phoenix area. During
1999, no single purchaser or user of energy accounted for more than 2% of total
electric revenues. See Note 18 of Notes to Financial Statements for a discussion
of business segments. At December 31, 1999, APS employed 6,234 people, which
includes employees assigned to joint projects where APS is project manager.
2
COMPETITION
RETAIL
The ACC has regulatory authority over APS in matters relating to retail
electric rates, the issuance of securities, and the transaction of business with
affiliated parties. See Note 3 of Notes to Financial Statements in Item 8 for a
discussion of the electric industry restructuring in Arizona, including APS'
1999 Settlement Agreement, ACC rules for the introduction of retail electric
competition, and Arizona legislative initiatives. See also "Financial Review -
Competition and Industry Restructuring" in Item 7. In addition to the
introduction of competition pursuant to the Settlement Agreement and the ACC
rules, APS is subject to varying degrees of competition in certain territories
adjacent to or within areas that APS serves that are also currently served by
other utilities in its 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).
APS faces competitive challenges from low-cost hydroelectric power and
natural gas fuel, as well as the access of some utilities to preferential
low-priced federal power and other subsidies. In addition, some customers,
particularly industrial and large commercial, may own and operate facilities to
generate their own electric energy requirements. Such facilities may be operated
by the customers themselves or by other entities engaged for such purpose.
WHOLESALE
APS competes with other utilities, power marketers, and independent power
producers in the sale of electric capacity and energy in the wholesale market.
APS expects that competition to sell capacity will remain vigorous. APS' rates
for wholesale power sales and transmission services are subject to regulation by
the FERC. During 1999, approximately 23% of its electric operating revenues
resulted from such sales and charges.
The National Energy Policy Act of 1992 has promoted increased competition
in the wholesale electric power markets. The Energy Act reformed provisions of
the Public Utility Holding Company Act of 1935 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.
APS has filed a revised open access tariff in accordance with this decision. APS
does not believe that this decision will have a material adverse impact on its
results of operations or financial position.
REGULATORY ASSETS
APS' major regulatory assets are deferred income taxes and rate
synchronization cost deferrals. As a result of APS' September 1999 Settlement
Agreement, APS has discontinued the application of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation," for its generation operations. This means that regulatory assets,
unless reestablished as recoverable through ongoing regulated cash flows, were
eliminated and the generation assets were tested for impairment. APS determined
that the generation assets were not impaired. Prior to the Settlement Agreement,
under a 1996 regulatory agreement, the ACC accelerated the amortization of
substantially all of APS' regulatory assets to an eight-year period that would
have ended June 30, 2004. See Notes 1, 3, and 4 of Notes to Financial Statements
in Item 8 for additional information.
3
COMPETITIVE STRATEGIES
APS is pursuing strategies to maintain and enhance its 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 APS'
core business through customer service, distribution system reliability,
business segmentation, and the anticipation of market opportunities; (iii) an
emphasis on good regulatory relationships; (iv) asset maximization (e.g., higher
capacity factors and lower forced outage rates); (v) strengthening its capital
structure and financial condition; (vi) leveraging core competencies into
related areas, such as energy management products and services; and (vii)
operating a trading floor and implementing a risk management program to provide
for more stability of prices and the ability to retain or grow incremental
margins through more competitive pricing and risk management. Underpinning APS'
competitive strategies are the strong growth characteristics of its service
territory. As competition in the electric utility industry continues to evolve,
APS will continue to evaluate strategies and alternatives that will position it
to compete effectively in a more competitive, restructured industry.
GENERATING FUEL AND PURCHASED POWER
1999 ENERGY MIX
APS' sources of energy during 1999 were: coal - 29.9%; nuclear - 22.4%;
purchased power - 43.2%; gas - 4.4%; and other - 0.1%.
COAL SUPPLY
LEASES NGS and Four Corners are located on the Navajo Reservation and held
under easements granted by the federal government as well as leases from the
Navajo Nation. See "Properties- Plant Sites Leased from the Navajo Nation" in
Item 2. Most of the coal for Cholla is supplied by a coal supplier who mines all
of the coal under a long-term lease of coal reserves owned by the Navajo Nation,
the federal government, and private landholders. Remaining coal requirements are
purchased on the spot market. All of the coal for Four Corners is purchased from
a coal supplier with a long-term lease of coal reserves owned by the Navajo
Nation. The coal for NGS comes from a supplier with a long-term lease with the
Navajo Nation and the Hopi Tribe. See Note 12 of Notes to Financial Statements
in Item 8 for information regarding our obligation for coal mine reclamation.
CONTRACTS Cholla presently has sufficient coal under current contracts to
ensure a reliable fuel supply through 2005. Portions of the fuel supply are bid
on the spot market to take advantage of competitive pricing options. Following
expiration of current contracts, there are numerous competitive fuel supply
options available to ensure continuous plant operation. Cholla also has certain
requirements for low sulfur coal and the current supplier is expected to
continue to provide most of Cholla's low sulfur coal requirements through the
current contract. There are sufficient reserves of low sulfur coal available
from other suppliers to ensure the continued operation of Cholla for its useful
life. The sulfur content of coal at Cholla for 1999 was 0.47%. Average prices
paid for all coal supplied from reserves dedicated under existing contracts were
slightly lower than, but comparable to, 1998. For the years remaining on the
contracts after 2000, prices will be reduced.
Four Corners is a mine-mouth operation which is under contract for coal
through 2004. There are options to extend the contract through the plant site
lease expiration in 2017. The sulfur content of Four Corners coal for 1999 was
0.77%, and the units are equipped with scrubbers. The average price paid for all
coal supplied under the existing contract was slightly lower than, but
comparable to, 1998. The Four Corners lease waives, until July 2001, the
requirement that APS, as well as its fuel supplier, pay certain taxes to the
Navajo Nation. In September 1997, a settlement agreement was finalized between
the coal supplier, the Navajo Nation, and Four Corners participants, which
settled certain issues in the lease regarding the obligation of the fuel
supplier to pay taxes prior to the expiration of tax waivers in 2001. Pursuant
to this agreement, the coal supplier currently pays a possessory interest tax to
the Navajo Nation, which is contractually reimbursed by participants. The
parties also agreed to
4
investigate alternative contractual arrangements and business relationships
before 2001 in an effort to permit the electricity generated at Four Corners to
be priced competitively. APS anticipates that additional taxes will be levied by
the Navajo Nation upon the expiration of the tax waivers; however, APS cannot
currently predict the outcome of this matter or the amount of the additional
taxes.
NGS is under contract with its coal supplier through 2011, with options to
extend through the plant site lease. The sulfur content of coal at NGS for 1999
was 0.53%, and the units are equipped with scrubbers. Average price paid for
coal supplied in 1999 under the existing contract was lower than, but comparable
to, 1998. The NGS lease waives certain taxes through the lease expiration in
2019. The lease provides for the potential to renegotiate the coal royalty in
2007 and 2017, which may impact the fuel price.
NATURAL GAS SUPPLY
APS is a party to contracts with a number of natural gas suppliers that
allow it to purchase natural gas in the method it determines to be most
economic. Currently, APS is purchasing the majority of its natural gas
requirements from numerous companies under these contracts. APS' natural gas
supply is transported pursuant to a firm transportation service contract with El
Paso Natural Gas Company. APS continues to analyze the market to determine the
most favorable source and method of meeting its 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 2002. Existing contracts and options could be
utilized to meet approximately 88% of requirements in 2003, 88% of requirements
in 2004, 49% of requirements in 2005, and 16% of requirements in 2006 and
beyond. Spot purchases on the uranium market will be made, as appropriate, in
lieu of any uranium that might be obtained through contractual options.
The Palo Verde participants have contracted for uranium conversion
services. Existing contracts and options could be utilized to meet approximately
70% of requirements in 2000, 75% of requirements in 2001 and 80% of requirements
in 2002. The Palo Verde participants have an enrichment services contract and an
enriched uranium product contract that furnish enrichment services required for
the operation of the three Palo Verde units through 2003. In addition, existing
contracts will provide fuel assembly fabrication services until at least 2015
for each Palo Verde unit.
SPENT NUCLEAR FUEL AND WASTE DISPOSAL. Pursuant to the Nuclear Waste Policy
Act of 1982, as amended in 1987, the United States Department of Energy ("DOE")
is obligated to accept and dispose of all spent nuclear fuel and other
high-level radioactive wastes generated by domestic power reactors. The NRC,
pursuant to the Waste Act, requires operators of nuclear power reactors to enter
into spent fuel disposal contracts with DOE. Under the Waste Act, DOE was to
develop the facilities necessary for the storage and disposal of spent nuclear
fuel and to have the first such facility in operation by 1998. That facility was
to be a permanent repository. DOE has announced that such a repository now
cannot be completed before 2010. In July 1996, the United States Court of
Appeals for the District of Columbia Circuit (D.C. Circuit) ruled that the DOE
has an obligation to start disposing of spent nuclear fuel no later than January
31, 1998. By way of letter dated December 17, 1996, DOE informed APS and other
contract holders that DOE anticipates that it would be unable to begin
acceptance of spent nuclear
5
fuel for disposal in a repository or interim storage facility by January 31,
1998. In November 1997, the D.C. Circuit issued a Writ of Mandamus precluding
DOE from excusing its own delay on the grounds that DOE has not yet prepared a
permanent repository or interim storage facility. On May 5, 1998, the D.C.
Circuit issued a ruling refusing to order DOE to begin moving spent nuclear
fuel. See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to
Financial Statements in Item 8 for a discussion of interim spent fuel storage
costs.
Several bills have been introduced in Congress contemplating the
construction of a central interim storage facility; however, there is resistance
to certain features of these bills both in Congress and the Administration.
Facility funding is a further complication. While all nuclear utilities pay
into a so-called nuclear waste fund an amount calculated on the basis of the
output of their respective plants, the annual Congressional appropriations for
the permanent repository have been for amounts less than the amounts paid into
the waste fund (the balance of which is being used for other purposes).
According to DOE spokespersons, the fund may now be at a level less than needed
to achieve a 2010 operational date for a permanent repository. No funding will
be available for a central interim facility until one is authorized by Congress.
APS has storage capacity in existing fuel storage pools at Palo Verde
which, with certain modifications, could accommodate all fuel expected to be
discharged from normal operation of Palo Verde through about 2002. Construction
of a new facility for on-site dry storage of spent fuel is underway. Once this
facility is completed and approvals are granted, APS believes 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, APS is currently shipping
low-level waste to off-site facilities. APS currently believes that interim
low-level waste storage methods are or will be available for use by Palo Verde
to allow its continued operation and to safely store low-level waste until a
permanent disposal facility is available.
APS believes that scientific and financial aspects of the issues of spent
fuel and low-level waste storage and disposal can be resolved satisfactorily.
However, APS also acknowledges that their ultimate resolution in a timely
fashion will require political resolve and action on national and regional
scales which APS is less able to predict.
PURCHASED POWER AGREEMENTS
In addition to that available from its own generating capacity (see
"Properties" in Item 2), APS purchases 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 APS
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 APS pursuant
to a related territorial agreement. The generating capacity available to APS
pursuant to the contract was 316 MW January through May 1999, and starting June
1999 changed to 302 MW. In 1999, APS received approximately 1,056,200 MWh of
energy under the contract and paid about $43.9 million for capacity availability
and energy received. See Note 3 of Notes to Financial Statements for a
discussion of amendments to this contract and other agreements with Salt River
Project.
In September 1990, APS entered into a thirty year agreement under which APS
and PacifiCorp engage in one-for-one seasonal capacity exchanges. APS receives
electricity from PacifiCorp during APS' summer peak season. APS will have 480 MW
of generating capacity available to it under the agreements until 2020. In 1999,
APS had 480 MW of generating capacity available from PacifiCorp and APS received
approximately 572,382 MWh of energy under the capacity exchange.
6
CONSTRUCTION PROGRAM
During the years 1997 through 1999, APS incurred approximately $962 million
in capital expenditures. Utility capital expenditures for the years 2000 through
2002 are expected to be primarily for expanding transmission and distribution
capabilities to meet customer growth, upgrading existing facilities, and for
environmental purposes. Capitalized expenditures, including expenditures for
environmental control facilities, for the years 2000 through 2002 have been
estimated as follows:
(MILLIONS OF DOLLARS)
BY YEAR BY MAJOR FACILITIES
------- -------------------
2000 $ 384 Production $ 255
2001 342 Transmission and Distribution 691
2002 334 General 114
------ ------
Total $1,060 Total $1,060
====== ======
The amounts for 2000 through 2002 exclude capitalized interest costs and
include capitalized property taxes and about $30-$35 million each year for
nuclear fuel. APS conducts a continuing review of its construction program.
MORTGAGE REPLACEMENT FUND REQUIREMENTS
So long as any of APS' first mortgage bonds are outstanding, APS is
required for each calendar year to deposit with the trustee under its mortgage
cash in a formularized amount related to net additions to its mortgaged utility
plant. APS may satisfy all or any part of this "replacement fund" requirement by
utilizing redeemed or retired bonds, net property additions, or property
retirements. For 1999, the replacement fund requirement amounted to
approximately $143 million. Certain of the bonds APS has issued under the
mortgage that are callable prior to maturity are redeemable at their par value
plus accrued interest with cash APS deposits in the replacement fund. 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. APS is subject to a number of requirements under the Clean
Air Act. Pursuant to the Clean Air Act, the EPA adopted regulations that address
visibility impairment in certain federally-protected areas which can be
reasonably attributed to specific sources. In September 1991, the EPA issued a
final rule that limited sulfur dioxide emissions at NGS. One NGS unit had to
comply with this rule in 1997, one in 1998, and the last unit in 1999. Salt
River Project is the NGS operating agent. Salt River Project estimates a capital
cost of $430 million and annual operations and maintenance costs of
approximately $14 million for all three units, for NGS to meet these
requirements. APS is required to fund 14% of these expenditures. About all of
these capital costs have been incurred.
The Clean Air Act also addresses, among other things:
* "acid rain,"
* visibility in certain specified areas,
* hazardous air pollutants and
* areas that have not attained national ambient air quality
standards.
With respect to "acid rain," the Clean Air Act establishes a system of sulfur
dioxide emissions "allowances." Each existing utility unit is granted a certain
number of "allowances." For Phase II plants, which include APS' plants,
allowances will be required beginning in the year 2000 to operate the plants.
Based on EPA allowance allocations,
7
APS has sufficient allowances to permit continued operation of its plants at
current levels without installing additional equipment.
The Clean Air Act also requires the EPA to set nitrogen oxides emissions
limitations. These limitations require certain plants to install additional
pollution control equipment. In December 1996, the EPA issued rules for nitrogen
oxides emissions limitations that would have required APS to install additional
pollution control equipment at Four Corners by January 1, 2000. On February 14,
1997, APS filed a Petition for Review in the United States Court of Appeals for
the District of Columbia. APS alleged that the EPA improperly classified Four
Corners Unit 4 in these rules, thereby subjecting Unit 4 to a more stringent
emission limitation. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 97-1091. In February 1998, the Court
vacated the Unit 4 emission limitation and remanded the issue to EPA for
reconsideration. In December 1999, EPA's direct final rule, which classified
Four Corners Unit 4 as APS had proposed, became final. APS does not currently
expect this rule to have a material impact on its financial position or results
of operations.
With respect to protection of visibility in certain specified areas, the
Clean Air Act requires the EPA to conduct a study concerning visibility
impairment in those areas and to identify sources contributing to such
impairment. Interim findings of this study indicate that any beneficial effect
on visibility as a result of the Clean Air Act would be offset by expected
population and industry growth. The Clean Air Act also requires EPA to establish
a "Grand Canyon Visibility Transport Commission" to complete a study on
visibility impairment in the "Golden Circle of National Parks" in the Colorado
Plateau. NGS, Cholla, and Four Corners are located near the Golden Circle of
National Parks. The Commission completed its study and on June 10, 1996
submitted its final recommendations to the EPA.
On April 22, 1999, the EPA announced final regional haze rules. These new
regulations require states to submit, by 2008, implementation plans containing
requirements to eliminate all man-made emissions causing visibility impairment
in certain specified areas, including the Golden Circle of National Parks in the
Colorado Plateau. The 2008 implementation plans must also include consideration
and potential application of best available retrofit technology ("BART") for
major stationary sources which came into operation between August 1962 and
August 1977, such as the Navajo Generating Station, Cholla Power Plant and Four
Corners Power Plant. The nine western states and tribes that participated in the
Grand Canyon Visibility Transport Commission process will have the option to
follow an alternate implementation plan and schedule for areas considered by the
Commission. Under this option, those states and tribes would submit
implementation plans by 2003, which would incorporate the emission reduction
scheme adopted in the Commission's recommendations and application of BART by
2018, possibly using an emission trading program. Any states and tribes that
implement this option will also have to submit revised implementation plans in
2008 to address visibility in certain specified areas that were not considered
by the Commission. Because Arizona and the Navajo Nation have the discretion to
choose between the national or Commission options and a variety of pollution
controls to meet the requirements of the regional haze rules, the actual impact
on APS cannot be determined at this time.
Also, in July 1997, EPA promulgated final National Ambient Air Quality
Standards for ozone and particulate matter. Pursuant to the rules, the ozone
standard is more stringent and a new ambient standard for very fine particles
has been established. Congress has enacted legislation that could delay the
implementation of regional haze requirements and the particulate matter ambient
standard. These standards were challenged and the court determined that EPA's
promulgation of the standards violated the constitutional prohibition on
delegation of legislative power. The court remanded the ozone standard, vacated
the coarse particulate matter standard, and invited the parties to brief the
court on vacating or remanding the fine particulate matter standard. APS cannot
currently predict EPA's response to this decision. Because the actual level of
emissions controls, if any, for any unit cannot be determined at this time, APS
currently cannot estimate the capital expenditures, if any, which would result
from the final rules. However, APS does not currently expect these rules to have
a material adverse effect on its financial position or results of operations.
With respect to hazardous air pollutants emitted by electric utility steam
generating units, the Clean Air Act requires two studies. The results of the
first study indicated an impact from mercury emissions from such units in
certain unspecified areas. The EPA has not yet stated whether or not mercury
emissions limitations will be
8
imposed. Secondly, the EPA will complete a general study by December 2000
concerning the necessity of regulating hazardous air pollutant emissions from
such units under the Clean Air Act. Because APS cannot speculate as to the
ultimate requirements by the EPA, APS cannot currently estimate the capital
expenditures, if any, which may be required as a result of these studies.
Certain aspects of the Clean Air Act may require APS to make related
expenditures, such as permit fees. APS does not expect any of these to have a
material impact on its financial position or results of operations.
FEDERAL IMPLEMENTATION PLAN. In September 1999, the EPA proposed a Federal
Implementation Plan ("FIP") to set air quality standards at certain power
plants, including the Navajo Generating Station and the Four Corners Power
Plant. The comment period on this proposal ended in November 1999. The FIP is
similar to current Arizona regulation of NGS and New Mexico regulation of Four
Corners, with minor modifications. APS does not currently expect FIP to have a
material impact on its 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 APS that the EPA
considers APS to be a PRP in the Indian Bend Wash Superfund Site, South Area.
Our Ocotillo Power Plant is located in this area. APS is in the process of
conducting an investigation to determine the extent and scope of contamination
at the plant site. Based on the information to date, including available
insurance coverage and an EPA estimate of cleanup costs, APS does not expect
this matter to have a material impact on its financial position or results of
operations.
MANUFACTURED GAS PLANT SITES. APS is currently investigating properties
which APS now owns or which were at one time owned by APS or its corporate
predecessors, that were at one time sites of, or sites associated with,
manufactured gas plants. The purpose of this investigation is to determine if:
* waste materials are present
* such materials constitute an environmental or health risk and
* APS has any responsibility for remedial action.
Where appropriate, APS has begun remediation of certain of these sites. APS does
not expect these matters to have a material adverse effect on its financial
position 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. APS is the Four Corners operating agent. APS owns a 100% interest
in Four Corners Units 1, 2, and 3, and a 15% interest in Four Corners Units 4
and 5. APS owns a 14% interest in 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
9
* 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. APS cannot currently
predict the outcome of this matter.
In February 1998, the EPA promulgated regulations specifying those
provisions of the Clean Air Act for which it is appropriate to treat Indian
tribes in the same manner as states. The EPA indicated that it believes that the
Clean Air Act generally would supersede pre-existing binding agreements that may
limit the scope of tribal authority over reservations. On April 10, 1998, APS
filed a Petition for Review in the United States Court of Appeals for the
District of Columbia. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 98-1196. On February 19, 1999, the EPA
promulgated regulations setting forth the EPA's approach to issuing Federal
operating permits to covered stationary sources on Indian reservations. On April
15, 1999, APS filed a Petition for Review in the United States Court of Appeals
for the District of Columbia. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 99-1146.
WATER SUPPLY
Assured supplies of water are important for APS' generating plants. At the
present time, APS has adequate water to meet its needs. However, conflicting
claims to limited amounts of water in the southwestern United States have
resulted in numerous court actions in recent years.
Both groundwater and surface water in areas important to APS' operations
have been the subject of inquiries, claims, and legal proceedings which will
require a number of years to resolve. APS is one of a number of parties in a
proceeding before a state court in New Mexico to adjudicate rights to a stream
system from which water for Four Corners is derived. (STATE OF NEW MEXICO, IN
THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY
OF FARMINGTON, UTAH INTERNATIONAL, INC., ET AL., San Juan County, New Mexico,
District Court No. 75-184). An agreement reached with the Navajo Nation in 1985,
however, provides that if Four Corners loses a portion of its rights in the
adjudication, the Navajo Nation will provide, for a then-agreed upon cost,
sufficient water from its allocation to offset the loss.
