SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission File Number 1-4473
Arizona Public Service Company
(Exact name of registrant as specified in its charter)
ARIZONA 86-0011170
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999 (602) 250-1000
(Address of principal executive offices, (Registrant's telephone number,
including zip code) including area code)
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Securities registered pursuant to Section 12(b)
of the Act:
Name of each exchange on
Title of each class which registered
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Adjustable Rate Cumulative Preferred Stock,
Series Q, $100 Par Value ..........................New York Stock Exchange
$1.8125 Cumulative Preferred Stock,
Series W, $25 Par Value ...........................New York Stock Exchange
10% Junior Subordinated Deferrable Interest
Debentures, Series A, Due 2025 ....................New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock
(Title of class)
(See Note 4 of Notes to Financial Statements in Item 8
for dividend rates, series designations (if any), and par values)
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. [ X ]
Aggregate Market Value
of Voting Stock Held by
Non-affiliates of the
Title of Each Class Shares Outstanding registrant as of
of Voting Stock as of March 11, 1998 March 11, 1998
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Cumulative Preferred Stock ........ 3,518,051 $147,000,000(a)
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(a) Computed, with respect to shares listed on the New York Stock Exchange, by
reference to the closing price on the composite tape on March 11, 1998, as
reported by The Wall Street Journal, and with respect to non-listed shares, by
determining the yield on listed shares and assuming a market value for
non-listed shares which would result in that same yield.
As of March 11, 1998, there were issued and outstanding 71,264,947 shares
of the registrant's common stock, $2.50 par value, all of which were held
beneficially and of record by Pinnacle West Capital Corporation.
Documents Incorporated by Reference
Portions of the registrant's definitive proxy statement relating to its
annual meeting of shareholders to be held on May 19, 1998, are incorporated by
reference into Part III hereof.
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TABLE OF CONTENTS
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Page
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GLOSSARY............................................................................................ 1
PART I
Item 1. Business............................................................................... 3
Item 2. Properties............................................................................. 12
Item 3. Legal Proceedings...................................................................... 15
Item 4. Submission of Matters to a Vote of Security Holders.................................... 15
Supplemental Item.
Executive Officers of the Registrant................................................... 16
PART II
Item 5. Market for Registrant's Common Stock and Related Security Holder Matters............... 17
Item 6. Selected Financial Data................................................................ 18
Item 7. Financial Review....................................................................... 19
Item 8. Financial Statements and Supplementary Data............................................ 24
Item 9. Changes In and Disagreements with Accountants on Accounting
and Financial Disclosure............................................................... 50
PART III
Item 10. Directors and Executive Officers of the Registrant..................................... 50
Item 11. Executive Compensation................................................................. 50
Item 12. Security Ownership of Certain Beneficial Owners and Management......................... 50
Item 13. Certain Relationships and Related Transactions......................................... 50
PART IV
Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
and Reports on Form 8-K................................................................ 51
SIGNATURES........................................................................................... 71
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GLOSSARY
ACC --- Arizona Corporation Commission
ACC Staff --- Staff of the Arizona Corporation Commission
AFUDC --- Allowance for Funds Used During Construction
Amendments --- Clean Air Act Amendments of 1990
ANPP --- Arizona Nuclear Power Project, also known as Palo Verde
APS --- Arizona Public Service Company
CC&N --- Certificate of convenience and necessity
Cholla --- Cholla Power Plant
Cholla 4 --- Unit 4 of the Cholla Power Plant
Company --- Arizona Public Service Company
CUC --- Citizens Utilities Company
DOE --- United States Department of Energy
EITF --- Emerging Issues Task Force
EITF 97-4 --- Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity --- Issues Related to the Applications of FASB Statements
No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises --- Accounting for the Discontinuation of Application of
FASB Statement No. 71"
Energy Act --- National Energy Policy Act of 1992
EPA --- United States Environmental Protection Agency
FASB --- Financial Accounting Standards Board
FERC --- Federal Energy Regulatory Commission
Four Corners --- Four Corners Power Plant
GAAP --- Generally accepted accounting principles
ITC --- Investment tax credit
kW --- Kilowatt, one thousand watts
kWh --- Kilowatt-hour, one thousand watts per hour
Mortgage --- Mortgage and Deed of Trust, dated as of July 1, 1946, as
supplemented and amended