A summons served on APS in early 1986 required all water claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987, in an action pending in Maricopa County Superior Court. (IN RE
THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA RIVER SYSTEM AND
SOURCE, Supreme Court Nos. WC-79-0001 through WC-79-0004 (Consolidated) [WC-1,
WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4
(Consolidated)). Palo Verde is located within the geographic area subject to the
summons. APS' rights and the rights of the Palo Verde participants to the use of
groundwater and effluent at Palo Verde is potentially at issue in this action.
As project manager of Palo Verde, APS filed claims that dispute the court's
jurisdiction over the Palo Verde participants' groundwater rights and their
contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks
confirmation of such rights. Three of APS' less-utilized power plants are also
located within the geographic area subject to the summons. APS' claims dispute
the court's jurisdiction over its groundwater rights with respect to these
plants. Alternatively, APS seeks confirmation of such rights. The Arizona
Supreme Court recently issued a decision confirming that certain groundwater
rights may be available to the federal government and Indian tribes. APS and
other parties have petitioned the U.S. Supreme Court for review of this
decision. Another issue important to the claims is pending on appeal to the
Arizona Supreme Court. No trial date concerning APS' water rights claims has
been set in this matter.
10
APS has also filed claims to water in the Little Colorado River Watershed
in Arizona in an action pending in the Apache County Superior Court. (IN RE THE
GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE LITTLE COLORADO RIVER
SYSTEM AND SOURCE, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417).
APS' groundwater resource utilized at Cholla is within the geographic area
subject to the adjudication and is therefore potentially at issue in the case.
APS' claims dispute the court's jurisdiction over its groundwater rights.
Alternatively, APS seeks confirmation of such rights. The parties are in the
process of settlement negotiations with respect to this matter. No trial date
concerning APS' water rights claims has been set in this matter.
Although the foregoing matters remain subject to further evaluation, APS
expects that the described litigation will not have a material adverse impact on
its financial position or results of operations.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
SunCor was incorporated in 1965 under the laws of the State of Arizona and
is engaged primarily in the acquisition, ownership, development, operation, and
sale of land and other real property, including homes and commercial buildings.
The principal executive offices of SunCor are located at 3838 North Central,
Suite 1500, Phoenix, Arizona 85012 (telephone 602-285-6800). SunCor and its
subsidiaries, excluding SunCor Resort & Golf Management, Inc. ("Resort
Management"), employ approximately 140 persons. Resort Management, which manages
the Wigwam Resort and Country Club (the "Wigwam"), employs between 620 and 750
persons at the Wigwam, depending on the Wigwam's operating season. In addition,
Resort Management operates four golf courses and three family entertainment
operations, which together employ about 350 people.
SunCor's assets consist primarily of land and improvements and other real
estate investments. SunCor's major asset is the Palm Valley project, which
consists of over 7,000 acres and is located west of Phoenix in the area of
Goodyear/Litchfield Park, Arizona ("Palm Valley"). SunCor has completed the
master plan for development of Palm Valley. There has been significant
residential and commercial development at Palm Valley by SunCor and by other
developers that have acquired land from SunCor or entered into joint ventures
with SunCor. Development at Palm Valley currently includes residential
communities, including a retirement community, with golf courses, hotels,
restaurants, commercial and retail outlets, a hospital, and assisted-care
facilities.
Other SunCor projects under development include seven master-planned
communities and four commercial projects. The four commercial projects and four
of the master-planned communities are located in the Phoenix area. Other
master-planned communities are located near Sedona, Arizona, St. George, Utah,
and Santa Fe, New Mexico. Several of the master-plan and commercial projects are
joint ventures with other developers, financial partners, or landowners.
For the past three years, SunCor's operating revenues were about: 1999,
$130.2 million; 1998, $125.4 million; and 1997, $123.6 million. For those same
periods, SunCor's net income was about: 1999, $6.1 million; 1998, $44.7 million;
and 1997, $5.3 million. About $37.2 million of SunCor's 1998 net income
represents income related to the recognition of a deferred tax asset. The
deferred tax asset relates to net operating losses and book/tax basis
differences. SunCor is expected to realize these benefits in subsequent periods
pursuant to an intercompany tax allocation agreement. On a consolidated basis,
there was no impact to consolidated net income. SunCor's capital needs consist
primarily of capital expenditures for land development and home construction for
SunCor's homebuilding subsidiary, Golden Heritage Homes, Inc. On the basis of
projects now under development, SunCor expects capital needs over the next three
years to be 2000, $53 million; 2001, $43 million; and 2002, $51 million.
At December 31, 1999, SunCor had total assets of about $437 million. See
Note 6 of Notes to the Consolidated Financial Statements in Item 8 for
information regarding SunCor's long-term debt. SunCor intends to continue its
focus on real estate development in homebuilding and the development of
residential, commercial, and industrial projects.
11
BUSINESS OF EL DORADO DEVELOPMENT COMPANY
El Dorado was incorporated in 1983 under the laws of the State of Arizona
and is engaged principally in the business of making equity investments in other
companies. El Dorado's short-term goal is to convert its venture capital
portfolio to cash as quickly and as advantageously as possible. On a long-term
basis, we may use El Dorado, when appropriate, as our subsidiary for new
ventures that are strategic to our principal business of generating,
distributing, and marketing electricity. El Dorado's offices are located at 400
East Van Buren Street, Suite 800, Phoenix, Arizona 85004 (telephone
602-379-2589).
At December 31, 1999, El Dorado had an investment in a venture capital
partnership at a carrying amount of $21.3 million. In addition, El Dorado had a
54% interest in a privately held company and limited partnership interests in
two professional sports teams.
For the past three years, El Dorado's net income was: $11.5 million in
1999, $4.5 million in 1998, and $8.2 million in 1997. At December 31, 1999, El
Dorado had total assets of $36.6 million.
BUSINESS OF APS ENERGY SERVICES COMPANY, INC.
APS Energy Services was incorporated in 1998 under the laws of the State of
Arizona and is engaged principally in the business of selling unregulated power
and related services. APS Energy Services' principal offices are located at 400
East Van Buren Street, Station 8103, Phoenix, Arizona 85004 (telephone (602)
250-5000).
BUSINESS OF PINNACLE WEST ENERGY CORPORATION
Pinnacle West Energy Corporation was incorporated in 1999 under the laws of
the State of Arizona and is engaged principally in the business of the
development and production of wholesale energy. Pinnacle West Energy is the
subsidiary through which we intend to conduct our future unregulated generation
operations. Pinnacle West Energy's principal offices are located at 400 North
Fifth Street, Station 8987, Phoenix, Arizona 85004 (telephone (602) 250-4145).
Pinnacle West Energy's capital expenditures in 1999 were $21 million.
Projected capital expenditures are $152 million in 2000; $240 million in 2001;
and $245 million in 2002.
12
ITEM 2. PROPERTIES
ACCREDITED CAPACITY
APS' present generating facilities have an accredited capacity as follows:
Capacity(kW)
------------
Coal:
Units 1, 2, and 3 at Four Corners ............................ 560,000
15% owned Units 4 and 5 at Four Corners ...................... 222,000
Units 1, 2, and 3 at Cholla Plant ............................ 615,000
14% owned Units 1, 2, and 3 at the Navajo Plant .............. 315,000
---------
1,712,000
---------
Gas or Oil:
Two steam units at Ocotillo and two steam units at Saguaro.... 435,000(1)
Eleven combustion turbine units .............................. 493,000
Three combined cycle units ................................... 255,000
---------
1,183,000
---------
Nuclear:
29.1% owned or leased Units 1, 2, and 3 at Palo Verde ........ 1,086,300
---------
Other .......................................................... 5,600
---------
Total ........................................................ 3,986,900
=========
----------
(1) West Phoenix steam units (108,300 kW) are currently mothballed.
----------
RESERVE MARGIN
APS' 1999 peak one-hour demand on its electric system was recorded on
August 24, 1999 at 4,934,700 kW, compared to the 1998 peak of 5,027,000 kW
recorded on July 16. Taking into account additional capacity then available to
APS under traditional long-term purchase power contracts as well as APS' own
generating capacity, APS' capability of meeting system demand on August 24, 1999
amounted to 4,754,600 kW, for an installed reserve margin of (4.4%). The power
actually available to APS from its resources fluctuates from time to time due in
part to planned outages and technical problems. The available capacity from
sources actually operable at the time of the 1999 peak amounted to 3,587,100 kW,
for a margin of (27.5%). Firm purchases, including short-term seasonal
purchases, totaling 1,643,000 kW were in place at the time of the peak ensuring
the ability to meet the load requirement, with an actual reserve margin of 9.1%.
13
PLANT SITES LEASED FROM NAVAJO NATION
LEASES NGS and Four Corners are located on land held under easements from
the federal government and also under leases from the Navajo Nation. These are
long term agreements with options to extend, and we do not believe that the risk
with respect to enforcement of these easements and leases is material. The
majority of coal contracted for use in these plants and certain associated
transmission lines are also located on Indian reservations. See "Generating Fuel
and Purchased Power -- Coal Supply" in Item 1.
TAX AND ROYALTY See "Generating Fuel and Purchased Power -- Coal Supply" in
Item 1 for a discussion of changes in the amount of royalty payments and
expiration of tax waivers under the NGS and Four Corners leases.
PALO VERDE NUCLEAR GENERATING STATION
PALO VERDE LEASES
See Note 10 of Notes to Consolidated Financial Statements in Item 8 for a
discussion of three sale and leaseback transactions related to Palo Verde Unit
2.
REGULATORY
Operation of each of the three Palo Verde units requires an operating
license from the NRC. The NRC issued full power operating licenses for Unit 1 in
June 1985, Unit 2 in April 1986, and Unit 3 in November 1987. The full power
operating licenses, each valid for a period of approximately 40 years, authorize
APS, as operating agent for Palo Verde, to operate the three Palo Verde units at
full power.
NUCLEAR DECOMMISSIONING COSTS
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. APS currently relies on the
external sinking fund mechanism to meet the NRC financial assurance requirements
for its interests in Palo Verde Units 1, 2, and 3. The decommissioning costs of
Palo Verde Units 1, 2, and 3 are currently included in ACC jurisdictional rates.
ACC rules regarding the introduction of retail electric competition in Arizona
(see Note 3 of Notes to Consolidated Financial Statements) currently provide
that decommissioning costs would be recovered through a non-bypassable "system
benefits" charge, which would allow APS to maintain its external sinking fund
mechanism. See Note 2 of Notes to Consolidated Financial Statements in Item 8
for additional information about nuclear decommissioning costs.
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the insurance
maintained by the Palo Verde participants, including APS, for Palo Verde.
OTHER INFORMATION REGARDING PROPERTIES
See "Environmental Matters" and "Water Supply" in Item 1 with respect to
matters having possible impact on the operation of certain of APS' power plants.
14
See "Construction Program" in Item 1 and "Financial Review -- Capital
Needs and Resources" in Item 7 for a discussion of APS' construction plans.
See Notes 6, 10, and 11 of Notes to Consolidated Financial Statements in
Item 8 with respect to property of the Company not held in fee or held subject
to any major encumbrance.
INFORMATION REGARDING PROPERTIES OF SUNCOR
See "Business of SunCor Development Company" for information regarding
SunCor's properties.
15
[MAP PAGE]
In accordance with Item 304 of Regulation S-T of the Securities Exchange
Act of 1934, APS' Service Territory map contained in this Form 10-K is a map of
the State of Arizona showing APS' service area, the location of its major power
plants and principal transmission lines, and the location of transmission lines
operated by APS for others. The major power plants shown on such map are the
Navajo Generating Station located in Coconino County, Arizona; the Four Corners
Power Plant located near Farmington, New Mexico; the Cholla Power Plant, located
in Navajo County, Arizona; the Yucca Power Plant, located near Yuma, Arizona;
and the Palo Verde Nuclear Generating Station, located about 55 miles west of
Phoenix, Arizona (each of which plants is reflected on such map as being jointly
owned with other utilities), as well as the Ocotillo Power Plant and West
Phoenix Power Plant, each located near Phoenix, Arizona, and the Saguaro Power
Plant, located near Tucson, Arizona. APS' major transmission lines shown on such
map are reflected as running between the power plants named above and certain
major cities in the State of Arizona. The transmission lines operated for others
shown on such map are reflected as running from the Four Corners Plant through a
portion of northern Arizona to the California border.
16
ITEM 3. LEGAL PROCEEDINGS
APS In June 1999, the Navajo Nation served Salt River Project with a
lawsuit naming Salt River Project, several Peabody Coal Company entities
("Peabody"), Southern California Edison Company and other defendants, and citing
various claims in connection with the renegotiations of the coal royalty and
lease agreements under which Peabody mines coal for the Navajo and Mohave
Generating Stations. THE NAVAJO NATION V. PEABODY HOLDING COMPANY, INC., ET AL.,
United States District Court for the District of Columbia, CA-99-0469-EGS. APS
is a 14% owner of Navajo Generating Station, which Salt River Project operates.
The suit alleges, among other things, that the defendants obtained a favorable
coal royalty rate by improperly influencing the outcome of a federal
administrative process under which the royalty rate was to be adjusted. The suit
seeks $600 million in damages, treble damages, punitive damages of not less than
$1 billion, and the ejection of defendants "from all possessory interests and
Navajo Tribal lands" arising out of the [primary coal lease]. Salt River Project
has advised APS that it denies all charges and will vigorously defend itself.
Because the litigation is in preliminary stages, APS cannot currently predict
the outcome of this matter.
See "Environmental Matters" and "Water Supply" in Item 1 in regard to
pending or threatened litigation and other disputes. See "Regulatory Matters" in
Note 3 of Notes to Consolidated Financial Statements in Item 8 for a discussion
of competition and the rules regarding the introduction of retail electric
competition in Arizona and related litigation. In December 1999, APS filed a
lawsuit to protect its legal rights regarding the rules, and in the complaint
APS asked the Court for (i) a judgment vacating the retail electric competition
rules, (ii) a declaratory judgment that the rules are unlawful because, among
other things, they were entered into without proper legal authorization, and
(iii) a permanent injunction barring the ACC from enforcing or implementing the
rules and from promulgating any other regulations without lawful authority.
ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION COMMISSION, CV99-21907. On
August 28, 1998, APS filed two lawsuits to protect its 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.
17
SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers are as follows:
Name Age at March 1, 2000 Position(s) at March 1, 2000
---- -------------------- ----------------------------
Robert S. Aiken 43 Vice President, Federal Affairs
John G. Bohon 54 Vice President, Corporate Services &
Human Resources
Jack E. Davis 53 President, APS Energy Delivery &
Sales
Armando B. Flores 56 Executive Vice President, Corporate
Business Services
Edward Z. Fox 46 Vice President, Communications,
Environment & Safety
Chris N. Froggatt 42 Vice President & Controller
Barbara M. Gomez 45 Treasurer
James L. Kunkel 62 Vice President
James M. Levine 50 Executive Vice President, APS
Generation
Nancy C. Loftin 46 Vice President & General Counsel
Michael V. Palmeri 41 Vice President, Finance
William J. Post 49 President and Chief Executive
Officer(1)
Martin L. Shultz 55 Vice President, Government Affairs
Richard Snell 69 Chairman of the Board of
Directors (1)
William L. Stewart 56 President, APS Generation
Faye Widenmann 51 Vice President and Secretary
----------
(1) member of the Board of Directors
The executive officers of the Company are elected no less often than
annually and may be removed by the Board of Directors at any time. The terms
served by the named officers in their current positions and the principal
occupations (in addition to those stated in the table) of such officers for the
past five years have been as follows:
Mr. Aiken was elected to his present position in July 1999. Prior to that
time he was the Company's Manager, Federal Affairs (November 1986-July 1999).
Mr. Bohon was elected to his present position in July 1999. Prior to that
time he was Vice President, Corporate Services and Human Resources of APS
(October 1998-July 1999), Vice President, Procurement of APS (April 1997-October
1998) and Director, Corporate Services of APS (December 1989-April 1997).
Mr. Davis was elected to his present position in October 1998. Prior to
that time he was Executive Vice President, Commercial Operations of APS
(September 1996-October 1998) and Vice President, Generation and Transmission of
APS (June 1993-September 1996). Mr. Davis is a director of APS.
Mr. Flores was elected to his present position in July 1999. Prior to that
time, he was Executive Vice President, Corporate Business Services of APS
(October 1998-July 1999), Senior Vice President, Corporate Business Services of
APS (September 1996-October 1998) and Vice President, Human Resources of APS
(December 1991-September 1996).
Mr. Fox was elected to his present position in July 1999. Prior to that
time he was Vice President, Environmental/Health/Safety and New Technology
Ventures of APS (October 1995-July 1999), Director, Arizona Department of
Environmental Quality and Chairman, Wastewater Management Authority of Arizona
(July 1991-September 1995).
18
Mr. Froggatt was elected to his present position in July 1999. Prior to
that time he was Controller of APS (July 1997-July 1999) and Director,
Accounting Services of APS (December 1992-July 1997).
Ms. Gomez was elected to her present position in August 1999. Prior to that
time, she was Manager, Treasury Operations of APS (1997-1999) and Manager,
Financial Planning of APS (1994-1997). She was also elected Treasurer of APS in
October 1999.
Mr. Kunkel was elected Vice President effective December 15, 1997. Prior to
December 1997, he was a partner with the accounting firm PricewaterhouseCoopers,
successor to Coopers & Lybrand, in both their Los Angeles and Phoenix offices.
Mr. Kunkel is also a director of Aztar Corporation.
Mr. Levine was elected to his present position in July 1999. Prior to that
time he was Senior Vice President, Nuclear Generation of APS (September
1996-July 1999) and Vice President, Nuclear Production of APS (September
1989-September 1996).
Ms. Loftin was elected to her present position in July 1999. She was
elected to the positions of Vice President and Chief Legal Counsel of APS in
September 1996. Prior to that time, she was Secretary of APS (since April 1987)
and Corporate Counsel of APS (since February 1989). She was also elected Vice
President and General Counsel of APS in July 1999.
Mr. Palmeri was elected to his present position in August 1999. Prior to
that time he was Treasurer of APS and Pinnacle West (July 1997-September 1999),
Assistant Treasurer of Pinnacle West (February 1994-July 1997) and Manager of
Finance of Pinnacle West (June 1990-February 1994). He also was elected Vice
President, Finance of APS in October 1999.
Mr. Post was elected President effective August, 1999, and Chief Executive
Officer effective February 1999. He has served as an officer of the Company
since 1995 in the following capacities: from August 1999 to present as President
and Chief Executive Officer; from February 1999 to August 1999 as Chief
Executive Officer; from February 1997 to February 1999 as President; and from
June 1995 to February 1997 as Executive Vice President. He was also elected
President and Chief Executive Officer of APS in February 1997. In October 1998,
he resigned as President and maintained the position of Chief Executive Officer
of APS. He was APS' Chief Operating Officer (September 1994-February 1997), as
well as a Senior Vice President of APS since June 1993. Mr. Post is also a
director of APS and Blue Cross-Blue Shield of Arizona.
Mr. Shultz was elected to his current position in July 1999. Prior to that
time he held the position of Director of Government Relations for APS (1988-July
1999).
Mr. Snell has been Chairman of the Board of the Company and Chairman of the
Board of APS since February 1990. Until February 1999, he was also Chief
Executive Officer of the Company, and until February 1997, he was President of
the Company. Mr. Snell is also a director of Aztar Corporation and Central
Newspapers, Inc.
Mr. Stewart was elected to his present position in October 1998. Prior to
that time he was Executive Vice President, Generation of APS (September
1996-October 1998), and Executive Vice President, Nuclear of APS (May
1994-September 1996). Mr. Stewart is a director of APS.
Ms. Widenmann was elected to her current position in July 1999. Prior to
that time, she held the position of Secretary (since 1985) and Vice President of
Corporate Relations and Administration (since November 1986). She was also
elected Vice President and Secretary of APS in July 1999.
19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
STOCK AND RELATED SECURITY HOLDER MATTERS
Our common stock is publicly held and is traded on the New York and Pacific
Stock Exchanges. At the close of business on March 27, 2000, our common stock
was held of record by approximately 42,645 shareholders.
The chart below sets forth the common stock price ranges on the composite
tape, as reported in the Wall Street Journal for 1999 and 1998. The chart also
sets forth the dividends declared during each of the four quarters for 1999 and
1998.
COMMON STOCK PRICE RANGES AND DIVIDENDS
HIGH LOW DIVIDEND PER SHARE(a)
---- --- ---------------------
1999
1st Quarter 43 3/8 35 15/16 $ .325
2nd Quarter 42 15/16 36 1/4 .650
3rd Quarter 41 5/16 34 11/16 --
4th Quarter 38 1/8 30 3/16 .350
1998
1st Quarter 45 39 3/8 $ .300
2nd Quarter 46 3/16 42 .600
3rd Quarter 45 9/16 40 1/16 --
4th Quarter 49 1/4 41 5/8 .325
----------
(a) Dividends for the third quarter of 1999 and 1998 were declared in June.
20
ITEM 6. SELECTED CONSOLIDATED DATA
(dollars in thousands, except per share amounts)
[Enlarge/Download Table]
1999 1998 1997 1996 1995
----------- ----------- ----------- ----------- -----------
OPERATING RESULTS
Operating revenues
Electric $ 2,293,184 $ 2,006,398 $ 1,878,553 $ 1,718,272 $ 1,614,952
Real estate 130,169 124,188 116,473 99,488 54,846
Income from continuing operations $ 269,772 $ 242,892 $ 235,856 $ 211,059 (a) $ 199,608
Discontinued operations 38,000 (d) -- -- (9,539)(b) --
Extraordinary charge - net of income tax (139,885)(e) -- -- (20,340)(c) (11,571)(c)
----------- ----------- ----------- ----------- -----------
Net income $ 167,887 $ 242,892 $ 235,856 $ 181,180 $ 188,037
=========== =========== =========== =========== ===========
Common Stock Data
Book value per share - year-end $ 26.00 $ 25.50 $ 23.90 $ 22.51 $ 21.49
Earnings (loss) per average common
share outstanding
Continuing operations - basic $ 3.18 $ 2.87 $ 2.76 $ 2.41 (a) $ 2.28
Discontinued operations 0.45 -- -- (0.11) --
Extraordinary charge (1.65) -- -- (0.23) (0.13)
----------- ----------- ----------- ----------- -----------
Net income - basic $ 1.98 $ 2.87 $ 2.76 $ 2.07 $ 2.15
=========== =========== =========== =========== ===========
Continuing operations - diluted $ 3.17 $ 2.85 $ 2.74 $ 2.40 (a) $ 2.27
Net income - diluted $ 1.97 $ 2.85 $ 2.74 $ 2.06 $ 2.14
Dividends declared per share $ 1.325 $ 1.225 $ 1.125 $ 1.025 $ 0.925
Indicated annual dividend rate - year-end $ 1.40 $ 1.30 $ 1.20 $ 1.10 $ 1.00
Average common shares outstanding - basic 84,717,135 84,774,218 85,502,909 87,441,515 87,419,300
Average common shares outstanding - diluted 85,008,527 85,345,946 86,022,709 88,021,920 87,884,226
TOTAL ASSETS $ 6,608,506 $ 6,824,546 $ 6,850,417 $ 6,989,289 $ 6,997,052
----------- ----------- ----------- ----------- -----------
LIABILITIES AND EQUITY
Long-term debt less current maturities $ 2,206,052 $ 2,048,961 $ 2,244,248 $ 2,372,113 $ 2,510,709
Other liabilities 2,196,721 2,516,993 2,407,572 2,428,180 2,336,695
----------- ----------- ----------- ----------- -----------
4,402,773 4,565,954 4,651,820 4,800,293 4,847,404
Minority interests
Non-redeemable preferred stock of APS -- 85,840 142,051 165,673 193,561
Redeemable preferred stock of APS -- 9,401 29,110 53,000 75,000
Common stock equity 2,205,733 2,163,351 2,027,436 1,970,323 1,881,087
----------- ----------- ----------- ----------- -----------
Total liabilities and equity $ 6,608,506 $ 6,824,546 $ 6,850,417 $ 6,989,289 $ 6,997,052
=========== =========== =========== =========== ===========
(a) Includes an after-tax charge of $18.9 million ($0.22 per share) for a
voluntary severance program and about $12 million ($0.13 per share) of
income tax benefits related to capital loss carryforwards.
(b) Charges, net of tax, associated with the settlement of a legal matter
related to MeraBank, A Federal Savings Bank.
(c) Charges associated with the repayment or refinancing of the parent
company's high-coupon debt.
(d) Tax benefit stemming from the resolution of income tax matters related to
MeraBank, A Federal Savings Bank.
(e) Charges associated with a regulatory disallowance.
21
(dollars in thousands, except per share amounts)
[Enlarge/Download Table]
1999 1998 1997 1996 1995
----------- ----------- ----------- ----------- -----------
ELECTRIC OPERATING REVENUES
Residential $ 805,173 $ 766,378 $ 746,937 $ 721,877 $ 669,762
Commercial 733,038 699,016 687,988 678,130 653,425
Industrial 159,329 172,296 164,696 162,324 156,501
Irrigation 7,374 7,288 8,706 9,448 9,596
Other 11,708 10,644 11,842 13,078 12,631
----------- ----------- ----------- ----------- -----------
Total retail 1,716,622 1,655,622 1,620,169 1,584,857 1,501,915
Sales for resale 506,877 300,698 226,828 98,560 86,510
Transmission for others 11,348 11,058 10,295 10,240 9,390
Miscellaneous services 58,337 39,020 21,261 24,615 17,137
----------- ----------- ----------- ----------- -----------
Net electric operating revenues $ 2,293,184 $ 2,006,398 $ 1,878,553 $ 1,718,272 $ 1,614,952
=========== =========== =========== =========== ===========
ELECTRIC SALES (MWh)
Residential 8,774,822 8,310,689 7,970,309 7,541,440 6,848,905
Commercial 9,543,853 8,697,397 8,524,882 8,233,762 7,768,289
Industrial 2,561,349 3,279,430 3,123,283 3,039,357 2,933,459
Irrigation 99,669 84,640 112,363 121,775 119,580
Other 94,877 90,927 86,090 84,362 78,478
----------- ----------- ----------- ----------- -----------
Total retail 21,074,570 20,463,083 19,816,927 19,020,696 17,748,711
Sales for resale 15,693,834 10,317,391 9,233,573 3,367,234 2,720,704
----------- ----------- ----------- ----------- -----------
Total electric sales 36,768,404 30,780,474 29,050,500 22,387,930 20,469,415
=========== =========== =========== =========== ===========
ELECTRIC CUSTOMERS - END OF YEAR
Residential 735,359 708,215 680,478 654,602 625,352
Commercial 86,707 83,506 81,246 78,178 75,105
Industrial 3,183 3,084 3,192 3,055 2,913
Irrigation 754 710 764 841 837
Other 932 895 851 828 786
----------- ----------- ----------- ----------- -----------
Total retail 826,935 796,410 766,531 737,504 704,993
Sales for resale 73 67 50 48 39
----------- ----------- ----------- ----------- -----------
Total electric customers 827,008 796,477 766,581 737,552 705,032
=========== =========== =========== =========== ===========
See "Financial Review" on pages 22-29 for a discussion of certain information in
the table above.
QUARTERLY STOCK PRICES AND DIVIDENDS STOCK SYMBOL: PNW
Dividends
Per
1999 High Low Close Share(a)
---- ---- --- ----- --------
1st Quarter 43 3/8 35 15/16 36 3/8 $0.325
2nd Quarter 42 15/16 36 1/4 40 1/4 $0.650
3rd Quarter 41 5/16 34 11/16 36 3/8 $ --
4th Quarter 38 1/8 30 3/16 30 9/16 $0.350
Dividends
Per
1998 High Low Close Share(a)
---- ---- --- ----- --------
1st Quarter 45 39 3/8 44 7/16 $0.300
2nd Quarter 46 3/16 42 45 $0.600
3rd Quarter 45 9/16 40 1/16 44 13/16 $ --
4th Quarter 49 1/4 41 5/8 42 3/8 $0.325
(a) Dividends for the 3rd quarter of 1999 and 1998 were declared in June.
22
ITEM 7. FINANCIAL REVIEW
In this section, we explain the results of operations, general financial
condition, and outlook for Pinnacle West and our subsidiaries: APS, SunCor, El
Dorado, APS Energy Services, and Pinnacle West Energy, including:
* the changes in our earnings from 1998 to 1999 and from 1997 to 1998
* the factors impacting our business, including competition and electric
industry restructuring
* the effects of regulatory agreements on our results and outlook
* our capital needs and resources - for APS and our other operations, and
* our management of market risks.
APS, our major subsidiary and Arizona's largest electric utility, with
approximately 827,000 customers, provides wholesale and retail electric service
to the entire state with the exception of Tucson and about one-half of the
Phoenix area. APS also generates, sells, and delivers electricity and
energy-related products and services to wholesale and retail customers in the
western United States. SunCor is a developer of residential, commercial, and
industrial projects on some 15,000 acres in Arizona, New Mexico, and Utah. El
Dorado is a venture capital firm with a diversified portfolio. APS Energy
Services was formed in 1998 and sells energy and energy-related products and
services in competitive retail markets in the western United States. Pinnacle
West Energy, which was formed in 1999, is the subsidiary through which we intend
to conduct our future unregulated generation operations.
Throughout this Financial Review, we refer to specific "Notes" in the Notes to
Consolidated Financial Statements that begin on page 37. These Notes add further
details to the discussion.
RESULTS OF OPERATIONS
1999 COMPARED WITH 1998
Our 1999 consolidated net income was $168 million compared with $243 million in
1998. The following is a summary:
1999 1998
---- ----
(millions of dollars)
APS $ 267 $ 246
APS Energy Services (9) --
SunCor 6 45
El Dorado 11 5
Parent Company (5) (53)
----- -----
Income from Continuing Operations 270 243
Income Tax Benefit from
Discontinued Operations 38 --
Extraordinary Charge --
Net of Income Taxes of $94 (140) --
----- -----
Net Income $ 168 $ 243
===== =====
The income tax benefit from discontinued operations resulted from resolution of
tax issues related to a former subsidiary, MeraBank, A Federal Savings Bank.
The extraordinary charge related to a regulatory disallowance which resulted
from APS' comprehensive Settlement Agreement that was approved by the Arizona
Corporation Commission (ACC) in September 1999. See "Regulatory Agreements"
below and Notes 1 and 3 for additional information about the regulatory
disallowance and the Settlement Agreement.
APS' earnings before extraordinary charge increased
$21 million - a 9% increase - over 1998 earnings primarily because of increases
in the number of customers and in the average amount of electricity used by
customers and lower financing costs. These positive impacts more than offset the
effects of retail electricity price reductions and higher utility operations and
maintenance expense. See Note 3 for additional information about the price
reductions.
In 1999, electric operating revenues increased $287 million primarily because
of:
* increased power marketing and trading revenues ($219 million)
* increases in the number of customers and the average amount of electricity
used by customers ($81 million) and
* miscellaneous factors ($9 million).
23
As mentioned above, these positive factors were partially offset by the effects
of reductions in retail prices ($22 million).
The increase in power marketing revenues resulted from higher prices and
increased activity in western U.S. bulk power markets. The revenues were
accompanied by an increase in purchased power expenses. Although these
activities contributed positively to earnings in both periods, the contribution
in 1999 was lower than in 1998.
APS' utility operations and maintenance expenses increased $18 million primarily
because of $19 million of non-recurring items recorded in 1999, including a
provision for certain environmental costs. Other increases primarily related to
customer growth were more than offset by lower employee benefit costs and
movement of certain marketing functions to APS Energy Services in early 1999.
APS Energy Services recorded a loss of $9 million in 1999,
its first year of operations. Income tax benefits related to the loss are
recorded at the parent company. In 1999, the loss consisted primarily of
operating expenses, which were partially offset by revenues as new markets began
to open for retail electricity competition.
Our real estate subsidiary, SunCor Development, reported earnings of $6 million
in 1999 compared with $45 million in 1998. SunCor's 1998 earnings included $37
million related to the recording of a deferred tax asset by SunCor in connection
with its intercompany tax sharing agreement with Pinnacle West. Income taxes
related to SunCor's pretax income are now being recorded by SunCor. Prior to
1998, the income tax effects related to SunCor's income and losses were not
recorded at SunCor due to net operating losses. On an after-tax basis and
excluding the effects of the deferred tax asset, SunCor's contributions to
consolidated earnings were $6 million in 1999 and $5 million in 1998 - a
significant percentage increase in net income from operations for the real
estate subsidiary.
El Dorado Investment Company, our investment subsidiary, reported earnings of
$11 million in 1999 compared with $5 million in 1998. The improvement related
primarily to the increased value of El Dorado's investment in a
technology-related venture capital partnership; this investment is revalued on a
quarterly basis.
1998 COMPARED WITH 1997
Our 1998 consolidated net income was $243 million compared with $236 million in
1997 - a 3.0% increase. The following is a summary:
1998 1997
---- ----
(millions of dollars)
APS $246 $ 239
SunCor 45 5
El Dorado 5 8
Parent Company (53) (16)
---- -----
Net Income $243 $ 236
==== =====
APS' 1998 earnings increased $7 million - a 3% increase over 1997 earnings
primarily because of an increase in customers, expanded power marketing and
trading activities, and lower financing costs. In the comparison, these positive
factors more than offset the effects of milder weather, the prior year's
benefits of the two fuel-related settlements recorded in 1997, and retail price
reductions. See Note 3 for additional information about the price reductions.
In 1998, electric operating revenues increased $128 million primarily because
of:
* increased power marketing and trading revenues ($94 million)
* increases in the number of customers and the average amount of electricity
used by customers ($77 million) and
* miscellaneous factors ($8 million).
As mentioned above, these positive factors were partially offset by the effects
of milder weather ($33 million) and reductions in retail prices ($18 million).
24
The increase in power marketing revenues resulted from higher prices and
increased activity in western U.S. bulk power markets. The revenue increases
were accompanied by an increase in purchased power expenses. These activities
contributed positively to earnings in both periods; the contribution in 1998 was
higher than in 1997.
The two fuel-related settlements increased 1997 pretax earnings by about $21
million. The income statement reflects these settlements as reductions in fuel
expense and as other income.
Operations and maintenance expense increased $14 million primarily because of
customer growth, initiatives related to competition, and expansion of our power
marketing and trading function.
Depreciation and amortization expense increased $11 million because APS had more
plant in service.
Financing costs decreased by $16 million primarily because of lower amounts of
outstanding debt and APS preferred stock.
Before the effects of recording deferred taxes under its tax sharing agreement,
the earnings contribution from our real estate subsidiary, SunCor Development,
increased $3 million as a result of an increase in land sales. SunCor's
stand-alone net income in 1998 was $45 million, of which $37 million represents
income related to the recognition of a deferred tax asset. The deferred tax
asset relates to net operating losses and book/tax basis differences. SunCor is
expected to realize these benefits in subsequent periods pursuant to an inter-
company tax allocation agreement. On a consolidated basis, Pinnacle West had
already recognized the income tax benefits; therefore, there was no impact on
consolidated net income in 1998.
The contribution from El Dorado, our investment subsidiary, decreased $3 million
as a result of a decrease in investment sales.
REGULATORY AGREEMENTS
Regulatory agreements approved by the ACC affect the results of APS' operations.
The following discussion focuses on three agreements approved by the ACC: the
1999 Settlement Agreement to implement retail electric competition; a 1996
agreement that accelerated the amortization of APS' regulatory assets; and a
1994 settlement that included accelerated amortization of APS' deferred
investment tax credits (ITCs).
As part of the 1999 Settlement Agreement, APS reduced rates for standard offer
service for customers with loads less than 3 megawatts in a series of annual
retail electric price reductions of 1.5% beginning July 1, 1999 through July 1,
2003, for a total of 7.5%. The first reduction of approximately $24 million ($14
million after income taxes) included the July 1, 1999 retail price decrease
related to the 1996 regulatory agreement (see below). For customers having loads
3 megawatts or greater, standard offer rates will be reduced in annual
increments that total 5% through 2002.
Also, under the Settlement Agreement a regulatory disallowance removed $234
million before income taxes ($183 million net present value) from ongoing
regulatory cash flows and was recorded as a net reduction of regulatory assets.
This reduction ($140 million after income taxes) was reported as an
extraordinary charge on the income statement. Before the ACC approved the 1999
Settlement Agreement, APS was recovering substantially all of its regulatory
assets through accelerated amortization over an eight-year period that would
have ended June 30, 2004 under the 1996 agreement. For more details, see Note 1.
The regulatory assets to be recovered under this Settlement Agreement are now
being amortized as follows:
(millions of dollars)
1/1-6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
25
Also, as part of the 1996 regulatory agreement, APS reduced its retail
electricity prices by 3.4% effective July 1, 1996. This reduction decreased
annual revenue by about $49 million annually ($29 million after income taxes).
APS also agreed to share future cost savings with its customers during the term
of the agreement, which resulted in the following additional retail price
reductions:
* $18 million annually ($11 million after income taxes), or 1.2%, effective
July 1, 1997,
* $17 million annually ($10 million after income taxes), or 1.1%, effective
July 1, 1998, and
* $11 million annually ($7 million after income taxes), or 0.7%, effective July
1, 1999, which was included in the July 1, 1999 1.5% price reduction under
the 1999 Settlement Agreement.
As part of the 1994 rate settlement, APS accelerated amortization of
substantially all deferred investment tax credits (ITCs) over a five-year period
that ended on December 31, 1999. The amortization of ITCs decreased annual
consolidated income tax expense by approximately $24 million. Beginning in 2000,
no further benefits will be reflected in income tax expense related to the
accelerated amortization of ITCs (see Note 4).
CAPITAL NEEDS AND RESOURCES
PINNACLE WEST (PARENT COMPANY)
During the past three years, our primary cash needs were for:
* dividends to our shareholders
* interest payments and
* optional and mandatory repayment of principal on our long-term debt.
In addition, as part of the 1996 agreement with the ACC, we invested $50 million
annually in APS for the years 1996 through 1999. The 1999 payment was the last
payment under the 1996 regulatory agreement (see Note 3). During 1997, we
repurchased $80 million of common stock, reducing our shares outstanding at
year-end 1997 by 2.7 million shares.
Our primary sources of cash are dividends from our subsidiaries. During 1999,
APS paid $170 million in dividends to the parent. In 1999, SunCor and El Dorado
declared dividends to the parent of $20 million and $10 million, respectively.
Combined dividends from SunCor and El Dorado are expected to be at least $25
million annually during the next several years; however, the aggregate amount of
those dividends depends somewhat on the status of the real estate and stock
markets (particularly the technology sector).
Our long-term debt at December 31, 1999 was $106 million compared to $92 million
at December 31, 1998. We have a $250 million line of credit, under which we had
$56 million of borrowings outstanding at December 31, 1999. We do not have any
principal debt repayment obligations until 2001.
APS
APS' capital requirements consist primarily of capital expenditures and optional
and mandatory redemptions of long-term debt. APS pays for its capital
requirements with cash from its operations and, to the extent necessary,
external financing.
As part of the 1996 regulatory agreement, APS received annual cash infusions
from Pinnacle West of $50 million from 1996 through 1999. During the period from
1997 through 1999, APS paid for all of its capital expenditures with cash from
its operations. APS expects to do so in 2000 through 2002 as well.
APS' capital expenditures in 1999 were $332 million. APS'
projected capital expenditures for the next three years are: $384 million in
2000; $342 million in 2001; and $334 million in 2002. These amounts include
about $30-$35 million each year for nuclear fuel. In general, most of the
projected capital expenditures are for:
* expanding transmission and distribution capabilities to meet customer growth
* upgrading existing utility property and
* environmental purposes.
26
During 1999, APS redeemed about $323 million of long-term debt and $96 million
of preferred stock, including premiums, with cash from operations and long- and
short-term debt. APS no longer has any outstanding preferred stock. Its
long-term debt redemption requirements and payment obligations on a capitalized
lease for the next three years are approximately: $115 million in 2000; $253
million in 2001; and $125 million in 2002. In addition, APS made optional
redemptions of about $89 million of long-term debt in January 2000. Based on
market conditions and optional call provisions, APS may make optional
redemptions of long-term debt from time to time.
As of December 31, 1999, APS had credit commitments from various banks totaling
about $350 million, which were available either to support the issuance of
commercial paper or to be used as bank borrowings. At the end of 1999, APS had
about $38 million of commercial paper and $50 million of long-term bank
borrowings outstanding.
In February 1999, APS issued $125 million of unsecured long-term debt and in
November 1999, APS issued $250 million of unsecured long-term debt.
Although provisions in APS' first mortgage bond indenture and ACC financing
orders establish maximum amounts of additional first mortgage bonds that APS may
issue, APS does not expect any of these provisions to limit its ability to meet
its capital requirements.
PINNACLE WEST ENERGY
We are currently planning, through Pinnacle West Energy, a 650-megawatt
expansion of our West Phoenix Power Plant, and the construction of a natural
gas-fired electric generating station of up to 2,120 megawatts near Palo Verde,
called Redhawk. Pinnacle West Energy's capital expenditures in 1999 were $21
million. Projected capital expenditures for these projects are $152 million in
2000; $240 million in 2001; and $245 million in 2002. We are also considering
additional expansion over the next several years, which may result in additional
expenditures. Pinnacle West Energy's capital expenditures will be funded with
debt proceeds, and with internally generated cash and debt proceeds from the
parent company. Assuming all approvals are granted, we expect to begin
construction at West Phoenix in the second quarter of 2000.
Pinnacle West Energy has signed a joint development agreement with Reliant
Energy Power Generation, Inc. (Reliant) covering construction and operation of
three new merchant plants. Pinnacle West Energy plans to contribute the first
two units (1,060 megawatts) of the Redhawk project to the joint agreement.
Construction is expected to start in the third quarter of 2000, with commercial
operation scheduled in the summer of 2002. Reliant plans to contribute two new
natural gas-fired projects (1,500 megawatts) in Nevada to the venture.
OTHER SUBSIDIARIES
During the past three years, SunCor and El Dorado each funded all of their cash
requirements with cash from operations and their own external financings.
SunCor's capital needs consist primarily of capital expenditures for land
development, retail and office building construction, and home construction. On
the basis of projects now under development, SunCor expects capital needs over
the next three years to be: $53 million in 2000; $43 million in 2001; and $51
million in 2002. Capital resources to meet these requirements include funds from
operations and SunCor's own external financings.
As of December 31, 1999, SunCor had a $100 million line of credit, under which
$94 million of borrowings were outstanding. SunCor has no principal debt
repayment requirements for 2000, $30 million for 2001, and $64 million for 2002.
27
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. See "Results of Operations
- Regulatory Agreements" and Note 3 for additional information about APS'
Settlement Agreement with the ACC related to the implementation of retail
electric competition, the ACC rules that provide a framework for the
introduction of retail electric competition in Arizona, and other competitive
developments, including an agreement with Salt River Project.
In May 1998, a law was enacted by the Arizona legislature to facilitate
implementation of retail electric competition in the state. Additionally,
legislation related to electric competition has been proposed in the United
States Congress. See Note 3 for a discussion of legislative developments.
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, or results of operations. As competition in the
electric industry continues to evolve, we will continue to evaluate strategies
and alternatives that will position us to compete effectively in a restructured
industry.