MWh --- Megawatt hours, one million watts per hour
1935 Act --- Public Utility Holding Company Act of 1935
NGS --- Navajo Generating Station
NRC --- Nuclear Regulatory Commission
PacifiCorp --- An Oregon-based utility company
Palo Verde --- Palo Verde Nuclear Generating Station
Pinnacle West --- Pinnacle West Capital Corporation, an Arizona corporation, the
Company's parent
SEC --- Securities and Exchange Commission
SFAS No. 34 --- Statement of Financial Accounting Standards No. 34,
"Capitalization of Interest Cost"
SFAS No. 71 --- Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
SFAS No. 123 --- Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation"
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SFAS No. 130 --- Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income"
SFAS No. 131 --- Statement of Financial Accounting Standards No. 131,
"Disclosures about Segments of an Enterprise and Related Information"
SFAS No. 132 --- Statement of Financial Accounting Standards No. 132,
"Employers' Disclosures about Pensions and Other Postretirement Benefits"
SRP --- Salt River Project Agricultural Improvement and Power District
USEC --- United States Enrichment Corporation
Waste Act --- Nuclear Waste Policy Act of 1982, as amended
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PART I
ITEM 1. BUSINESS
The Company
The Company was incorporated in 1920 under the laws of Arizona and is
engaged principally in serving electricity in the State of Arizona. The
principal executive offices of the Company are located at 400 North Fifth
Street, Phoenix, Arizona 85004 (telephone 602-250-1000). Pinnacle West owns all
of the outstanding shares of the Company's common stock.
The Company is Arizona's largest electric utility, with 767,000 customers,
and 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
1997, no single purchaser or user of energy accounted for more than 2% of total
electric revenues. At December 31, 1997, the Company employed 5,981 people,
which includes employees assigned to joint projects where the Company is project
manager.
This document contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax and environmental
legislation; the ability of the Company 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; and technological developments in the electric
industry. See "Competition" in this Item for a discussion of some of these
factors.
Competition
Retail
General. Under current law, the Company is not in direct competition with
any other regulated electric utility for electric service in the Company's
retail service territory. Nevertheless, the Company is subject to varying
degrees of competition in certain territories adjacent to or within areas that
it 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 SRP).
The Company 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. The
legislatures and/or the regulatory commissions in most states have considered or
are considering "retail wheeling." This requirement to transmit directly to
retail customers could have the result of allowing retail customers to choose to
purchase electric capacity and energy from the electric utility in whose service
area they are located or from other electric utilities or independent power
producers or power marketers.
ACC Rules Regarding Arizona Electric Industry Restructuring. The ACC Staff
has been conducting an ongoing investigation into the restructuring of the
Arizona electric industry. In December 1996, the ACC adopted rules that provide
a framework for the introduction of retail electric competition in Arizona in
phases from 1999 to 2003. The ACC ordered in the rules that numerous issues
require additional consideration prior to the implementation of retail electric
competition in Arizona. During 1997, the ACC held workshops to gather input from
various constituencies with respect to those issues.
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The rules indicate that the ACC will allow recovery of unmitigated stranded
costs, but do not set forth the mechanisms for determining and recovering such
costs. In February 1998, the ACC completed a formal, generic hearing on stranded
cost determination and recovery. Based on various assumptions, estimates and
methodologies, the Company currently estimates that its stranded costs to be
recovered (excluding regulatory assets which have already been addressed by the
ACC) will be less than $500 million. The Company is seeking full recovery of
stranded costs during a transition period proposed to go through 2006. Decisions
by the ACC have not yet been made with respect to this issue.
An Arizona joint legislative committee studied electric utility industry
restructuring issues in 1996 and 1997. In conjunction with that study, Arizona
legislative counsel prepared memoranda in late 1997 related to the legal
authority of the ACC to deregulate the Arizona electric utility industry. The
memoranda raise a question as to the degree to which the ACC may, under the
Arizona Constitution, deregulate any portion of the electric utility industry
and allow rates to be determined by market forces. In February 1998, a bill was
introduced in the Arizona legislature to facilitate implementation of retail
electric competition in the state. The bill has progressed through several
stages to date. The bill includes, among other things, a proposal that the ACC
adopt provisions for public service corporations substantially consistent with
some of the bill's provisions for certain government-operated electric
utilities. The Company continues to believe that legislation and perhaps
amendments to the Arizona Constitution will ultimately be required before
significant implementation of retail electric competition can lawfully occur in
Arizona.
See Note 3 of Notes to Financial Statements for additional information
regarding the rules and other regulatory and legal issues relating to the
electric industry restructuring.
Wholesale
General. The Company competes with other utilities, power marketers, and
independent power producers in the sale of electric capacity and energy in the
wholesale market. The Company expects that competition to sell capacity will
remain vigorous, and that wholesale prices will remain depressed for at least
the next several years due to increased competition and surplus capacity in the
western United States. The Company's rates for wholesale power sales and
transmission services are subject to regulation by the FERC. During 1997,
approximately 13% of the Company's electric operating revenues resulted from
such sales and charges.
The National Energy Policy Act of 1992 (the "Energy Act") has promoted
increased competition in the wholesale electric power markets. The Energy Act
reformed provisions of the Public Utility Holding Company Act of 1935 (the "1935
Act") and the Federal Power Act to remove certain barriers to competition for
the supply of electricity. For example, the Energy Act permits the FERC to order
transmission access for third parties to transmission facilities owned by
another entity so that independent suppliers and other third parties can sell at
wholesale to customers wherever located. The Energy Act does not, however,
permit the FERC to issue an order requiring transmission access to retail
customers.
Effective July 9, 1996, a FERC decision requires all electric utilities
subject to the FERC's jurisdiction to file transmission tariffs which provide
competitors with access to transmission facilities comparable to the
transmission owners' access for wholesale transactions, establishes information
requirements and provides for recovery of certain wholesale stranded costs.
Retail stranded costs resulting from a state-authorized retail direct-access
program are the responsibility of the states, unless a state lacks authority to
impose rates to recover such costs, in which case FERC will consider doing so.
The Company has filed its revised open access tariff in accordance with this
decision. The Company does not believe that this decision will have a material
adverse impact on its results of operations or financial position.
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Federal Regulation
Several electric utility reform bills have been introduced during recent
Congressional sessions, which as currently written, would allow consumers to
choose their electric supplier by 2000 or 2003. These bills, other bills that
are expected to be introduced, and ongoing discussions at the federal level
suggest a wide range of opinion that will need to be narrowed before any
substantial restructuring of the electric utility industry can occur.
Regulatory Assets
The Company's major regulatory assets are deferred income taxes and rate
synchronization cost deferrals. These items, combined with miscellaneous
regulatory assets and liabilities, amounted to approximately $1.0 billion at
December 31, 1997. In accordance with a 1996 regulatory agreement, the ACC
accelerated the amortization of substantially all of the Company's regulatory
assets to an eight-year period beginning July 1, 1996. The Company's existing
regulatory orders and current regulatory environment support its accounting
practices related to regulatory assets. If rate recovery of these assets is no
longer probable, whether due to competition or regulatory action, the Company
would no longer be able to apply the provisions of SFAS No. 71 to all or some
part of its operations which could have a material impact on the Company's
financial statements. See Notes 1, 3 and 10 of Notes to Financial Statements in
Item 8 for additional information.
Competitive Strategies
The Company 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 the
Company's 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
the Company's capital structure and financial condition; (vi) leveraging core
competencies into related areas, such as energy management products and
services; and (vii) establishing a trading floor and implementing a risk
management program to provide for more stability of prices and the ability to
retain or grow incremental margin through more competitive pricing and risk
management. Underpinning the Company's competitive strategies are the strong
growth characteristics of the Company's service territory. As competition in the
electric utility industry continues to evolve, the Company will continue to
evaluate strategies and alternatives that will position the Company to compete
effectively in a more competitive, restructured industry.
Generating Fuel and Purchased Power
1997 Energy Mix
The Company's sources of energy during 1997 were: coal - 36.5%; nuclear -
28.2%; other - 3.1%; and purchased power - 32.2%.