APS prepares its financial statements in accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to
reflect the impact of regulatory decisions in its financial statements. As a
result of the Settlement Agreement (see Note 3), APS discontinued the
application of SFAS No. 71 for its generation operations. This meant that the
generation assets were tested for impairment and the portion of the regulatory
assets deemed to be unrecoverable through ongoing regulated cash flows was
eliminated. APS determined that the generation assets were not impaired. A
regulatory disallowance ($140 million after income taxes) was reported as an
extraordinary charge on the income statement. See Note 1 for additional
information on regulatory accounting and Note 3 for additional information on
the Settlement Agreement.
YEAR 2000 READINESS DISCLOSURE
Some companies expected to face problems on January 1, 2000 in the case that
computer systems and equipment would not properly recognize calendar dates.
During 1997, APS had initiated a comprehensive company-wide Year 2000 program to
review and resolve all Year 2000 issues in mission critical systems in a timely
manner to ensure the reliability of electric service to its customers. We have
spent about $5 million to be Year 2000 ready. To date, we have not experienced
any material Year 2000 related problems, and we do not anticipate any in the
future.
ACCOUNTING MATTERS
We describe a new standard on accounting for derivatives in Note 2. The new
standard on derivatives is effective for us in 2001. We are currently evaluating
what impact it will have on our financial statements. Also, see Note 2 for a
description of a proposed standard on accounting for certain liabilities related
to closure or removal of long-lived assets.
28
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 (see Note 13). Our policy is to
manage interest rates through the use of a combination of fixed-rate and
floating-rate debt. The nuclear decommissioning fund also has risks associated
with changing market values of equity investments. Nuclear decommissioning costs
are recovered in regulated electricity prices.
The tables below present contractual balances of our long-term and short-term
debt at the expected maturity dates as well as the fair value of those
instruments on December 31, 1999 and December 31, 1998. The interest rates
presented in the table below represent the weighted average interest rates for
the years ended December 31, 1999 and December 31, 1998.
[Enlarge/Download Table]
EXPECTED MATURITY/PRINCIPAL REPAYMENT - DECEMBER 31, 1999 (thousands of dollars)
Short-Term Variable Long-Term Fixed Long-Term
---------------------- ------------------------- -------------------------
Interest Rates Amount Interest Rates Amount Interest Rates Amount
-------------- ------ -------------- ------ -------------- ------
2000 5.33% $38,300 10.25% $ 87 5.79% $ 114,711
2001 -- -- 7.00% 336,117 6.70% 27,488
2002 -- -- 8.47% 64,085 8.13% 125,000
2003 -- -- 5.51% 50,118 6.87% 25,000
2004 -- -- 10.25% 130 6.17% 205,000
Years thereafter -- -- 3.19% 479,727 7.87% 900,483
------- -------- ----------
Total $38,300 $930,264 $1,397,682
------- -------- ----------
Fair Value $38,300 $930,264 $1,366,968
======= ======== ==========
EXPECTED MATURITY/PRINCIPAL REPAYMENT - DECEMBER 31, 1998 (thousands of dollars)
Short-Term Variable Long-Term Fixed Long-Term
---------------------- ------------------------- -------------------------
Interest Rates Amount Interest Rates Amount Interest Rates Amount
-------------- ------ -------------- ------ -------------- ------
1999 5.88% $178,830 7.30% $ 3,268 7.24% $ 164,777
2000 -- -- 7.32% 25,756 5.79% 114,711
2001 -- -- 6.57% 93,472 6.70% 27,488
2002 -- -- 10.25% 119 8.13% 125,000
2003 -- -- 5.94% 125,131 6.87% 25,000
Years thereafter -- -- 3.43% 459,803 7.75% 1,058,963
-------- -------- ----------
Total $178,830 $707,549 $1,515,939
-------- -------- ----------
Fair Value $178,830 $707,549 $1,577,365
======== ======== ==========
29
COMMODITY PRICE RISK
APS is exposed to the impact of market fluctuations in the price and
distribution costs of electricity, natural gas, coal, and emissions allowances.
APS employs established procedures to manage risks associated with these market
fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options, and over-the-counter forwards, options, and
swaps. As part of its overall risk management program, APS enters into these
derivative transactions for trading and to hedge certain natural gas in storage
as well as purchases and sales of electricity, fuels, and emissions
allowances/credits.
As of December 31, 1999, a hypothetical adverse price movement of 10% in the
market price of APS' commodity derivative portfolio would decrease the fair
market value of these contracts by approximately $6 million. This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying position being hedged with the commodity derivative portfolio.
APS is exposed to credit losses in the event of non-performance or non-payment
by counterparties. APS uses a credit management process to assess and monitor
its financial exposure to counterparties. APS does not expect counterparty
defaults to materially impact its financial condition, results of operations, or
net cash flow.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; the ability of APS to successfully compete outside its 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; Year 2000
issues; the strength of the stock market (particularly the technology sector)
and the strength of the real estate market.
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 QUALITAVE DISCLOSURES ABOUT MARKET RISK
See "Financial Review" in Item 7 for a discussion of quantitative and qualitave
disclosures about market risk.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
Report of Management...................................................... 32
Independent Auditors' Report.............................................. 32
Consolidated Statements of Income for 1999, 1998, and 1997................ 33
Consolidated Balance Sheets as of December 31, 1999 and 1998 ............. 34
Consolidated Statements of Cash Flows for 1999, 1998 and 1997............. 36
Consolidated Statements of Retained Earnings for 1999, 1998 and 1997...... 37
Notes to Consolidated Financial Statements................................ 37
Financial Statement Schedule for 1999, 1998 and 1997
Schedule II - Valuation and Qualifying Accounts for 1999,
1998 and 1997............................................................ 58
See Note 14 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.
31
REPORT OF MANAGEMENT AND INDEPENDENT AUDITORS' REPORT
REPORT OF MANAGEMENT
The primary responsibility for the integrity of our financial information
rests with management, which has prepared the accompanying financial statements
and related information. Such information was prepared in accordance with
generally accepted accounting principles appropriate in the circumstances, and
based on management's best estimates and judgments. These financial statements
have been audited by independent auditors and their report is included.
Management maintains and relies upon systems of internal accounting
controls. A limiting factor in all systems of internal accounting control is
that the cost of the system should not exceed the benefits to be derived.
Management believes that our system provides the appropriate balance between
such costs and benefits.
Periodically the internal accounting control system is reviewed by both our
internal auditors and our independent auditors to test for compliance. Reports
issued by the internal auditors are released to management, and such reports or
summaries thereof are transmitted to the Audit Committee of the Board of
Directors and the independent auditors on a timely basis.
The Audit Committee, composed solely of outside directors, meets
periodically with the internal auditors and independent auditors (as well as
management) to review the work of each. The internal auditors and independent
auditors have free access to the Audit Committee, without management present, to
discuss the results of their audit work.
Management believes that our systems, policies and procedures provide
reasonable assurance that operations are conducted in conformity with the law
and with management's commitment to a high standard of business conduct.
William J. Post Chris N. Froggatt
President and Vice President and Controller
Chief Executive Officer
INDEPENDENT AUDITORS' REPORT
We have audited the accompanying consolidated balance sheets of Pinnacle
West Capital Corporation and its subsidiaries as of December 31, 1999 and 1998
and the related consolidated statements of income, retained earnings and cash
flows for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Pinnacle West Capital
Corporation and its subsidiaries at December 31, 1999 and 1998 and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1999 in conformity with generally accepted accounting
principles.
Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 18, 2000
32
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands, except per share amounts)
[Enlarge/Download Table]
Year Ended December 31,
-------------------------------------------
1999 1998 1997
----------- ----------- -----------
OPERATING REVENUES
Electric $ 2,293,184 $ 2,006,398 $ 1,878,553
Real estate 130,169 124,188 116,473
----------- ----------- -----------
Total 2,423,353 2,130,586 1,995,026
----------- ----------- -----------
OPERATING EXPENSES
Fuel and purchased power 796,109 545,297 443,571
Utility operations and maintenance 446,777 419,433 405,605
Real estate operations 119,516 115,331 111,628
Depreciation and amortization (Note 1) 385,568 379,679 368,285
Taxes other than income taxes 96,606 103,718 108,431
----------- ----------- -----------
Total 1,844,576 1,563,458 1,437,520
----------- ----------- -----------
OPERATING INCOME 578,777 567,128 557,506
----------- ----------- -----------
OTHER INCOME (EXPENSE)
Preferred stock dividend requirements of APS (1,016) (9,703) (12,803)
Net other income and expense 10,793 609 4,569
----------- ----------- -----------
Total 9,777 (9,094) (8,234)
----------- ----------- -----------
INCOME BEFORE INTEREST AND INCOME TAXES 588,554 558,034 549,272
----------- ----------- -----------
INTEREST expense
Interest charges 162,381 169,145 182,838
Capitalized interest (11,664) (18,596) (19,703)
----------- ----------- -----------
Total 150,717 150,549 163,135
----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 437,837 407,485 386,137
INCOME TAXES (NOTE 4) 168,065 164,593 150,281
----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS 269,772 242,892 235,856
Income tax benefit from discontinued operations 38,000 -- --
Extraordinary charge - net of income taxes of $94,115 (139,885) -- --
----------- ----------- -----------
NET INCOME $ 167,887 $ 242,892 $ 235,856
=========== =========== ===========
AVERAGE COMMON SHARES OUTSTANDING - BASIC 84,717,135 84,774,218 85,502,909
AVERAGE COMMON SHARES OUTSTANDING - DILUTED 85,008,527 85,345,946 86,022,709
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING
Continuing operations - basic $ 3.18 $ 2.87 $ 2.76
Net income - basic 1.98 2.87 2.76
Continuing operations - diluted 3.17 2.85 2.74
Net income - diluted 1.97 2.85 2.74
DIVIDENDS DECLARED PER SHARE $ 1.325 $ 1.225 $ 1.125
=========== =========== ===========
See Notes to Consolidated Financial Statements.
33
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
[Enlarge/Download Table]
December 31,
--------------------------
1999 1998
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 20,705 $ 20,538
Customer and other receivables - net 244,599 233,876
Accrued utility revenues 72,919 67,740
Materials and supplies (at average cost) 69,977 69,074
Fossil fuel (at average cost) 21,869 13,978
Deferred income taxes (Note 4) 8,163 3,999
Other current assets 60,562 47,594
---------- ----------
Total current assets 498,794 456,799
---------- ----------
INVESTMENTS AND OTHER ASSETS
Real estate investments - net (Note 6) 344,293 331,021
Other assets (Note 13) 267,458 236,562
---------- ----------
Total investments and other assets 611,751 567,583
---------- ----------
UTILITY PLANT (NOTES 6, 10 AND 11)
Electric plant in service and held for future use 7,546,314 7,265,604
Less accumulated depreciation and amortization 3,026,194 2,814,762
---------- ----------
Total 4,520,120 4,450,842
Construction work in progress 209,281 228,643
Nuclear fuel, net of amortization of $66,357 and $68,569 49,114 51,078
---------- ----------
Net utility plant 4,778,515 4,730,563
---------- ----------
DEFERRED DEBITS
Regulatory assets (Notes 3 and 4) 613,729 980,084
Other deferred debits 105,717 89,517
---------- ----------
Total deferred debits 719,446 1,069,601
---------- ----------
TOTAL ASSETS $6,608,506 $6,824,546
========== ==========
See Notes to Consolidated Financial Statements.
34
(thousands of dollars)
[Download Table]
December 31,
--------------------------
1999 1998
---------- ----------
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable $ 186,524 $ 155,800
Accrued taxes 70,510 62,520
Accrued interest 33,253 31,866
Short-term borrowings (Note 5) 38,300 178,830
Current maturities of long-term debt (Note 6) 114,798 168,045
Customer deposits 26,098 28,510
Other current liabilities 26,007 14,632
---------- ----------
Total current liabilities 495,490 640,203
---------- ----------
LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 6) 2,206,052 2,048,961
---------- ----------
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4) 1,183,855 1,343,536
Deferred investment tax credit (Note 4) 3,830 27,345
Unamortized gain - sale of utility plant 73,212 77,787
Other 440,334 428,122
---------- ----------
Total deferred credits and other 1,701,231 1,876,790
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTES 3, 12 AND 13)
MINORITY INTERESTS (NOTE 7)
Non-redeemable preferred stock of APS -- 85,840
---------- ----------
Redeemable preferred stock of APS -- 9,401
---------- ----------
COMMON STOCK EQUITY (NOTE 8)
Common stock, no par value; authorized 150,000,000
shares; issued and outstanding 84,824,947 at end
of 1999 and 1998 1,537,449 1,550,643
Retained earnings 668,284 612,708
---------- ----------
Total common stock equity 2,205,733 2,163,351
---------- ----------
TOTAL LIABILITIES AND EQUITY $6,608,506 $6,824,546
========== ==========
35
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
[Enlarge/Download Table]
Year Ended December 31,
-----------------------------------------
1999 1998 1997
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 269,772 $ 242,892 $ 235,856
Items not requiring cash
Depreciation and amortization 385,568 379,679 368,285
Nuclear fuel amortization 31,371 32,856 32,702
Deferred income taxes - net (17,413) 41,262 24,809
Deferred investment tax credit (23,514) (23,516) (23,518)
Other - net (12,476) 1,190 (3,854)
Changes in current assets and liabilities
Customer and other receivables - net (10,723) (50,369) (14,270)
Accrued utility revenues (5,179) (9,181) (3,089)
Materials, supplies and fossil fuel (8,794) (2,797) 7,793
Other current assets (12,968) (6,186) (109)
Accounts payable 28,193 34,386 (54,882)
Accrued taxes 12,591 (22,090) 2,197
Accrued interest 1,387 (1,108) (6,678)
Other current liabilities 15,047 (5,235) (23,087)
(Increase) decrease in land held (12,542) 33,405 33,010
Other - net (4,720) (39,350) 48,254
--------- --------- ---------
Net Cash Flow Provided By Operating Activities 635,600 605,838 623,419
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (343,448) (319,142) (307,876)
Capitalized interest (11,664) (18,596) (19,703)
Other - net (16,143) (2,144) (3,124)
--------- --------- ---------
Net Cash Flow Used For Investing Activities (371,255) (339,882) (330,703)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 607,791 148,229 146,013
Short-term borrowings - net (140,530) 48,080 113,850
Dividends paid on common stock (112,311) (103,849) (96,160)
Repurchase and retirement of common stock -- -- (79,997)
Repayment of long-term debt (510,693) (286,314) (325,526)
Redemption of preferred stock (96,499) (75,517) (47,201)
Other - net (11,936) (3,531) (2,897)
--------- --------- ---------
Net Cash Flow Used For Financing Activities (264,178) (272,902) (291,918)
--------- --------- ---------
NET CASH FLOW 167 (6,946) 798
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 20,538 27,484 26,686
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 20,705 $ 20,538 $ 27,484
========= ========= =========
See Notes to Consolidated Financial Statements.
36
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(thousands of dollars)
[Download Table]
Year Ended December 31,
-----------------------------------------
1999 1998 1997
--------- --------- ---------
Retained Earnings At Beginning of Year $ 612,708 $ 473,665 $ 333,969
Net Income 167,887 242,892 235,856
Common Stock Dividends (112,311) (103,849) (96,160)
--------- --------- ---------
Retained Earnings at End of Year $ 668,284 $ 612,708 $ 473,665
========= ========= =========
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION AND NATURE OF OPERATIONS
The consolidated financial statements include the accounts of Pinnacle West
and our subsidiaries: APS, SunCor, El Dorado, APS Energy Services, and Pinnacle
West Energy.
APS, our major subsidiary and Arizona's largest electric utility, with
approximately 827,000 customers, provides wholesale or retail electric service
to the entire state with the exception of Tucson and about one-half of the
Phoenix area. APS also generates, sells, and delivers electricity and
energy-related products and services to wholesale and retail customers in the
western United States. SunCor is a developer of residential, commercial, and
industrial projects on some 15,000 acres in Arizona, New Mexico, and Utah. El
Dorado is a venture capital firm with a diversified portfolio. APS Energy
Services was formed in 1998 and sells energy and energy-related products and
services in competitive retail markets in the western United States. Pinnacle
West Energy, which was formed in 1999, is the subsidiary through which we intend
to conduct our future unregulated generation operations.
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
APS is regulated by the ACC and the Federal Energy Regulatory Commission
(FERC). The accompanying financial statements reflect the ratemaking policies of
these commissions. For regulated operations, APS prepares its financial
statements in accordance with Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.
During 1997, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board (FASB) issued EITF 97-4. EITF 97-4 requires that SFAS
No. 71 be discontinued no later than when legislation is passed or a rate order
is issued that contains sufficient detail to determine its effect on the portion
of the business being deregulated, which could result in write-downs or
write-offs of physical and/or regulatory assets. Additionally, the EITF
determined that regulatory assets should not be written off if they are to be
recovered from a portion of the entity which continues to apply SFAS No. 71.
In September 1999, the APS Settlement Agreement was approved by the ACC
(see Note 3 for a discussion of the agreement). APS has discontinued the
application of SFAS No. 71 for its generation operations. This means that the
generation assets were tested for impairment and the portion of regulatory
assets deemed to be unrecoverable through ongoing regulated cash flows was
eliminated. APS determined that the generation assets were not impaired. A
regulatory disallowance removed $234 million pretax ($183 million net present
value) from ongoing regulatory cash flows and this was recorded as a net
reduction of regulatory assets. This reduction ($140 million after income taxes)
was reported as an extraordinary charge on the consolidated income statement.
Prior to the Settlement Agreement, under the 1996 regulatory agreement (see Note
3), the ACC accelerated the amortization of substantially all of APS' regulatory
assets to an eight-year period that would have ended June 30, 2004.
37
The regulatory assets to be recovered under this Settlement Agreement are
now being amortized as follows:
(millions of dollars)
1/1-6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
The majority of the regulatory assets relate to deferred income taxes (see
Note 4) and rate synchronization cost deferrals (see "Rate Synchronization Cost
Deferrals" in this Note).
The balance sheets include the amounts listed below for generation assets
not subject to SFAS No. 71:
(thousands of dollars)
December 31,
---------------------------
1999 1998
----------- -----------
Electric plant in service and held for future use $ 3,770,234 $ 3,680,482
Accumulated depreciation and amortization (1,817,589) (1,681,099)
Construction work in progress 87,819 107,324
Nuclear fuel, net of amortization 49,114 51,078
UTILITY PLANT AND DEPRECIATION
Utility plant is the term we use to describe the business property and
equipment that supports electric service. We report utility plant at its
original cost, which includes:
* material and labor
* contractor costs
* construction overhead costs (where applicable) and
* capitalized interest or an allowance for funds used during construction.
We charge retired utility plant, plus removal costs less salvage realized,
to accumulated depreciation. See Note 2 for information on a proposed accounting
standard that impacts accounting for removal costs.
We record depreciation on utility property on a straight-line basis. For
the years 1997 through 1999 the rates, as prescribed by our regulators, ranged
from a low of 1.51% to a high of 20%. The weighted-average rate for 1999 was
3.34%. APS depreciates non-utility property and equipment over the estimated
useful lives of the related assets, ranging from 3 to 50 years.
VENTURE CAPITAL INVESTMENTS
El Dorado has investments in venture capital partnerships that account for
their investments at fair value. Since El Dorado uses the equity method of
accounting for its partnership interests, it must record its share of realized
and unrealized gains and losses in net income.
CAPITALIZED INTEREST
Capitalized interest represents the cost of debt funds used to finance
construction of utility plant. Plant construction costs, including capitalized
interest, are expensed through depreciation when completed projects are placed
into commercial operation. Capitalized interest does not represent current cash
earnings. The rate used to calculate capitalized interest was a composite rate
of 6.65% for 1999, 6.88% for 1998, and 7.25% for 1997.
REVENUES
We record electric operating revenues on the accrual basis, which includes
estimated amounts for service rendered but unbilled at the end of each
accounting period.
RATE SYNCHRONIZATION COST DEFERRALS
As authorized by the ACC, operating costs (excluding fuel) and financing
costs of Palo Verde Units 2 and 3 were deferred from the commercial operation
dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the
units were included in a rate order (April 1988 for Unit 2 and December 1991 for
Unit 3). In accordance with the 1999 Settlement Agreement, APS is continuing to
accelerate the amortization of the deferrals over an eight-year period that will
end June 30, 2004. Amortization of the deferrals is included in "Depreciation
and Amortization" expense on the Statements of Income.
NUCLEAR FUEL
APS charges nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method that is based on
actual physical usage. APS divides the cost of the fuel by the estimated number
of thermal units that APS expects to produce with that fuel. APS then multiplies
that rate by the number of thermal units that it produces within the current
period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The United States Department of Energy (DOE) is responsible for
the permanent disposal of spent nuclear fuel, and it charges APS $0.001 per kwh
of nuclear generation. See Note 12 for information about spent nuclear fuel
disposal. In addition, Note 13 has information on nuclear decommissioning costs.
38
INCOME TAXES
We file our federal income tax return on a consolidated basis and we file
our state income tax returns on a consolidated or unitary basis. In accordance
with our intercompany tax sharing agreement, federal and state income taxes are
allocated to each subsidiary as though each subsidiary filed a separate income
tax return. Any difference between the aforementioned allocations and the
consolidated (and unitary) income tax liability is attributed to the parent
company.
REACQUIRED DEBT COSTS
For debt related to the regulated portion of APS' business, APS amortizes
those gains and losses incurred upon early retirement over the remaining life of
the debt. In accordance with the 1999 Settlement Agreement, APS is continuing to
accelerate reacquired debt costs over an eight-year period that will end June
30, 2004. The accelerated portion of the regulatory asset amortization is
included in "Depreciation and Amortization" expense in the Statements of Income.