Coal Supply
The Company believes that Cholla has sufficient reserves of low sulfur coal
committed to the plant for the next two years, the term of the existing coal
contract. In 1997, the current supplier experienced production and delivery
problems that required Cholla to purchase coal from the spot market. The current
supplier is expected to continue to provide substantially all of Cholla's low
sulfur coal requirements. Contract renegotiation with the current supplier is in
progress. The current supplier has sufficient reserves of low sulfur coal
available to allow the continued operation of Cholla for its useful life. The
Company also believes that Four Corners and NGS have sufficient reserves of low
sulfur coal available for use by those plants to continue operating them for
their useful lives.
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The current sulfur content of coal being used at Four Corners, NGS and
Cholla is approximately 0.78%, 0.55% and 0.44%, respectively. In 1997, average
prices paid for coal supplied from the reserves dedicated under the existing
contracts were comparable to 1996. Escalation components of existing long-term
coal contracts impact future coal prices. In addition, major price adjustments
can occur from time to time as a result of contract renegotiation.
NGS and Four Corners are located on the Navajo Reservation and held under
easements granted by the federal government as well as leases from the Navajo
Nation. See "Properties- Plant Sites Leased from the Navajo Nation" in Item 2.
The Company purchases all of the coal which fuels Four Corners from a coal
supplier with a long-term lease of coal reserves owned by the Navajo Nation and
for NGS from a coal supplier with a long-term lease with the Navajo Nation and
the Hopi Tribe. Coal is supplied to Cholla from a coal supplier who mines all of
the coal under a long-term lease of coal reserves owned by the Navajo Nation,
the federal government, and private landholders. See Note 12 of Notes to
Financial Statements in Item 8 for information regarding the Company's
obligation for coal mine reclamation.
Natural Gas Supply
The Company is a party to contracts with a number of natural gas operators
and marketers which allow the Company to purchase natural gas in the method it
determines to be most economic. The Company is currently purchasing the majority
of its natural gas requirements from twelve companies pursuant to contracts. The
Company's natural gas supply is transported pursuant to a firm transportation
service contract between the Company and El Paso Natural Gas Company. The
Company continues to analyze the market to determine the source and method of
meeting its natural gas requirements.
Nuclear Fuel Supply
The fuel cycle for Palo Verde is comprised of the following stages: (1) the
mining and milling of uranium ore to produce uranium concentrates, (2) the
conversion of uranium concentrates to uranium hexafluoride, (3) the enrichment
of uranium hexafluoride, (4) the fabrication of fuel assemblies, (5) the
utilization of fuel assemblies in reactors and (6) the storage of spent fuel and
the disposal thereof. The Palo Verde participants have made arrangements through
contract flexibilities to obtain quantities of uranium concentrates anticipated
to be sufficient to meet operational requirements through 2000. Existing
contracts and options could be utilized to meet approximately 80% of
requirements in 2001 and 2002 and 50% of requirements from 2003 through 2007.
Spot purchases in the uranium market will be made, as appropriate, in lieu of
any uranium that might be obtained through contract flexibilities and options.
The Palo Verde participants have contracted for all conversion services required
through 1998 and for up to 60% through 2002. The Palo Verde participants,
including the Company, have an enrichment services contract with USEC which
obligates USEC to furnish enrichment services required for the operation of the
three Palo Verde units over a term expiring in September 2002, with options to
continue through September 2007. In addition, existing contracts will provide
fuel assembly fabrication services until at least 2003 for each Palo Verde unit,
and through contract options, approximately fifteen additional years are
available.
Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy
Act of 1982, as amended in 1987 (the "Waste Act"), DOE is obligated to accept
and dispose of all spent nuclear fuel and other high-level radioactive wastes
generated by all domestic power reactors. The NRC, pursuant to the Waste Act,
requires operators of nuclear power reactors to enter into spent fuel disposal
contracts with DOE, and the Company, on its own behalf and on behalf of the
other Palo Verde participants, has done so. 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, but 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
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later than January 31, 1998. By way of letter dated December 17, 1996, DOE
informed contract holders, including the Company, that DOE anticipates that it
will be unable to begin acceptance of spent nuclear fuel for disposal in a
repository or interim storage facility by January 31, 1998. In November 1997,
the D.C. Circuit issued a Writ of Mandamus precluding DOE from excusing its own
delay on the grounds that DOE has not yet prepared a permanent repository or
interim storage facility. Several bills have been introduced in Congress
contemplating the construction of a central interim storage facility which could
be available in the latter part of the current decade; 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) and,
according to DOE spokespersons, 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.