STATEMENTS OF CASH FLOWS
We consider temporary cash investments and marketable securities to be cash
equivalents for purposes of reporting cash flows. During 1999, 1998, and 1997 we
paid interest, net of amounts capitalized, income taxes, and dividends on
preferred stock of APS as follows:
(millions of dollars)
Years Ended December 31,
-------------------------
1999 1998 1997
---- ---- ----
Interest paid $141 $144 $163
Income taxes paid 200 165 146
Dividends paid on preferred stock of APS 1 10 13
RECLASSIFICATIONS
We have reclassified certain prior year amounts for comparison purposes
with 1999.
2. ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which is
effective for us in 2001. SFAS No. 133 requires that entities recognize all
derivatives as either assets or liabilities on the balance sheet and measure
those instruments at fair value. The standard also provides specific guidance
for accounting for derivatives designated as hedging instruments. We are
currently evaluating what impact this standard will have on our financial
statements.
In 1999 we adopted EITF 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities." EITF 98-10 requires energy trading
contracts to be measured at fair value as of the balance sheet date with the
gains and losses included in earnings and separately disclosed in the financial
statements or footnotes. The effects of adopting EITF 98-10 were not material to
our financial statements.
In February 1996, the FASB issued an exposure draft, "Accounting for
Certain Liabilities Related to Closure or Removal of Long-Lived Assets." This
proposed standard would require the estimated present value of the cost of
decommissioning and certain other removal costs to be recorded as a liability,
along with an offsetting plant asset when a decommissioning or other removal
obligation is incurred. The FASB issued a revised exposure draft in February
2000 and we are evaluating the impacts.
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE
SETTLEMENT AGREEMENT. On May 14, 1999, APS entered into a comprehensive
Settlement Agreement with various parties, including representatives of major
consumer groups, related to the implementation of retail electric competition.
On September 23, 1999, the ACC voted to approve the Settlement Agreement, with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement Agreement. One of the parties questioned
the authority of the ACC to approve the Settlement Agreement and both parties
challenged several specific provisions of the Settlement Agreement.
The following are the major provisions of the Settlement Agreement, as
approved:
* APS will reduce rates for standard offer service for customers with
loads less than 3 megawatts in a series of annual retail electric price
reductions of 1.5% beginning July 1, 1999 through July 1, 2003, for a
total of 7.5%. The first reduction of approximately $24 million ($14
million after income taxes) includes the July 1, 1999 retail price
decrease of approximately $11 million annually ($7 million after income
taxes) related to the 1996 regulatory agreement. See "1996 Regulatory
Agreement" below. For having loads 3 megawatts or greater, standard
offer rates will be reduced in annual increments that total 5% through
2002.
39
* Unbundled rates being charged by APS for competitive direct access
service (for example, distribution services) became effective upon
approval of the Settlement Agreement, retroactive to July 1, 1999, and
also will be subject to annual reductions beginning January 1, 2000,
that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
limited circumstances. Neither the ACC nor APS will be prevented from
seeking or authorizing rate changes prior to July 1, 2004 in the event
of conditions or circumstances that constitute an emergency, such as an
inability to finance on reasonable terms, or material changes in APS'
cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws, regulatory requirements, judicial
decisions, actions or orders.
* APS will be permitted to defer for later recovery prudent and reasonable
costs of complying with the ACC electric competition rules, system
benefits costs in excess of the levels included in current rates, and
costs associated with the "provider of last resort" and standard offer
obligations for service after July 1, 2004. These costs are to be
recovered through an adjustment clause or clauses commencing on July 1,
2004.
* APS' distribution system opened for retail access effective September
24, 1999. Customers will be eligible for retail access in accordance
with the phase-in adopted by the ACC under the electric competition
rules (see "Retail Electric Competition Rules" below), with an
additional 140 megawatts being made available to eligible
non-residential customers. Unless subject to judicial or regulatory
restraint, APS will open its distribution system to retail access for
all customers on January 1, 2001.
* Prior to the Settlement Agreement, APS was recovering substantially all
of its regulatory assets through July 1, 2004, pursuant to the 1996
regulatory agreement. In addition, the Settlement Agreement states that
APS has demonstrated that its allowable stranded costs, after mitigation
and exclusive of regulatory assets, are at least $533 million net
present value. APS will not be allowed to recover $183 million net
present value of the above amounts. The Settlement Agreement provides
that APS will have the opportunity to recover $350 million net present
value through a competitive transition charge (CTC) that will remain in
effect through December 31, 2004, at which time it will terminate. Any
over/under-recovery will be credited/debited against the costs subject
to recovery under the adjustment clause described above.
* APS will form a separate corporate affiliate or affiliates and transfer
to that affiliate(s) its generating assets and competitive services at
book value as of the date of transfer, which transfer shall take place
no later than December 31, 2002. APS will be allowed to defer and later
collect, beginning July 1, 2004, sixty-seven percent of its costs to
accomplish the required transfer of generation assets to an affiliate.
* When the Settlement Agreement approved by the ACC is no longer subject
to judicial review, APS will move to dismiss all of its litigation
pending against the ACC as of the date APS entered into the Settlement
Agreement. To protect its rights, APS has several lawsuits pending on
ACC orders relating to stranded cost recovery and the adoption and
amendment of the ACC's electric competition rules, which would be
voluntarily dismissed at the appropriate time under this provision.
As discussed in Note 1 above, APS has discontinued the application of
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation," for its generation operations.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve the rules that provide a framework for the introduction of retail
electric competition in Arizona (Rules). If any of the Rules conflict with the
Settlement Agreement, the terms of the Settlement Agreement govern. On December
8, 1999, APS filed a lawsuit to protect its legal rights regarding the Rules.
This lawsuit is pending, along with several other lawsuits on ACC orders
relating to stranded cost recovery and the adoption or amendment of the Rules,
but two related cases filed by other utilities have been partially decided in a
manner adverse to those utilities' positions. On January 14, 2000, a special
action was filed requesting the Arizona Supreme Court to enjoin implementation
of the Rules and decide whether the ACC can allow the competitive marketplace,
rather than the ACC, to set just and reasonable rates under the Arizona
Constitution. The issue of competitively set rates has been decided by lower
Arizona courts in favor of the ACC in four separate lawsuits, two of which
relate to telecommunications companies. The Supreme Court denied to hear the
case as a special action on March 17, 2000. The lower court litigation will
continue.
40
The Rules approved by the ACC include the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by the
ACC, including APS.
* The Rules require each affected utility, including APS, to make
available at least 20% of its 1995 system retail peak demand for
competitive generation supply beginning when the ACC makes a final
decision on each utility's stranded costs and unbundled rates (Final
Decision Date) or January 1, 2001, whichever is earlier, and 100%
beginning January 1, 2001. Under the Settlement Agreement, APS will
provide retail access to customers representing the minimum 20% required
by the ACC and an additional 140 megawatts of non-residential load in
1999, and to all customers as of January 1, 2001, or such other dates as
approved by the ACC.
* Subject to the 20% requirement, all utility customers with single
premise loads of one megawatt or greater will be eligible for
competitive electric services on the Final Decision Date, which for APS'
customers was the approval of the Settlement Agreement. Customers may
also aggregate smaller loads to meet this one megawatt requirement.
* When effective, residential customers will be phased in at 1.25% per
quarter calculated beginning on January 1, 1999, subject to the 20%
requirement above.
* Electric service providers that get Certificates of Convenience and
Necessity (CC&Ns) from the ACC can supply only competitive services,
including electric generation, but not electric transmission and
distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
non-competitive services.
* The ACC shall allow a reasonable opportunity for recovery of unmitigated
stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
generation assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the Settlement Agreement, APS
received a waiver to allow transfer of its competitive generation assets
and services to affiliates no later than December 31, 2002.
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and APS. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases of
approximately $49 million ($29 million after income taxes), or 3.4%, effective
July 1, 1996; approximately $18 million ($11 million after income taxes), or
1.2%, effective July 1, 1997; approximately $17 million ($10 million after
income taxes), or 1.1%, effective July 1, 1998; and approximately $11 million
($7 million after income taxes), or 0.7%, effective as of July 1, 1999. The July
1, 1999 rate decrease was included in the first rate reduction under the
Settlement Agreement discussed above. The regulatory agreement also required the
parent company to infuse $200 million of common equity into APS in annual
payments of $50 million from 1996 through 1999. All of these equity infusions
were made by December 31, 1999.
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River
Project) and, at their option, smaller municipal electric systems must
(i) make at least 20% of their 1995 retail peak demand available to
electric service providers by December 31, 1998 and for all retail
customers by December 31, 2000; (ii) decrease rates by at least 10% over
a ten-year period beginning as early as January 1, 1991; (iii) implement
procedures and public processes comparable to those already applicable
to public service corporations for establishing the terms, conditions,
and pricing of electric services as well as certain other decisions
affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt
River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive
basis during the first two years of competition only for customers
having demands in excess of one megawatt (and that are eligible for
competitive generation services), and thereafter for all customers
receiving competitive electric generation.
In addition, the Arizona legislature will review and make recommendations
for the 1999-2000 legislative session on certain competitive issues.
GENERAL
APS cannot accurately predict the impact of full retail competition on its
financial position, cash flows, or results of operation. As competition in the
electric industry continues to evolve, APS will continue to evaluate strategies
and alternatives that will position it to compete in the new regulatory
environment.
FEDERAL
The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted
increased competition in the wholesale electric
41
power markets. APS does not expect these rules to have a material impact on its
financial statements.
Several electric utility industry restructuring bills have been introduced
during the 106th Congress. Several of these bills are written to allow consumers
to choose their electricity suppliers beginning in 2000 and beyond. These bills,
other bills that are expected to be introduced, and ongoing discussions at the
federal level suggest a wide range of opinion that will need to be narrowed
before any comprehensive restructuring of the electric utility industry can
occur.
AGREEMENT WITH SALT RIVER PROJECT
On April 25, 1998, APS entered into a Memorandum of Agreement with Salt
River Project in anticipation of, and to facilitate, the opening of the Arizona
electric industry. The ACC approved the Agreement on February 18, 1999. The
Agreement contains the following major components:
* Both parties amended the Territorial Agreement to remove any barriers to
the provision of competitive electricity supply and non-distribution
services.
* Both parties amended the Power Coordination Agreement to lower the price
that APS pays Salt River Project for purchased power. During 1999, the
price APS paid Salt River Project for purchased power was reduced by
approximately $3 million (pretax) and we estimate the decrease to be
approximately $16 million (pretax) in 2000 and lesser annual amounts
through 2006.
* Both parties agreed on certain legislative positions regarding electric
utility restructuring at the state and federal levels.
Certain provisions of the Agreement (including those relating to the
amendments of the Territorial Agreement and the Power Coordination Agreement)
became effective upon the introduction of competition. See "Settlement
Agreement" and "ACC Rules" above.
4. INCOME TAXES
INVESTMENT TAX CREDIT
Because of a 1994 rate settlement agreement, we accelerated amortization of
substantially all of our investment tax credits (ITCs) over a five-year period
(1995-1999).
INCOME TAX BENEFIT FROM DISCONTINUED OPERATIONS
The income tax benefit from discontinued operations for $38 million
resulted from resolution of tax issues related to a former subsidiary, Merabank,
A Federal Savings Bank.
INCOME TAXES
Certain assets and liabilities are reported differently for income tax
purposes than they are for financial statements. The tax effect of these
differences is recorded as deferred taxes. We calculate deferred taxes using the
current income tax rates.
APS has recorded a regulatory asset related to income taxes on its Balance
Sheet in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. APS amortizes this amount as the differences reverse. In
accordance with the 1999 Settlement Agreement, APS is continuing to accelerate
its amortization of the regulatory asset for income taxes over an eight-year
period that will end June 30, 2004 (see Note 1). We are including this
accelerated amortization in depreciation and amortization expense on the
Statements of Income. The components of income tax expense for continuing
operations are:
(thousands of dollars)
Year Ended December 31,
---------------------------------------
1999 1998 1997
--------- --------- ---------
Current
Federal $ 171,491 $ 105,922 $ 105,818
State 37,501 40,621 43,172
--------- --------- ---------
Total current 208,992 146,543 148,990
Deferred (17,413) 41,566 28,729
Change in valuation allowance -- -- (3,920)
ITC amortization (23,514) (23,516) (23,518)
--------- --------- ---------
Total expense $ 168,065 $ 164,593 $ 150,281
========= ========= =========
42
The following chart compares pretax income at the 35% federal income tax
rate to income tax expense:
(thousands of dollars)
[Enlarge/Download Table]
Year Ended December 31,
---------------------------------------
1999 1998 1997
--------- --------- ---------
Federal income tax expense at 35% statutory rate $ 153,243 $ 142,620 $ 135,148
Increases (reductions) in tax expense resulting from:
Tax under book depreciation 14,575 17,848 14,694
Preferred stock dividends of APS 356 3,396 4,481
ITC amortization (23,514) (23,516) (23,518)
State income tax net of federal income tax benefit 23,030 22,764 24,497
Change in valuation allowance -- -- (3,400)
Other 375 1,481 (1,621)
--------- --------- ---------
Income tax expense $ 168,065 $ 164,593 $ 150,281
========= ========= =========
The components of the net deferred income tax liability were as follows:
(thousands of dollars)
Year Ended December 31,
-------------------------
1999 1998
---------- ----------
DEFERRED TAX ASSETS
Deferred gain on Palo Verde Unit 2 sale/leaseback $ 29,446 $ 31,285
Other 133,748 127,903
---------- ----------
Total deferred tax assets 163,194 159,188
---------- ----------
DEFERRED TAX LIABILITIES
Plant-related 1,104,769 1,117,253
Regulatory asset for income taxes 234,117 381,472
---------- ----------
Total deferred tax liabilities 1,338,886 1,498,725
---------- ----------
Accumulated deferred income taxes - net $1,175,692 $1,339,537
========== ==========
5. LINES OF CREDIT
APS had committed lines of credit with various banks of $350 million at
December 31, 1999 and $400 million at December 31, 1998, which were available
either to support the issuance of commercial paper or to be used for bank
borrowings. The commitment fees at December 31, 1999 and 1998 for these lines of
credit ranged from 0.07% to 0.125% per annum. APS had long-term bank borrowings
of $50 million outstanding at December 31, 1999 and $125 million outstanding at
December 31, 1998.
APS' commercial paper borrowings outstanding were $38 million at December
31, 1999 and $179 million at December 31, 1998. The weighted average interest
rate on commercial paper borrowings was 5.33% for the year ended December 31,
1999 and 5.88% for December 31, 1998. By Arizona statute, APS' short-term
borrowings cannot exceed 7% of its total capitalization unless approved by the
ACC.
Pinnacle West had a revolving line of credit of $250 million at December
31, 1999 and 1998. The commitment fees were 0.10% in 1999 and 1998. Outstanding
amounts at December 31, 1999 were $56 million and at December 31, 1998 were $42
million.
SunCor had revolving lines of credit totalling $100 million at December 31,
1999 and $55 million at December 31, 1998. The commitment fees were 0.125% in
1999 and 1998. SunCor had $94 million outstanding at December 31, 1999 and $38
million outstanding at December 31, 1998.
43
6. LONG-TERM DEBT
Borrowings under the APS mortgage bond indenture are secured by
substantially all utility plant; SunCor's debt is collateralized by interests in
certain real property; Pinnacle West's debt is unsecured. The following table
presents the components of consolidated long-term debt outstanding at December
31, 1999 and December 31, 1998:
(thousands of dollars)
[Enlarge/Download Table]
December 31,
Maturity Interest --------------------------
Dates (a) Rates 1999 1998
--------- ----- ---- ----
APS
First mortgage bonds 1999 7.625% $ -- $ 100,000
2000 5.75% 100,000 100,000
2002 8.125% 125,000 125,000
2004 6.625% 80,000 85,000
2020 10.25% 100,550 100,550
2021 9.5% 45,140 45,140
2021 9% 72,370 72,370
2023 7.25% 70,650 91,900
2024 8.75% 121,668 121,668
2025 8% 47,075 88,300
2028 5.5% 25,000 25,000
2028 5.875% 154,000 154,000
Unamortized discount and premium (5,860) (6,482)
Pollution control bonds 2024-2034 Adjustable rate(b) 476,860 456,860
Funds held in trust account for
certain pollution control bonds (1,236) --
Collateralized loan 1999-2000 5.375%-6.125% 10,000 20,000
Unsecured notes 2004 5.875% 125,000 --
Unsecured notes 2005 6.25% 100,000 100,000
Floating rate notes 2001 Adjustable rate(c) 250,000 --
Senior notes (d) 1999 6.72% -- 50,000
Senior notes (d) 2006 6.75% 83,695 100,000
Debentures 2025 10% 75,000 75,000
Bank loans 2003 Adjustable rate(e) 50,000 125,000
Capitalized lease obligation 1999-2001 7.48%(f) 7,199 11,612
---------- ----------
2,112,111 2,040,918
---------- ----------
SUNCOR
Revolving credit 2001-2002 (g) 94,000 38,139
Bank loan 2001 (h) -- 42,061
Notes payable 1998-2006 (i) 3,404 3,888
Bonds payable 2039 5.85% 5,335 --
---------- ----------
102,739 84,088
---------- ----------
PINNACLE WEST
Revolving credit 2001 (j) 56,000 42,000
Senior notes 2001-2003 (k) 50,000 50,000
---------- ----------
106,000 92,000
---------- ----------
Total long-term debt 2,320,850 2,217,006
Less current maturities 114,798 168,045
---------- ----------
Total long-term debt less current maturities $2,206,052 $2,048,961
========== ==========
44
(a) This schedule does not reflect the timing of redemptions that may occur
prior to maturity.
(b) The weighted-average rate for the year ended December 31, 1999 was 3.15%
and for December 31, 1998 was 3.39%. Changes in short-term interest rates
would affect the costs associated with this debt.
(c) The weighted-average rate for the year ended December 31, 1999 was 6.8525%.
(d) APS currently has outstanding $84 million of first mortgage bonds ("senior
note mortgage bonds") issued to the senior note trustee as collateral for
the senior notes. The senior note mortgage bonds have the same interest
rate, interest payment dates, maturity, and redemption provisions as the
senior notes. APS' payments of principal, premium, and/or interest on the
senior notes satisfy its corresponding payment obligations on the senior
note mortgage bonds. As long as the senior note mortgage bonds secure the
senior notes, the senior notes will effectively rank equally with the first
mortgage bonds. When APS repays all of its first mortgage bonds, other than
those that secure senior notes, the senior note mortgage bonds will no
longer secure the senior notes and will cease to be outstanding.
(e) The weighted-average rate for the year ended December 31, 1999 was 5.5% and
for December 31, 1998 was 5.94%. Changes in short-term interest rates would
affect the costs associated with this debt.
(f) Represents the present value of future lease payments (discounted at an
interest rate of 7.48%) on a combined cycle plant that was sold and leased
back (see Note 10).
(g) The weighted-average rate at December 31, 1999 was 8.51% and at December
31, 1998 was 7.41%. Interest for 1999 and 1998 was based on LIBOR plus 2%
or prime plus 0.5%.
(h) The weighted-average rate at December 31, 1998 was 7.76%. Interest for 1998
was based on LIBOR plus 2% or prime plus 0.5%.
(i) Multiple notes primarily with variable interest rates based mostly on the
lenders' prime plus 1.75%.
(j) The weighted-average rate at December 31, 1999 was 6.825% and at December
31, 1998 was 5.66%. Interest for 1999 and 1998 was based on LIBOR plus
0.33%.
(k) Includes two series of notes: $25 million at 6.62% due 2001, and $25
million at 6.87% due 2003.
The following is a list of principal payments due on total long-term debt
and sinking fund requirements through 2004:
* $115 million in 2000
* $364 million in 2001
* $189 million in 2002
* $75 million in 2003 and
* $205 million in 2004.
First mortgage bondholders share a lien on substantially all utility plant
assets (other than nuclear fuel, transportation equipment, and the combined
cycle plant). The mortgage bond indenture restricts the payment of common stock
dividends under certain conditions. These conditions did not exist at December
31, 1999.
7. PREFERRED STOCK OF APS
On March 1, 1999, APS redeemed all of its preferred stock. Preferred stock
balances of APS at December 31, 1999 and 1998 are shown below:
[Enlarge/Download Table]
(dollars in thousands,
except per share amounts) Number of Shares Outstanding Par Value Outstanding
December 31, December 31,
----------------------------------- ---------------------------------
Par Value
Authorized 1999 1998 Per Share 1999 1998
---------- ---- ---- --------- ---- ----
NON-REDEEMABLE:
$1.10 preferred 160,000 -- 139,030 $ 25.00 $ -- $ 3,476
$2.50 preferred 105,000 -- 86,440 50.00 -- 4,322
$2.36 preferred 120,000 -- 32,520 50.00 -- 1,626
$4.35 preferred 150,000 -- 62,986 100.00 -- 6,299
Serial preferred: 1,000,000
$2.40 Series A -- 200,587 50.00 -- 10,029
$2.625 Series C -- 214,895 50.00 -- 10,745
$2.275 Series D -- 90,691 50.00 -- 4,534
$3.25 Series E -- 304,475 50.00 -- 15,224
Serial preferred: 4,000,000
Adjustable rate
Series Q -- 295,851 100.00 -- 29,585
--- --------- ---- -------
Total -- 1,427,475 $ -- $85,840
=== ========= ==== =======
REDEEMABLE:
Serial preferred:
$10.00 Series U -- 94,011 $100.00 $ -- $ 9,401
=== ========= ==== =======
45
Redeemable preferred stock transactions of APS during each of the three
years in the period ended December 31, 1999 are as follows:
(dollars in thousands)
Number of Par Value
Shares Amount
-------- --------
Balance, December 31, 1996 530,000 $ 53,000
Retirements
$10.00 Series U (118,902) (11,890)
$7.875 Series V (120,000) (12,000)
-------- --------
Balance, December 31, 1997 291,098 29,110
Retirements
$10.00 Series U (197,087) (19,709)
-------- --------
Balance, December 31, 1998 94,011 9,401
Retirements
$10.00 Series U (94,011) (9,401)
-------- --------
Balance, December 31, 1999 -- $ --
======== ========
8. COMMON STOCK
Our common stock issued during each of the three years in the period ended
December 31, 1999 is as follows:
(dollars in thousands)
Number of
Shares Amount (a)
----------- -----------
Balance, December 31, 1996 87,515,847 $ 1,636,354
Common stock expense - net -- (2,586)
Common stock retired (2,690,900) (79,997)
----------- -----------
Balance, December 31, 1997 84,824,947 1,553,771
Common stock expense - net -- (3,128)
----------- -----------
Balance, December 31, 1998 84,824,947 1,550,643
Common stock expense - net -- (13,194)
----------- -----------
Balance, December 31, 1999 84,824,947 $ 1,537,449
=========== ===========
(a) Including premiums and expenses of preferred stock issues of APS.
46
9. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLANS
Through 1999, Pinnacle West and its subsidiaries each sponsored defined
benefit pension plans for their own employees. As of January 1, 2000, these
plans were consolidated and now a single pension plan is sponsored by Pinnacle
West for the employees of Pinnacle West and its subsidiaries. A defined benefit
plan specifies the amount of benefits a plan participant is to receive using
information about the participant. The plan covers nearly all of our employees.
Our employees do not contribute to this plan. Generally, we calculate the
benefits under these plans based on age, years of service, and pay. We fund the
plan by contributing at least the minimum amount required under Internal Revenue
Service regulations but no more than the maximum tax-deductible amount. The
assets in the plan at December 31, 1999 were mostly domestic and international
common stocks and bonds and real estate.
Pension expense, including administrative costs, was:
* $4 million in 1999
* $11 million in 1998 and
* $9 million in 1997.
The following table shows the components of net pension cost before
consideration of amounts capitalized or billed to others:
(thousands of dollars)
1999 1998 1997
-------- -------- --------
Service cost - benefits earned during
the period $ 24,982 $ 24,817 $ 20,435
Interest cost on projected benefit obligation 52,905 51,524 48,402
Expected return on plan assets (68,335) (54,513) (47,959)
Amortization of:
Transition asset (3,226) (3,226) (3,226)
Prior service cost 2,078 2,078 2,078
-------- -------- --------
Net periodic pension cost $ 8,404 $ 20,680 $ 19,730
======== ======== ========
The following table shows a reconciliation of the funded status of the
plans to the amounts recognized in the balance sheets:
(thousands of dollars)
1999 1998
--------- ---------
Funded status - pension plan assets more than
(less than) projected benefit obligation $ 37,275 $ (41,034)
Unrecognized net transition asset (20,008) (23,235)
Unrecognized prior service cost 20,636 22,715
Unrecognized net actuarial gains (101,153) (38,668)
--------- ---------
Net pension amount recognized in the balance sheets $ (63,250) $ (80,222)
========= =========
47
The following table sets forth the defined benefit pension plans' change in
projected benefit obligation for the plan years 1999 and 1998:
(thousands of dollars)
1999 1998
--------- ---------
Projected pension benefit obligation at
beginning of year $ 731,305 $ 708,144
Service cost 24,982 24,817
Interest cost 52,905 51,524
Benefit payments (29,694) (29,636)
Actuarial gains (36,860) (23,544)
--------- ---------
Projected pension benefit obligation at end of year $ 742,638 $ 731,305
========= =========
The following table sets forth the defined benefit pension plans' change in
the fair value of plan assets for the plan years 1999 and 1998:
(thousands of dollars)
1999 1998
--------- ---------
Fair value of pension plan assets at
beginning of year $ 690,271 $ 619,412
Actual return on plan assets 93,977 86,527
Employer contributions 25,359 13,968
Benefit payments (29,694) (29,636)
--------- ---------
Fair value of pension plan assets at end of year $ 779,913 $ 690,271
========= =========
We made the assumptions below to calculate the pension liability:
1999 1998
--------- ---------
Discount rate 7.75% 7.00%
Rate of increase in compensation levels 4.25% 3.50%
Expected long-term rate of return on assets 10.00% 10.00%
EMPLOYEE SAVINGS PLAN BENEFITS
Through 1999, Pinnacle West and its subsidiaries each sponsored defined
contribution savings plans for their own employees. As of January 1, 2000, these
plans were consolidated and now a single defined contribution savings plan is
sponsored by Pinnacle West for the employees of Pinnacle West and its
subsidiaries. In a defined contribution plan, the benefits a participant will
receive result from regular contributions they make to a participant account.
Under this plan, we make matching contributions to participant accounts. We
recorded expenses for this plan of approximately $4 million for each of the last
three years (1997-1999).
POSTRETIREMENT PLANS
We provide medical and life insurance benefits to retired employees.
Employees must retire to become eligible for these retirement benefits, which
are based on years of service and age. For the medical insurance plans, retirees
make contributions to cover a portion of the plan costs. For the life insurance
plan, retirees do not make contributions to cover a portion of the plan costs.
We retain the right to change or eliminate these benefits.
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:
* $ 7 million for 1999
* $ 9 million for 1998 and
* $10 million for 1997.
48
The following table shows the components of net periodic postretirement
benefit costs before consideration of amounts capitalized or billed to others:
(thousands of dollars)
1999 1998 1997
-------- -------- --------
Service cost - benefits earned during
the period $ 8,939 $ 7,890 $ 7,046
Interest cost on accumulated benefit obligation 17,366 15,763 14,441
Expected return on plan assets (18,454) (12,001) (8,706)
Amortization of:
Transition asset 7,698 7,698 7,698
Net actuarial gains (5,117) (2,952) (2,685)
-------- -------- --------
Net periodic postretirement benefit cost $ 10,432 $ 16,398 $ 17,794
======== ======== ========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the balance sheets:
(thousands of dollars)
1999 1998
--------- ---------
Funded status - postretirement plan assets more
than (less than) projected benefit obligation $ 25,549 $ (24,269)
Unrecognized net obligation at transition 100,145 107,842
Unrecognized net actuarial gains (128,309) (86,692)
--------- ---------
Net postretirement amount recognized in
the balance sheets $ (2,615) $ (3,119)
========= =========
The following table sets forth the postretirement benefit plans' change in
accumulated benefit obligation for the plan years 1999 and 1998:
(thousands of dollars)
1999 1998
--------- ---------
Accumulated postretirement benefit obligation at
beginning of year $ 237,679 $ 199,348
Service cost 8,939 7,890
Interest cost 17,366 15,763
Benefit payments (8,761) (10,378)
Actuarial (gains) losses (23,234) 25,056
--------- ---------
Accumulated postretirement benefit obligation
at end of year $ 231,989 $ 237,679
========= =========
The following table sets forth the postretirement benefit plans' change in
the fair value of plan assets for the plan years 1999 and 1998:
(thousands of dollars)
1999 1998
--------- ---------
Fair value of postretirement plan assets at
beginning of year $ 213,410 $ 151,146
Actual return on plan assets 42,975 47,284
Employer contributions 9,914 25,327
Benefit payments (8,761) (10,347)
--------- ---------
Fair value of postretirement plan assets
at the end of year $ 257,538 $ 213,410
========= =========
49
We made the assumptions below to calculate the postretirement liability:
1999 1998
---- ----
Discount rate 7.75% 7.00%
Expected long-term rate of return on assets - after tax 8.77% 8.73%
Initial health care cost trend rate - under age 65 7.00% 7.50%
Initial health care cost trend rate - age 65 and over 6.00% 6.50%
Ultimate health care cost trend rate (reached
in the year 2002) 5.00% 5.00%
Assuming a 1% increase in the health care cost trend rate, the 1999 cost of
postretirement benefits other than pensions would increase by approximately $5
million and the accumulated benefit obligation as of December 31, 1999 would
increase by approximately $38 million.
Assuming a 1% decrease in the health care cost trend rate, the 1999 cost of
postretirement benefits other than pensions would decrease by approximately $4
million and the accumulated benefit obligation as of December 31, 1999 would
decrease by approximately $30 million.
10. LEASES
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale leaseback transactions. APS accounts
for these leases as operating leases. The gain of approximately $140 million was
deferred and is being amortized to operations expense over 29.5 years, the
original term of the leases. There are options to renew the leases for two
additional years and to purchase the property for fair market value at the end
of the lease terms. Consistent with the ratemaking treatment, an amount equal to
the annual lease payments is included in rent expense. A regulatory asset is
recognized for the difference between lease payments and rent expense calculated
on a straight-line basis.
The average amounts to be paid for the Palo Verde Unit 2 leases are
approximately $46 million in 2000 and approximately $49 million per year in
2001-2015.
In accordance with the 1999 Settlement Agreement, APS is continuing to
accelerate amortization of the regulatory asset for leases over an eight-year
period that will end June 30, 2004 (see Note 1). The accelerated amortization is
included in depreciation and amortization expense on the Statements of Income.
The balance of this regulatory asset at December 31, 1999 was $43 million. Lease
expense was approximately $42 million in each of the years 1997 through 1999.
APS has a capital lease on a combined cycle plant, which it sold and leased
back. The lease requires semiannual payments of $3 million through June 2001,
and includes renewal and purchase options based on fair market value. The plant
is included in plant in service at its original cost of $54 million; accumulated
amortization at December 31, 1999 was $51 million.
In addition, we lease certain land, buildings, equipment, and miscellaneous
other items through operating rental agreements with varying terms, provisions,
and expiration dates. Miscellaneous lease expense was approximately $10 million
in 1999, $13 million in 1998, and $11 million in 1997.
Estimated future minimum lease commitments, excluding the Palo Verde and
combined cycle leases, are as follows:
(dollars in millions)
Year
----
2000 $ 17
2001 19
2002 20
2003 20
2004 20
Thereafter 138
----
Total future commitments $234
====
50
11. JOINTLY-OWNED FACILITIES
APS shares ownership of some of its generating and transmission facilities
with other companies. The following table shows APS' interest in those
jointly-owned facilities at December 31, 1999. APS' share of operating and
maintaining these facilities is included in the income statement in operations
and maintenance expense.
(dollars in thousands)
[Enlarge/Download Table]
Percent Plant Construction
Owned by in Accumulated Work In
APS Service Depreciation Progress
--- ------- ------------ --------
Generating Facilities:
Palo Verde Nuclear Generating Station Units 1 and 3 29.1% $1,829,633 $ 751,567 $ 7,220
Palo Verde Nuclear Generating Station Unit 2 (see Note 10) 17.0% 572,574 240,696 17,145
Four Corners Steam Generating Station Units 4 and 5 15.0% 139,209 71,333 364
Navajo Steam Generating Station Units 1, 2, and 3 14.0% 230,536 94,332 4,555
Cholla Steam Generating Station Common Facilities (a) 62.8%(b) 68,643 38,068 1,679
Transmission Facilities:
ANPP 500 KV System 35.8%(b) 68,133 21,446 7
Navajo Southern System 31.4%(b) 27,364 17,550 42
Palo Verde - Yuma 500 KV System 23.9%(b) 11,728 4,388 36
Four Corners Switchyards 27.5%(b) 3,071 1,855 --
Phoenix - Mead System 17.1%(b) 36,434 1,768 --
(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for them. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
12. COMMITMENTS AND CONTINGENCIES
LITIGATION
We are party to various claims, legal actions, and complaints arising in
the ordinary course of business. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial
statements.
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.
APS has 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 believes it 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. APS currently estimates that it will incur $113
million (in 1999 dollars) over the life of Palo Verde for its share of the costs
related to the on-site interim storage of spent nuclear fuel. As of December 31,
1999, APS had recorded a liability and a regulatory asset of $37 million for
on-site interim nuclear fuel storage costs related to nuclear fuel burned to
date. APS currently believes 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
51
liability insurance provided by commercial insurance carriers in the amount of
$200 million and the balance by an industry-wide retrospective assessment
program. If losses at any nuclear power plant covered by the programs exceed the
accumulated funds, APS could be assessed retrospective premium adjustments. The
maximum assessment per reactor under the program for each nuclear incident is
approximately $88 million, subject to an annual limit of $10 million per
incident. Based upon the 29.1% interest in the three Palo Verde units, APS'
maximum potential assessment per incident for all three units is approximately
$77 million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. APS has also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
FUEL AND PURCHASED POWER COMMITMENTS
APS is a party to various fuel and purchased power contracts with terms
expiring from 2000 through 2020 that include required purchase provisions. APS
estimates its 2000 contract requirements to be about $177 million. However, this
amount may vary significantly pursuant to certain provisions in such contracts
that permit APS to decrease its required purchases under certain circumstances.
APS must reimburse certain coal providers for amounts incurred for coal
mine reclamation. APS estimates its share of the total obligation to be about
$103 million. The portion of the coal mine reclamation obligation related to
coal already burned is about $57 million at December 31, 1999 and is included in
"Deferred Credits-Other" in the Balance Sheet.
A regulatory asset has been established for amounts not yet recovered from
ratepayers. In accordance with the 1999 Settlement Agreement with the ACC, APS
is continuing to accelerate the amortization of the regulatory asset for coal
mine reclamation over an eight-year period that will end June 30, 2004.
Amortization is included in depreciation and amortization expense on the
Statements of Income. The balance of the regulatory asset at December 31, 1999
was about $41 million.
CONSTRUCTION PROGRAM
Consolidated capital expenditures in 2000 are estimated at $591 million.
GENERATION EXPANSION
We are currently planning, through Pinnacle West Energy, a 650-megawatt
expansion of our West Phoenix Power Plant, and the construction of a natural
gas-fired electric generating station of up to 2,120 megawatts near Palo Verde,
called Redhawk. Pinnacle West Energy's capital expenditures in 1999 were $21
million. Projected capital expenditures for these projects are $152 million in
2000; $240 million in 2001; and $245 million in 2002. We are also considering
additional expansion over the next several years, which may result in additional
expenditures. Pinnacle West Energy's capital expenditures will be funded with
debt proceeds, and internally generated cash and debt proceeds from the parent
company. Assuming all approvals are granted, we expect to begin construction at
West Phoenix in the second quarter of 2000.
Pinnacle West Energy has signed a joint development agreement with Reliant
Energy Power Generation, Inc. (Reliant) covering construction and operation of
three new merchant plants. Pinnacle West Energy plans to contribute the first
two units (1,060 megawatts) of the Redhawk project to the joint agreement.
Construction is expected to start in the third quarter of 2000, with commercial
operation scheduled in the summer of 2002. Reliant plans to contribute two new
natural gas-fired projects (1,500 megawatts) in Nevada to the venture.
13. NUCLEAR DECOMMISSIONING COSTS
APS recorded $11 million for nuclear decommissioning expense in each of the
years 1999, 1998, and 1997. APS estimates it will cost about $1.8 billion ($472
million in 1999 dollars) to decommission its 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. APS charges decommissioning costs to expense over each
unit's operating license term and includes them in the accumulated depreciation
balance until each unit is retired. Nuclear decommissioning costs are recovered
in rates.
APS' current estimates are based on a 1998 site-specific study for Palo
Verde that assumes the prompt removal/dismantlement method of decommissioning.
An independent consultant prepared this study. APS is required to update the
study every three years.
To fund the costs APS expects to incur to decommission the plant, APS
established external decommissioning trusts in accordance with Nuclear
Regulatory Commission (NRC) regulations. The trust accounts are reported in
"Investments and Other Assets" on the Consolidated Balance Sheets at their
market value of $176 million at December 31, 1999 and $146 million at December
31, 1998.
52
APS invests the trust funds primarily in fixed income securities and
domestic stock and classifies them as available for sale. Realized and
unrealized gains and losses are reflected in accumulated depreciation.
See Note 2 for a proposed accounting standard on accounting for certain
liabilities related to closure or removal of long-lived assets.
14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Consolidated quarterly financial information for 1999 and 1998 is as
follows:
[Enlarge/Download Table]
(dollars in thousands, except per share amounts) 1999
--------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Operating revenues
Electric $413,983 $511,434 $ 867,630 $500,137
Real estate 24,533 32,697 26,640 46,299
Operating income (a) $ 91,599 $148,968 $ 240,294 $ 97,916
Income from continuing operations $ 30,690 $ 68,702 $ 125,579 $ 44,801
Income tax benefit from discontinued operations -- -- 38,000 --
Extraordinary charge - net of income tax -- -- (139,885) --
-------- -------- --------- --------
Net income $ 30,690 $ 68,702 $ 23,694 $ 44,801
======== ======== ========= ========
Earnings (loss) per average common share outstanding
Continuing operations - basic $ 0.36 $ 0.81 $ 1.48 $ 0.53
Discontinued operations - basic -- -- 0.45 --
Extraordinary charge - basic -- -- (1.65) --
-------- -------- --------- --------
Net Income - basic $ 0.36 $ 0.81 $ 0.28 $ 0.53
======== ======== ========= ========
Continuing operations - diluted $ 0.36 $ 0.81 $ 1.48 $ 0.53
Discontinued operations - diluted -- -- 0.45 --
Extraordinary charge - diluted -- -- (1.65) --
-------- -------- --------- --------
Net Income - diluted $ 0.36 $ 0.81 $ 0.28 $ 0.53
======== ======== ========= ========
Dividends declared per share (b) $ 0.325 $ 0.65 $ -- $ 0.35
(dollars in thousands, except per share amounts) 1998
--------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Operating revenues
Electric $380,423 $441,715 $740,734 $443,526
Real estate 34,161 28,916 18,276 42,835
Operating income (a) $ 90,837 $122,605 $251,838 $101,848
Net income $ 31,086 $ 48,997 $127,281 $ 35,528
Earnings per average common share outstanding
Net income - basic $ 0.37 $ 0.58 $ 1.50 $ 0.42
Net income - diluted $ 0.36 $ 0.57 $ 1.49 $ 0.42
Dividends declared per share (b) $ 0.30 $ 0.60 $ -- $ 0.325
(a) APS' utility business is seasonal in nature, with the peak sales periods
generally occurring during the summer months. Comparisons among quarters of
a year may not represent overall trends and changes in operations.
(b) Dividends for the quarters ending September 30, 1999 and September 30, 1998
were declared in June.
53
15. FAIR VALUE OF FINANCIAL INSTRUMENTS
We believe that the carrying amounts of our cash equivalents and commercial
paper are reasonable estimates of their fair values at December 31, 1999 and
1998 due to their short maturities.
We hold investments in debt and equity securities for purposes other than
trading. The December 31, 1999 and 1998 fair values of such 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 amount.
The carrying value of our long-term debt (excluding a capitalized lease
obligation) was $2.31 billion on December 31, 1999, with an estimated fair value
of $2.29 billion. On December 31, 1998, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.21 billion, with an estimated
fair value of $2.27 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.
16. EARNINGS PER SHARE
In 1997 we adopted SFAS No. 128, "Earnings Per Share." This statement
requires the presentation of both basic and diluted earnings per share on the
financial statements. The following table presents earnings per average common
share outstanding (EPS):
1999 1998 1997
---- ---- ----
Basic EPS:
Continuing operations $ 3.18 $2.87 $2.76
Discontinued operations 0.45 -- --
Extraordinary charge (1.65) -- --
------ ----- -----
Net income $ 1.98 $2.87 $2.76
====== ===== =====
Diluted EPS:
Continuing operations $ 3.17 $2.85 $2.74
Discontinued operations 0.45 -- --
Extraordinary charge (1.65) -- --
------ ----- -----
Net income $ 1.97 $2.85 $2.74
====== ===== =====
Dilutive stock options increased average common shares outstanding by
291,392 shares in 1999, 571,728 shares in 1998, and 519,800 shares in 1997.
Total average common shares outstanding for the purposes of calculating diluted
earnings per share were 85,008,527 shares in 1999, 85,345,946 shares in 1998,
and 86,022,709 shares in 1997.
Options to purchase 506,734 shares of common stock were outstanding during
the last quarter of 1999 but were not included in the computation of diluted EPS
because the options' exercise price was greater than the average market price of
the common shares.
17. STOCK-BASED COMPENSATION
Pinnacle West offers two stock incentive plans for our and our
subsidiaries' officers and key employees.
The most recent plan provides for the granting of new options (which may be
non-qualified stock options or incentive stock options) of up to 3.5 million
shares at a price per option not less than the fair market value on the date the
option is granted. The plan also provides for the granting of any combination of
shares of restricted stock, stock appreciation rights or dividend equivalents.
The awards outstanding under the incentive plans at December 31, 1999
approximate 1,441,124 non-qualified stock options, 159,837 restricted stock, and
no incentive stock options, stock appreciation rights or dividend equivalents.
The FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation"
which was effective beginning in 1996. The 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."
54
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:
(thousands of dollars)
1999 1998 1997
-------- -------- --------
Net income
As reported $167,887 $242,892 $235,856
Pro forma (fair value method) $166,913 $242,177 $235,446
Net income per share - basic
As reported $ 1.98 $ 2.87 $ 2.76
Pro forma (fair value method) $ 1.97 $ 2.86 $ 2.75
We did not consider compensation costs for stock options granted before
January 1, 1995. Therefore, future reported net income may not be representative
of this compensation cost calculation. In order to present the pro forma
information above, we calculated the fair value of each fixed stock option in
the incentive plans using the Black-Scholes option-pricing model. The fair value
was calculated based on the date the option was granted. The following
weighted-average assumptions were also used in order to calculate the fair value
of the stock options:
1999 1998 1997
---- ---- ----
Risk-free interest rate 5.68% 4.54% 5.66%
Dividend yield 3.33% 3.03% 4.50%
Volatility 20.50% 18.80% 15.63%
Expected life (months) 60 60 60
The following table is a summary of the status of our stock option plans as
of December 31, 1999, 1998, and 1997 and changes during the years ending on
those dates:
[Enlarge/Download Table]
1999 Weighted 1998 Weighted 1997 Weighted
1999 Average 1998 Average 1997 Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
------ -------------- ------ -------------- ------ --------------
Outstanding at beginning of year 1,563,512 $27.95 1,554,631 $24.38 1,739,576 $21.51
Granted 458,450 35.95 244,200 46.78 260,450 39.56
Exercised (516,838) 18.19 (217,317) 23.09 (409,975) 21.60
Forfeited (64,000) 40.36 (18,002) 33.42 (35,420) 27.10
--------- --------- ---------
Outstanding at end of year 1,441,124 33.45 1,563,512 27.95 1,554,631 24.38
--------- --------- ---------
Options exercisable at year-end 835,381 29.69 1,106,165 22.04 1,075,014 19.52
--------- --------- ---------
Weighted average fair value of
options granted during the year 7.05 8.15 5.83
55
The following table summarizes information about our stock option plans at
December 31, 1999:
Weighted Average
Exercise Remaining Options
Prices Per Share Outstanding Contract Life Exercisable
---------------- ----------- ------------- -----------
$10.06 7,000 1.50 7,000
11.25 15,500 0.90 15,500
15.75 17,500 1.90 17,500
16.25 3,500 0.50 3,500
17.68 10,775 2.10 10,775
18.13 28,000 2.50 28,000
19.00 82,370 4.90 82,370
19.56 32,000 2.90 32,000
22.13 71,584 4.00 71,584
23.25 28,000 3.50 28,000
27.44 126,837 5.90 126,837
31.44 157,874 6.90 157,874
34.66 348,450 9.90 9,679
36.56 5,000 9.80 417
39.75 213,534 8.00 142,356
41.00 70,000 9.10 21,389
46.78 223,200 8.90 80,600
--------- -------
$10.06-$46.78 1,441,124 835,381
========= =======
18. BUSINESS SEGMENTS
Historically, we reported our operations as a single, integrated business
segment. The basis of our reporting in previous years was due to APS' regulated
operating environment. The ACC authorized a combined rate for supplying and
delivering electricity to customers which was cost-based and was designed to
recover APS' operating expenses and investment in electric utility assets and to
provide a return on the investment.
As a result of the 1999 Settlement Agreement, our generation operations are
now deregulated for accounting purposes. For the purposes of complying with SFAS
No. 131, "Disclosures about Segments of an Enterprise and Related Information"
(SFAS No. 131), we are required to disclose information about its business
segments separately. Accordingly, APS has separated identifiable expenses
between the two segments and has allocated revenues and other expenses using a
study that identifies the portion of its base rates related to generation and
delivery. APS then used that information to develop the financial information of
the business segments for each of the three years ended December 31, 1999 (or as
of December 31, 1999 and 1998, with respect to assets). None of our revenues
from external customers are attributed to, and none of our long-lived assets are
located in, any foreign country.
Beginning in 1999, we have two principal business segments (determined by
products, services, and regulatory environment) which consist of the generation
of electricity (generation business segment), and the transmission and
distribution of electricity (delivery business segment). The "Other" amounts
include activity relating to other subsidiaries including SunCor, El Dorado, and
APS Energy Services. Intercompany eliminations primarily relate to intercompany
sales of electricity. Financial data for business segments is provided as
follows:
56
BUSINESS SEGMENTS FOR YEAR ENDED DECEMBER 31, 1999 (in thousands)
[Enlarge/Download Table]
Generation Delivery Other Eliminations Total
---------- -------- ----- ------------ -----
Operating revenues $ 853,755 $2,292,798 $130,555 $(853,755) $2,423,353
Operating expense 522,925 1,672,169 106,876 (853,755) 1,448,215
---------- ---------- -------- --------- ----------
Operating margin 330,830 620,629 23,679 -- 975,138
Depreciation and amortization 121,683 260,374 3,511 -- 385,568
Interest and preferred stock
dividend requirements 40,753 101,855 9,125 -- 151,733
---------- ---------- -------- --------- ----------
Pretax margin 168,394 258,400 11,043 -- 437,837
Income taxes 47,976 111,512 8,577 -- 168,065
Income tax benefit from
discontinued operations - PNW -- -- 38,000 -- 38,000
Extraordinary charge - net
of income tax of $94,115 -- (139,885) -- -- (139,885)
---------- ---------- -------- --------- ----------
Earnings for common stock $ 120,418 $ 7,003 $ 40,466 $ -- $ 167,887
========== ========== ======== ========= ==========
Total assets $2,342,291 $3,795,846 $470,369 $ -- $6,608,506
========== ========== ======== ========= ==========
Capital expenditures $ 110,798 $ 241,469 $126,581 $ -- $ 478,848
========== ========== ======== ========= ==========
BUSINESS SEGMENTS FOR YEAR ENDED DECEMBER 31, 1998 (in thousands)
Generation Delivery Other Eliminations Total
---------- -------- ----- ------------ -----
Operating revenues $ 858,340 $2,006,398 $124,188 $(858,340) $2,130,586
Operating expense 522,696 1,414,753 104,061 (858,340) 1,183,170
---------- ---------- -------- --------- ----------
Operating margin 335,644 591,645 20,127 -- 947,416
Depreciation and amortization 135,406 241,168 3,105 -- 379,679
Interest and preferred stock
dividend requirements 37,045 108,670 14,537 -- 160,252
---------- ---------- -------- --------- ----------
Pretax margin 163,193 241,807 2,485 -- 407,485
Income taxes 49,969 109,487 5,137 -- 164,593
---------- ---------- -------- --------- ----------
Earnings for common stock $ 113,224 $ 132,320 $ (2,652) $ -- $ 242,892
========== ========== ======== ========= ==========
Total assets $2,399,560 $3,993,740 $431,246 $ -- $6,824,546
========== ========== ======== ========= ==========
Capital expenditures $ 85,767 $ 241,638 $ 73,133 $ -- $ 400,538
========== ========== ======== ========= ==========
BUSINESS SEGMENTS FOR YEAR ENDED DECEMBER 31, 1997 (in thousands)
Generation Delivery Other Eliminations Total
---------- -------- ----- ------------ -----
Operating revenues $ 803,647 $1,878,553 $116,473 $(803,647) $1,995,026
Operating expense 471,992 1,297,802 98,519 (803,647) 1,064,666
---------- ---------- -------- --------- ----------
Operating margin 331,655 580,751 17,954 -- 930,360
Depreciation and amortization 131,684 233,987 2,614 -- 368,285
Interest and preferred stock
dividend requirements 50,311 104,410 21,217 -- 175,938
---------- ---------- -------- --------- ----------
Pretax margin 149,660 242,354 (5,877) -- 386,137
Income taxes 44,898 108,426 (3,043) -- 150,281
---------- ---------- -------- --------- ----------
Earnings for common stock $ 104,762 $ 133,928 $ (2,834) $ -- $ 235,856
========== ========== ======== ========= ==========
Capital expenditures $ 84,960 $ 217,047 $ 67,248 $ -- $ 369,255
========== ========== ======== ========= ==========
57
PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
[Enlarge/Download Table]
Column A Column B Column C Column D Column E
Additions
----------------------
Balance at Charged to Charged Balance
beginning cost and to other at end of
Description of Period Expenses Accounts Deductions (a) Period
----------- --------- -------- -------- ---------- ------
(Thousands of Dollars)
YEAR ENDED DECEMBER 31, 1999
Real Estate Valuation Reserves $15,000 $ --- $ --- $ 7,000 $ 8,000
YEAR ENDED DECEMBER 31, 1998
Real Estate Valuation Reserves $23,000 $ --- $ --- $ 8,000 $15,000
YEAR ENDED DECEMBER 31, 1997
Real Estate Valuation Reserves $41,000 $ --- $ --- $18,000 $23,000
----------
(a) Represents pro-rata allocations for sale of land.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" and to "General --
Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's Proxy
Statement relating to the Annual Meeting of Shareholders to be held on May 17,
2000 (the "2000 Proxy Statement") and to the Supplemental Item --- "Executive
Officers of the Registrant" in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to the fourth and fifth paragraphs under the
heading "The Board and its Committees," to "Executive Compensation," to "Human
Resources Committee Report," to "Stock Performance Comparisons" and to
"Executive Benefit Plans" in the 2000 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Certain Securities Ownership" in the 2000
Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to "Executive Benefit Plans --- Employment and
Severance Arrangements" and to "General-Business Relationship" in the 2000 Proxy
Statement.
58
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements
See the Index to Consolidated Financial Statements and Financial
Statement Schedule in Part II, Item 8.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION
----------- -----------
10.1(a) -- 2000 Management Variable Incentive Plan (Pinnacle West)
10.2(a) -- 2000 Senior Management Variable Incentive Plan (Pinnacle West)
10.3(a) -- 2000 Officer Variable Incentive Plan (Pinnacle West)
10.4(a) -- 2000 Management Variable Incentive Plan (APS)
10.5(a) -- 2000 Senior Management Variable Incentive Plan (APS)
10.6(a) -- 2000 Officers Variable Incentive Plan (APS)
10.7(a) -- First Amendment effective as of January 1, 1999, to the Pinnacle
West Capital Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company Deferred
Compensation Plan
10.8(a) -- Fourth Amendment dated December 28, 1999 to the Arizona Public
Service Company Directors Deferred Compensation Plan
10.9(a) -- Letter Agreement dated December 13, 1999 between APS and William L.
Stewart
10.10(a) -- Second Amendment effective January 1, 2000 to the Pinnacle West
Capital Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company Deferred
Compensation Plan
10.11(a) -- First Amendment dated December 7, 1999 to the Pinnacle West Capital
Corporation Stock Option and Incentive Plan
10.12(a) -- First Amendment dated December 7, 1999 to the Pinnacle West Capital
Corporation 1994 Long-Term Incentive Plan
10.13(a) -- Pinnacle West Capital Corporation Supplemental Excess Benefit
Retirement Plan, as amended and restated, dated December 7, 1999
10.14(a) -- Trust for the Pinnacle West Capital Corporation, Arizona Public
Service Company and SunCor Development Company Deferred
Compensation Plans dated August 1, 1996
10.15(a) -- First Amendment dated December 7, 1999 to the Trust for the
Pinnacle West Capital Corporation, Arizona Public Service Company
and SunCor Development Company Deferred Compensation Plans
59
10.16(a) -- Letter Agreement dated July 28, 1995 between Arizona Public Service
Company and Armando B. Flores
10.17(a) -- Letter Agreement dated October 3, 1997 between Arizona Public
Service Company and James M. Levine
21 -- Subsidiaries of the Company
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:
[Enlarge/Download Table]
Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
3.1 Articles of Incorporation, 19.1 to the Company's 1-8962 11-14-88
restated as of July 29, 1988 September 1988 Form 10-Q
Report
3.2 Bylaws, amended as of 4.1 to the Company's 1-8962 1-20-00
December 15, 1999 Registration Statement on
Form S-8 No. 333-95035
4.1 Mortgage and Deed of Trust 4.1 to APS' September 1992 1-4473 11-9-92
Relating to APS' First Form 10-Q Report
Mortgage Bonds, together
with forty-eight indentures
supplemental thereto
4.2 Forty-ninth Supplemental 4.1 to APS' 1992 Form 10-K 1-4473 3-30-93
Indenture Report
4.3 Fiftieth Supplemental 4.2 to APS' 1993 Form 10-K 1-4473 3-30-94
Indenture Report
4.4 Fifty-first Supplemental 4.1 to APS' August 1, 1993 1-4473 9-27-93
Indenture Form 8-K Report
4.5 Fifty-second Supplemental 4.1 to APS' September 30, 1993 1-4473 11-15-93
Indenture Form 10-Q Report
4.6 Fifty-third Supplemental 4.5 to APS' Registration 1-4473 3-1-94
Indenture Statement No. 33-61228 by
means of February 23, 1994
Form 8-K Report
4.7 Fifty-fourth Supplemental 4.1 to APS' Registration 1-4473 11-22-96
Indenture Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996 Form 8-K
Report
60
[Enlarge/Download Table]
Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
4.8 Fifty-fifth Supplemental 4.8 to APS' Registration 1-4473 4-9-97
Indenture Statement Nos. 33-55473, 33-
64455 and 333-15379 by means
of April 7, 1997 Form 8-K
Report
4.9 Agreement, dated March 21, 4.1 to APS' 1993 Form 10-K 1-4473 3-30-94
1994, relating to the filing Report
of instruments defining the
rights of holders of APS
long-term debt not in excess
of 10% of APS' total assets
4.10 Indenture dated as of January 4.6 to APS' Registration 1-4473 1-11-95
1, 1995 among APS and The Statement Nos. 33-61228 and
Bank of New York, as 33-55473 by means of January
Trustee 1, 1995 Form 8-K Report
4.11 First Supplemental Indenture 4.4 to APS' Registration 1-4473 1-11-95
dated as of January 1, 1995 Statement Nos. 33-61228 and
33-55473 by means of January
1, 1995 Form 8-K Report
4.12 Indenture dated as of 4.5 to APS' Registration 1-4473 11-22-96
November 15, 1996 among Statements Nos. 33-61228,
APS and The Bank of New 33-55473, 33-64455 and 333-
York, as Trustee 15379 by means of November
19, 1996 Form 8-K Report
4.13 First Supplemental Indenture 4.6 to APS' Registration 1-4473 11-22-96
Statements Nos. 33-61228,
33-55473, 33-64455 and 333-
15379 by means of November
19, 1996 Form 8-K Report
4.14 Second Supplemental 4.10 to APS' Registration 1-4473 4-9-97
Indenture Statement Nos. 33-55473, 33-
64455 and 333-15379 by means
of April 7, 1997 Form 8-K
Report
61
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
4.15 Specimen Certificate of 4.2 to the Company's 1988 1-8962 3-31-89
Pinnacle West Capital Form 10-K Report
Corporation Common Stock,
no par value
4.16 Agreement, dated March 29, 4.1 to the Company's 1987 1-8962 3-30-88
1988, relating to the filing of Form 10-K Report
instruments defining the
rights of holders of long-term
debt not in excess of 10% of
the Company's total assets
4.17 Indenture dated as of January 4.10 to APS' Registration 1-4473 1-16-98
15, 1998 among APS and The Statement Nos. 333-15379
and Chase Manhattan Bank, as 333-27551 by means of January
Trustee 13, 1998 Form 8-K Report
4.18 First Supplemental Indenture 4.3 to APS' Registration 1-4473 1-16-98
dated as of January 15, 1998 Statement Nos. 333-15379 and
333-27551 by means of January
13, 1998 Form 8-K Report
4.19 Second Supplemental 4.3 to APS' Registration 1-4473 2-22-99
Indenture dated as of Statement Nos. 333-27551
February 15, 1999 and 333-58445 by means of
February 18, 1999
Form 8-K Report
4.20 Third Supplemental Indenture 4.5 to APS' Registration 1-4473 11-5-99
dated as of November 1, 1999 Statement No. 333-58445 by
means of November 2, 1999
Form 8-K Report
4.21 Amended and Restated Rights 4.1 to the Company's March 22, 1-8962 4-19-99
Agreement, dated as of March 1999 Form 8-K Report
26, 1999, between Pinnacle
West Capital Corporation and
BankBoston, N.A., as Rights
Agent, including (i) as Exhibit
A thereto the form of Amended
Certificate of Designation of
Series A Participating Preferred
Stock of Pinnacle West Capital
Corporation, (ii) as Exhibit B
thereto the form of Rights
Certificate and (iii) as Exhibit
C thereto the Summary of Right
to Purchase Preferred Shares
62
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.18(a) Employment Agreement, 10.1 to the Company's 1990 2-96386 3-28-91
effective as of February 5, Form 10-K Report
1990, between Richard Snell
and the Company
10.19 Two separate 10.2 to APS' September 1991 1-4473 11-14-91
Decommissioning Trust Form 10-Q Report
Agreements (relating to
PVNGS Units 1 and 3,
respectively), each dated July
1, 1991, between APS and
Mellon Bank, N.A., as
Decommissioning Trustee
10.20 Amendment No. 1 to 10.1 to APS' 1994 Form 10- K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 1),
dated as of December 1, 1994
10.21 Amendment No. 1 to 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 3),
dated as of December 1, 1994
10.22 Amendment No. 2 to APS 10.4 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 1)
dated as of July 1, 1991
10.23 Amendment No. 2 to APS 10.6 to APS' 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 3)
dated as of July 1, 1991
63
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.24 Amended and Restated 10.1 to the Company's 1991 1-8962 3-26-92
Decommissioning Trust Form 10-K Report
Agreement (PVNGS Unit 2)
dated as of January 31, 1992,
among APS, Mellon Bank, N.A.,
as Decommissioning Trustee,
and State Street Bank and Trust
Company, as successor to The
First National Bank of Boston,
as Owner Trustee under two
separate Trust Agreements,
each with a separate Equity
Participant, and as Lessor
under two separate Facility
Leases, each relating to
an undivided interest in PVNGS
Unit 2
10.25 First Amendment to 10.2 to APS' 1992 Form 10-K 1-4473 3-30-93
Amended and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2),
dated as of November 1, 1992
10.26 Amendment No. 2 to 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95
Amended and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2),
dated as of November 1, 1994
10.27 Amendment No. 3 to 10.1 to APS' June 1996 Form 1-4473 8-9-96
Amended and Restated 10-Q Report
Decommissioning Trust
Agreement (PVNGS Unit 2),
dated as of November 1, 1994
10.28 Amendment No. 4 to APS 10.5 to APS' 1996 Form 10-K 1-4473 3-28-97
Amended and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2)
dated as of January 31, 1992
10.29 Asset Purchase and Power 10.1 to APS' June 1991 Form 1-4473 8-8-91
Exchange Agreement dated 10-Q Report
September 21, 1990 between
APS and PacifiCorp, as
amended as of October 11,
1990 and as of July 18, 1991
64
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.30 Long-Term Power 10.2 to APS' June 1991 Form 1-4473 8-8-91
Transaction Agreement dated 10-Q Report
September 21, 1990 between
APS and PacifiCorp, as
amended as of October 11,
1990, and as of July 8, 1991
10.31 Amendment No. 1 dated 10.3 to APS' 1995 Form 10-K 1-4473 3-29-96
April 5, 1995 to the Report
Long-Term Power
Transaction Agreement and
Asset Purchase and Power
Exchange Agreement
between PacifiCorp and APS
10.32 Restated Transmission 10.4 to APS' 1995 Form 10-K 1-4473 3-29-96
Agreement between Report
PacifiCorp and APS
dated April 5, 1995
10.33 Contract among PacifiCorp, 10.5 to APS' 1995 Form 10-K 1-4473 3-29-96
APS and United States Report
Department of Energy
Western Area Power
Administration, Salt Lake
Area Integrated Projects for
Firm Transmission Service
dated May 5, 1995
10.34 Reciprocal Transmission 10.6 to APS' 1995 Form 10-K 1-4473 3-29-96
Service Agreement between Report
APS and PacifiCorp dated as
of March 2, 1994
10.35 Contract, dated July 21, 1984, 10.31 to the Company's Form 2-96386 3-13-85
with DOE providing for the S-14 Registration Statement
disposal of nuclear fuel
and/or high-level radioactive
waste, ANPP
10.36 Indenture of Lease with 5.01 to APS' Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Four Registration Statement
Corners Plant
10.37 Supplemental and Additional 5.02 to APS' Form S-7 2-59644 9-1-77
Indenture of Lease, including Registration Statement
amendments and supplements
to original lease with Navajo
Tribe of Indians, Four
Corners Plant
10.38 Amendment and Supplement 10.36 to the Company's 1-8962 7-25-85
No. 1 to Supplemental and Registration Statement on Form
Additional Indenture of Lease 8-B Report
Four Corners, dated April 25,
1985
65
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.39 Application and Grant of 5.04 to APS' Form S-7 2-59644 9-1-77
multi-party rights-of-way Registration Statement
and easements, Four Corners
Plant Site
10.40 Application and Amendment 10.37 to the Company's 1-8962 7-25-85
No. 1 to Grant of multi-party Registration Statement on Form
rights-of-way and easements, 8-B
Four Corners Power Plant
Site dated April 25, 1985
10.41 Application and Grant of 5.05 to APS' Form S-7 2-59644 9-1-77
Arizona Public Service Registration Statement
Company rights-of-way and
easements, Four Corners
Plant Site
10.42 Application and Amendment 10.38 to the Company's 1-8962 7-25-85
No. 1 to Grant of Arizona Registration Statement on Form
Public Service Company 8-B
rights-of-way and easements,
Four Corners Power Plant Site
dated April 25, 1985
10.43 Indenture of Lease, Navajo 5(g) to APS' Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.44 Application and Grant of 5(h) to APS' Form S-7 2-36505 3-23-70
rights-of-way and easements, Registration Statement
Navajo Plant
10.45 Water Service Contract 5(1) to APS' Form S-7 2-394442 3-16-71
Assignment with the United Registration Statement
States Department of Interior,
Bureau of Reclamation,
Navajo Plant
10.46 Arizona Nuclear Power 10.1 to APS' 1988 Form 10-K 1-4473 3-8-89
Project Participation
Agreement, dated August 23, 1973,
among APS Salt River Project
Agricultural Improvement and
Power District, Southern California
Edison Company, Public Service
Company of New Mexico, El Paso
Electric Company, Southern California
Public Power Authority,
and Department of Water and Power of
the City of Los Angeles,
and amendments 1-12 thereto
66
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.47 Amendment No. 13, dated as 10.1 to APS' March 1991 Form 1-4473 5-15-91
of April 22, 1991, to Arizona 10-Q
Nuclear Power Project
Participation Agreement,
dated August 23, 1973,
among APS, Salt River
Project Agricultural
Improvement and Power
District, Southern California
Edison Company, Public
Service Company of New
Mexico, El Paso Electric
Company, Southern
California Public Power
Authority, and Department of
Water and Power of the City
of Los Angeles
10.48(c) Facility Lease, dated as of 4.3 to APS' 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 APS, as Lessee
10.49(c) Amendment No. 1, dated as 10.5 to APS' September 1986 1-4473 12-4-86
of November 1, 1986, to Form 10-Q Report by means of
Facility Lease, dated as of Amendment No. on December
August 1, 1986, between 3, 1986 Form 8
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and APS, as Lessee
10.50(c) Amendment No. 2 dated as of 10.3 to APS' 1988 Form 10-K 1-4473 3-8-89
June 1, 1987 to Facility 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
10.51(c) Amendment No. 3, dated as 10.3 to APS' 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Facility
Report Lease, dated as of August
1, 1986, between State Street
Bank and Trust Company, as
successor to The First National
Bank of Boston, as Lessor, and
APS, as Lessee
67
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.52 Facility Lease, dated as of 10.1 to APS' November 18 1-4473 1-20-87
December 15, 1986, between 1986 Form 8-K Report
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor,
and APS, as Lessee
10.53 Amendment No. 1, dated as 4.13 to APS' Form S-3 1-4473 8-24-87
of August 1, 1987, to Facility Registration Statement No.
Lease, dated as of December 33-9480 by means of August 1,
15, 1986, between State 1987 Form 8-K Report
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Lessor, and APS,
as Lessee
10.54 Amendment No. 2, dated as 10.4 to APS' 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Facility Lease, dated as of
December 15, 1986, between
State Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Lessor, and APS,
as Lessee
10.55(a) Directors' Deferred 10.1 to APS' June 1986 Form 1-4473 8-13-86
Compensation Plan, as 10-Q Report
restated, effective January 1,
1986
10.56(a) Second Amendment to the 10.2 to APS' 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.57(a) Third Amendment to the 10.1 to APS' September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q
Company Directors' Deferred
Compensation Plan, effective
as of May 1, 1993
10.58(a) Arizona Public Service 10.4 to APS' 1988 Form 10-K 1-4473 3-8-89
Company Deferred Report
Compensation Plan, as
restated, effective January 1,
1984, and the second and third
amendments thereto, dated December
22, 1986, and December 23,
1987 respectively
68
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.59 Third Amendment to the 10.3 to APS' 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.60(a) Fourth Amendment to the 10.2 to APS' September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q Report
Company Deferred
Compensation Plan effective
as of May 1, 1993
10.61(a) Fifth Amendment to the 10.3 to APS' 1996 Form 10-K 1-4473 3-28-97
Arizona Public Service Report
Company Deferred
Compensation Plan
10.62(a) Pinnacle West Capital 10.10 to APS' 1995 Form 10-K 1-4473 3-29-96
Corporation, Arizona Public Report
Service Company, SunCor
Development Company and
El Dorado Investment
Company Deferred
Compensation Plan as
amended and restated
effective January 1, 1996
10.63(a) Arizona Public Service 10.11 to APS' 1995 Form 10-K 1-4473 3-29-96
Company Supplemental Report
Excess Benefit Retirement
Plan as amended and restated
on December 20, 1995
10.64(a) Pinnacle West Capital 10.7 to APS' 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
10.65(a) Letter Agreement dated 10.7 to APS' 1994 Form 10-K 1-4473 3-30-96
December 21, 1993, between Report
APS and William L. Stewart
10.66(a) Letter Agreement dated as of 10.8 to APS' 1995 Form 10-K 1-4473 3-29-96
January 1, 1996 between APS Report
and Robert G. Matlock &
Associates, Inc. for
consulting services
10.67(a) Letter Agreement dated 10.8 to APS' 1996 Form 10-K 1-4473 3-28-97
August 16, 1996 between Report
APS and William L. Stewart
10.68(a) Letter Agreement between 10.2 to APS' September 1997 1-4473 11-12-97
APS and William L. Stewart Form 10-Q Report
69
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.69(ad) Key Executive Employment and 10.1 to June 1999 1-8962 8-16-99
Severance Agreement between Form 10-Q Report
Pinnacle West and certain
executive officers of Pinnacle
West and its subsidiaries
10.70(a) Pinnacle West Capital 10.1 to APS' 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option and Report
Incentive Plan
10.71(a) Pinnacle West Capital A to the Proxy Statement for the 1-8962 4-16-94
Corporation 1994 Long-Term Plan Report for the Company's
Incentive Plan, effective as of 1994 Annual Meeting of
March 23, 1994 Shareholders
10.72(a) Pinnacle West Capital B to the Proxy Statement for the 1-8962 4-16-94
Corporation Director Equity Plan Report for the Company's
Participation Plan 1994 Annual Meeting of
Shareholders
10.73 Agreement No. 13904 10.3 to APS' 1991 Form 10-K 1-4473 3-19-92
(Option and Purchase of Report
Effluent) with Cities of
Phoenix, Glendale, Mesa,
Scottsdale, Tempe, Town of
Youngtown, and Salt River
Project Agricultural
Improvement and
Power District, dated April 23, 1973
10.74 Agreement for the Sale and 10.4 to A PS' 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
10.75(a) First Amendment to 10.2 to the Company's 1995 1-8962 4-1-96
Employment Agreement, Form 10-K Report
effective March 31, 1995,
between Richard Snell and
the Company
10.76(a) Second Amendment to 10.2 to the Company's 1996 1-8962 3-31-97
Employment Agreement, Form 10-K Report
effective February 5, 1997,
between Richard Snell and
the Company
10.77(a) APS Director Equity Plan 10.1 to September 1997 Form 1-4473 11-12-97
10-Q Report
70
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
10.78 Territorial Agreement 10.1 to APS' March 1998 1-4473 5-15-98
between the Company Form 10-Q Report
and Salt River Project
10.79 Power Coordination 10.2 to APS' March 1998 1-4473 5-15-98
Agreement between Form 10-Q Report
the Company and Salt
River Project
10.80 Memorandum of Agreement 10.3 to APS' March 1998 1-4473 5-15-98
between the Company and Form 10-Q Report
Salt River Project
10.81 Addendum to Memorandum 10.2 to APS' May 19, 1998 1-4473 6-26-98
of Agreement between APS Form 8-K Report
and Salt River Project dated
as of May 19, 1998
99.1 Collateral Trust Indenture 4.2 to APS' 1992 Form 10 K 1-4473 3-30-93
among PVNGS II Funding Report
Corp., Inc., APS and
Chemical Bank, as Trustee
99.2 Supplemental Indenture to 4.3 to APS' 1992 Form 10 K 1-4473 3-30-93
Collateral Trust Indenture Report
among PVNGS II Funding
Corp., Inc., APS and
Chemical Bank, as Trustee
99.3(c) Participation Agreement, 28.1 to APS' 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, APS, and the Equity
Participant named therein
71
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
99.4(c) Amendment No. 1 dated as of 10.8 to APS' September 1986 1-4473 12-4-86
November 1, 1986, to Form 10-Q Report by means of
Participation Agreement, Amendment No. 1, on
dated as of August 1, 1986, December 3, 1986 Form 8
among PVNGS Funding
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, APS, and the Equity
Participant named therein
99.5(c) Amendment No. 2, dated as 28.4 to APS' 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Participation Agreement,
dated as of August 1, 1986,
among PVNGS Funding
Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and as
Indenture Trustee, APS, and
the Equity Participant named
therein
99.6(c) Trust Indenture, Mortgage, 4.5 to APS' Form S-3 33-9480 10-24-86
Security Agreement and 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
72
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
99.7(c) Supplemental Indenture No. 10.6 to APS' September 1986 1-4473 12-4-86
1, dated as of November 1, Form 10-Q Report by means of
1986 to Trust Indenture, Amendment No. 1 on December
Mortgage, Security 3, 1986 Form 8
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
99.8(c) Supplemental Indenture No. 2 28.14 to APS' 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture, Mortgage, Report
Security Agreement and
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Lease Indenture
Trustee
99.9(c) Assignment, Assumption and 28.3 to APS' Form S-3 33-9480 10-24-86
Further Agreement, dated as Registration Statement
of August 1, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.10(c) Amendment No. 1, dated as 10.10 to APS' September 1986 1-4473 12-4-86
of November 1, 1986, to Form 10-Q Report by means of
Assignment, Assumption and Amendment No. l on December
Further Agreement, dated as 3, 1986 Form 8
of August 1, 1986, between
APS and State Street Bank
and Trust Company,
as successor to The First
National Bank of Boston, as
Owner Trustee
99.11(c) Amendment No. 2, dated as 28.6 to APS' 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
APS and State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
73
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
99.12 Participation Agreement, 28.2 to APS' September 1992 1-4473 11-9-92
dated as of December 15, Form 10-Q Report
1986, among PVNGS Funding Report
Corp., Inc., State Street Bank
and Trust Company, as successor
to The First National Bank of
Boston, in its individual capacity
and as Owner Trustee,
Chemical Bank, in its individual
capacity and as Indenture
Trustee under a Trust Indenture,
APS, and the Owner Participant
named therein
99.13 Amendment No. 1, dated as 28.20 to APS' Form S-3 1-4473 8-10-87
of August 1, 1987, to Registration Statement No.
Participation Agreement, 33-9480 by means of a
dated as of December 15, November 6, 1986 Form 8-K
1986, among PVNGS Report
Funding Corp., Inc. as
Funding Corporation, State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, as Owner Trustee,
Chemical Bank, as Indenture
Trustee, APS, and the Owner
Participant named therein
99.14 Amendment No. 2, dated as 28.5 to APS' 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS
Funding Corp., Inc., PVNGS
II Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to
The First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in
its individual capacity and as
Indenture Trustee, APS, and
the Owner Participant named
therein
74
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
99.15 Trust Indenture, Mortgage 10.2 to APS' November 18, 1-4473 1-20-87
Security Agreement and 1986 Form 10-K Report
Assignment of Facility Lease,
dated as of December 15,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.16 Supplemental Indenture No. 4.13 to APS' Form S-3 1-4473 8-24-87
1, dated as of August 1, 1987, Registration Statement No.
to Trust Indenture, Mortgage, 33-9480 by means of August 1,
Security Agreement and 1987 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
99.17 Supplemental Indenture No. 2 4.5 to APS' 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture Mortgage, Report
Security Agreement and
Assignment of Facility Lease,
dated as of December 15,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Lease Indenture
Trustee
99.18 Assignment, Assumption and 10.5 to APS' November 18, 1-4473 1-20-87
Further Agreement, dated as 1986 Form 8-K Report
of December 15, 1986,
between APS and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.19 Amendment No. 1, dated as 28.7 to APS' 1992 Form 10-K 1-4473 3-30-93
of March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of December 15, 1986,
between APS and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
75
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Exhibit No. Description Originally Filed as Exhibit: File No.b Date Effective
----------- ----------- ---------------------------- -------- --------------
99.20(c) Indemnity Agreement dated 28.3 to APS' 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993 by APS Report
99.21 Extension Letter, dated as of 28.20 to APS' Form S-3 1-4473 8-10-87
August 13, 1987, from the Registration Statement No.
signatories of the 33-9480 by means of a
Participation Agreement to November 6, 1986 Form 8-K
Chemical Bank Report
99.22 Arizona Corporation 28.1 to APS' 1991 Form 10-K 1-4473 3-19-92
Commission Order dated Report
December 6, 1991
99.23 Arizona Corporation 10.1 to APS' June 1994 form 1-4473 8-12-94
Commission Order dated 10-Q Report
June 1, 1994
99.24 Rate Reduction Agreement 10.1 to APS' December 4, 1995 1-4473 12-14-95
dated December 4, 1995 8-K Report
between APS and the ACC
Staff
99.25 ACC Order dated April 24, 10.1 to APS' March 1996 Form 1-4473 5-14-96
1996 10-Q Report
99.26 Arizona Corporation 99.1 to APS' 1996 Form 10-K 1-4473 3-28-97
Commission Order, Decision Report
No. 59943, dated December
26, 1996, including the Rules
regarding the introduction of
retail competition in Arizona
99.27 Retail Electric 10.1 to APS' June 1998 1-4473 8-14-98
Competition Rules Form 10-Q Report
99.28 Arizona Corporation Commission 10.1 to APS' September 1-4473 11-15-99
Order, Decision No. 61973, dated 1999 10-Q Report
October 6, 1999, approving APS'
Settlement Agreement
99.29 Arizona Corporation Commission 10.2 to APS' September 1-4473 11-15-99
Order, Decision No. 61969, dated 1999 10-Q Report
September 29, 1999, including the
Retail Electric Competition Rules
76
----------
(a) Management contract or compensatory plan or arrangement to be filed as an
exhibit pursuant to Item 14(c) of Form 10-K.
(b) Reports filed under File No. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
(c) An additional document, substantially identical in all material respects to
this Exhibit, has been entered into, relating to an additional Equity
Participant. Although such additional document may differ in other respects
(such as dollar amounts, percentages, tax indemnity matters, and dates of
execution), there are no material details in which such document differs
from this Exhibit.
(d) Additional agreements, substantially identical in all material respects to
this Exhibit have been entered into with additional persons. Although such
additional documents may differ in other respects (such as dollar amounts
and dates of execution), there are no material details in which such
agreements differ from this Exhibit.
REPORTS ON FORM 8-K
During the quarter ended December 31, 1999, and the period ended March 29, 2000,
the Company filed the following Report on Form 8-K:
Report dated September 29, 1999 regarding our plan to construct an electric
generating plant of up to 2,120 megawatts near Palo Verde.
77
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Date: March 29, 2000 William J. Post
----------------------------------------
(William J. Post, President
and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
William J. Post Principal Executive March 29, 2000
-------------------------------------- Officer and Director
(William J. Post, President and
Chief Executive Officer)
Michael V. Palmeri Principal Financial March 29, 2000
-------------------------------------- Officer
(Michael V. Palmeri, Vice President,
Finance)
Chris N. Froggatt Principal Accounting March 29, 2000
-------------------------------------- Officer
(Chris N. Froggatt, Vice President
and Controller)
Richard Snell Director March 29, 2000
--------------------------------------
(Richard Snell, Chairman of the
Board of Directors)
Edward N. Basha, Jr. Director March 29, 2000
--------------------------------------
(Edward N. Basha, Jr.)
Michael L. Gallagher Director March 29, 2000
--------------------------------------
(Michael L. Gallagher)
Pamela Grant Director March 29, 2000
--------------------------------------
(Pamela Grant)
Roy A. Herberger, Jr. Director March 29, 2000
--------------------------------------
(Roy A. Herberger, Jr.)
78
Martha O. Hesse Director March 29, 2000
--------------------------------------
(Martha O. Hesse)
William S. Jamieson, Jr. Director March 29, 2000
--------------------------------------
(William S. Jamieson, Jr.)
Humberto S. Lopez Director March 29, 2000
--------------------------------------
(Humberto S. Lopez)
79
Commission File Number 1-8962
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------
EXHIBITS TO
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
--------------------
Pinnacle West Capital Corporation
(Exact name of registrant as specified in charter)
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
INDEX TO EXHIBITS
Exhibit No. Description
----------- -----------
10.1(a) 2000 Management Variable Incentive Plan (Pinnacle West)
10.2(a) 2000 Senior Management Variable Incentive Plan (Pinnacle West)
10.3(a) 2000 Officer Variable Incentive Plan (Pinnacle West)
10.4(a) 2000 Management Variable Incentive Plan (APS)
10.5(a) 2000 Senior Management Variable Incentive Plan (APS)
10.6(a) 2000 Officers Variable Incentive Plan (APS)
10.7(a) First Amendment effective as of January 1, 1999, to the Pinnacle
West Capital Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company Deferred
Compensation Plan
10.8(a) Fourth Amendment dated December 28, 1999 to the Arizona Public
Service Company Directors Deferred Compensation Plan
10.9(a) Letter Agreement dated December 13, 1999 between APS and William
L. Stewart
10.10(a) Second Amendment effective January 1, 2000 to the Pinnacle West
Capital Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company Deferred
Compensation Plan
10.11(a) First Amendment dated December 7, 1999 to the Pinnacle West
Capital Corporation Stock Option and Incentive Plan
10.12(a) First Amendment dated December 7, 1999 to the Pinnacle West
Capital Corporation 1994 Long-Term Incentive Plan
10.13(a) Pinnacle West Capital Corporation Supplemental Excess Benefit
Retirement Plan, as amended and restated, dated December 7, 1999
10.14(a) Trust for the Pinnacle West Capital Corporation, Arizona Public
Service Company and SunCor Development Company Deferred
Compensation Plans dated August 1, 1996
10.15(a) First Amendment dated December 7, 1999 to the Trust for the
Pinnacle West Capital Corporation, Arizona Public Service Company
and SunCor Development Company Deferred Compensation Plans
10.16(a) Letter Agreement dated July 28, 1995 between Arizona Public
Service Company and Armando B. Flores
10.17(a) Letter Agreement dated October 3, 1997 between Arizona Public
Service Company and James M. Levine
21 Subsidiaries of the Company
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.
Dates Referenced Herein and Documents Incorporated by Reference
| Referenced-On Page |
|---|
| This ‘10-K’ Filing | | Date | | First | | Last | | | Other Filings |
|---|
| |  |
| | 12/31/04 | | 42 | | | | | 10-K, 11-K, 8-K, U-3A-2 |
| | 7/1/04 | | 42 | | | | | 4 |
| | 6/30/04 | | 5 | | 54 | | | 10-Q, 8-K |
| | 1/1/04 | | 42 |
| | 7/1/03 | | 27 | | 41 | | | 4, 4/A |
| | 12/31/02 | | 42 | | 43 | | | 10-K, 11-K, 5, 8-K, U-3A-2 |
| | 1/1/01 | | 42 | | 43 |
| | 12/31/00 | | 43 | | | | | 10-K, 11-K, U-3A-2 |
| | 5/17/00 | | 1 | | 60 | | | 3, DEF 14A |
| Filed as of: | | 3/30/00 |
| Filed on: | | 3/29/00 | | 79 | | 81 |
| | 3/27/00 | | 1 | | 22 |
| | 3/17/00 | | 42 |
| | 3/1/00 | | 20 |
| | 2/18/00 | | 34 |
| | 1/14/00 | | 42 |
| | 1/1/00 | | 10 | | 83 |
| For Period End: | | 12/31/99 | | 1 | | 82 | | | 11-K, 5, U-3A-2 |
| | 12/28/99 | | 61 | | 83 |
| | 12/15/99 | | 62 |
| | 12/13/99 | | 41 | | 83 |
| | 12/8/99 | | 42 |
| | 12/7/99 | | 61 | | 83 |
| | 11/2/99 | | 64 |
| | 11/1/99 | | 64 |
| | 10/6/99 | | 78 |
| | 9/30/99 | | 55 | | | | | 10-Q |
| | 9/29/99 | | 78 | | 79 | | | 8-K |
| | 9/24/99 | | 42 |
| | 9/23/99 | | 41 |
| | 9/21/99 | | 42 | | | | | 8-K |
| | 8/24/99 | | 15 |
| | 7/1/99 | | 27 | | 43 |
| | 5/14/99 | | 41 | | | | | 8-K |
| | 4/22/99 | | 10 |
| | 4/15/99 | | 12 |
| | 3/1/99 | | 47 | | | | | U-3A-2 |
| | 2/19/99 | | 12 |
| | 2/18/99 | | 44 | | 64 |
| | 2/15/99 | | 64 |
| | 1/1/99 | | 43 | | 83 |
| | 12/31/98 | | 28 | | 60 | | | 10-K405, 11-K, U-3A-2 |
| | 11/23/98 | | 16 |
| | 9/30/98 | | 55 | | | | | 10-Q |
| | 8/28/98 | | 19 |
| | 7/1/98 | | 28 | | 43 |
| | 5/19/98 | | 73 |
| | 5/5/98 | | 8 |
| | 4/25/98 | | 44 |
| | 4/10/98 | | 12 |
| | 1/31/98 | | 7 | | 8 |
| | 1/15/98 | | 64 |
| | 1/13/98 | | 64 |
| | 12/31/97 | | 57 | | 60 | | | 10-K405, 11-K, 4, 5, U-3A-2 |
| | 12/15/97 | | 21 |
| | 10/3/97 | | 62 | | 83 |
| | 7/1/97 | | 28 | | 43 | | | 4 |
| | 4/7/97 | | 63 |
| | 2/14/97 | | 10 | | | | | 5 |
| | 2/5/97 | | 72 |
| | 12/26/96 | | 78 |
| | 12/17/96 | | 7 |
| | 11/19/96 | | 62 | | 63 |
| | 11/15/96 | | 63 |
| | 8/16/96 | | 71 |
| | 8/1/96 | | 61 | | 83 |
| | 7/9/96 | | 5 |
| | 7/1/96 | | 28 | | 43 |
| | 6/10/96 | | 10 |
| | 1/1/96 | | 71 |
| | 12/20/95 | | 71 |
| | 10/18/95 | | 12 |
| | 10/17/95 | | 11 |
| | 10/13/95 | | 11 |
| | 7/28/95 | | 62 | | 83 |
| | 5/5/95 | | 67 |
| | 4/5/95 | | 67 |
| | 3/31/95 | | 72 | | | | | 10-K, 10-Q, POS AM |
| | 1/1/95 | | 57 | | 71 |
| | 12/1/94 | | 65 |
| | 11/1/94 | | 66 |
| | 6/1/94 | | 78 |
| | 3/23/94 | | 72 |
| | 3/2/94 | | 67 |
| | 2/23/94 | | 62 |
| | 12/21/93 | | 71 |
| | 5/1/93 | | 70 | | 71 |
| | 3/17/93 | | 69 | | 78 |
| | 1/1/93 | | 70 | | 71 |
| | 11/1/92 | | 66 |
| | 1/31/92 | | 66 |
| List all Filings |
4 Subsequent Filings that Reference this Filing
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