The Company 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, 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. One way or another,
the Company currently 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, the Company is currently
shipping low-level waste to off-site facilities. The Company 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.
While believing that scientific and financial aspects of the issues of
spent fuel and low-level waste storage and disposal can be resolved
satisfactorily, the Company acknowledges that their ultimate resolution in a
timely fashion will require political resolve and action on national and
regional scales which it is less able to predict.
Purchased Power Agreements
In addition to that available from its own generating capacity (see
"Properties" in Item 2), the Company purchases electricity from other utilities
under various arrangements. One of the most important of these is a long-term
contract with SRP which may be canceled by SRP on three years' notice and which
requires SRP to make available, and the Company to pay for, certain amounts of
electricity that are based in large part on customer demand within certain areas
now served by the Company pursuant to a related territorial agreement. The
generating capacity available to the Company pursuant to the contract was 297 MW
through May 1997, at which time the capacity decreased to 292 MW. In 1997, the
Company received approximately 610,400 MWh of energy under the contract and paid
approximately $37 million for capacity availability and energy received.
In September 1990, the Company and PacifiCorp entered into certain
agreements relating principally to sales and purchases of electric power and
electric utility assets, and in July 1991 the Company sold Cholla 4 to
PacifiCorp. As part of the transaction, PacifiCorp agreed to make a firm system
sale to the Company for thirty years during the Company's summer peak season in
the amount of 175 megawatts for the first five years, increasing thereafter, at
the Company's option, up to a maximum amount equal to the rated capacity of
Cholla 4 (380 megawatts). The Company also had the option to convert these firm
system sales to one-for-one seasonal capacity exchanges with PacifiCorp. The
Company's agreements with PacifiCorp currently provide for the following Company
purchases and one-for-one seasonal capacity exchanges during the indicated
years: 1998 (175 megawatt firm capacity purchase, converting to capacity
exchange in the summer of 1998; and 100 megawatt
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capacity exchange); 1999 and beyond (275 megawatt capacity exchange; and 205
megawatt capacity exchange beginning in the summer of 1999). In 1997, the
generating capacity available to the Company from PacifiCorp was 175 MW. The
Company received approximately 486,000 MWh of energy and paid approximately
$17.4 million for capacity availability and the energy received.
During 1996, the Company entered into an agreement with Citizens Utilities
Company to build, own, operate and maintain a combustion turbine in northwest
Arizona. Pursuant to a twenty-year purchase power agreement, the Company will
recover the cost of the turbine and CUC will pay for the output requested by
CUC. The Company has the right to secondary use of the output for cost of fuel
and variable operations and maintenance. The Company expects that the combustion
turbine will be in service during the first quarter of 2001.
Construction Program
During the years 1995 through 1997, the Company incurred approximately $824
million in capitalized expenditures. Utility capitalized expenditures for the
years 1998 through 2000 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 1998 through
2000 have been estimated as follows:
(Millions of Dollars)
By Year By Major Facilities
- -------------------------------- ----------------------------------------
1998 $323 Production $235
1999 313 Transmission and Distribution 565
2000 306 General 119
---- Other Projects 23
$942 ----
==== $942
====
The amounts for 1998 through 2000 exclude capitalized interest costs and
include capitalized property taxes and about $30- $35 million each year for
nuclear fuel. The Company conducts a continuing review of its construction
program.
Mortgage Replacement Fund Requirements
So long as any of the Company's first mortgage bonds are outstanding, the
Company is required for each calendar year to deposit with the trustee under its
Mortgage cash in a formularized amount related to net additions to the Company's
mortgaged utility plant; however, the Company may satisfy all or any part of
this "replacement fund" requirement by utilizing redeemed or retired bonds, net
property additions, or property retirements. For 1997, the replacement fund
requirement amounted to approximately $134 million. All of the bonds issued by
the Company under the Mortgage which are callable prior to maturity are
redeemable at their par value plus accrued interest with cash deposited by the
Company in the replacement fund, subject in many cases to a period of time after
the original issuance of the bonds during which they may not be so redeemed
and/or to other restrictions on any such redemption.
Environmental Matters
EPA Environmental Regulation
Clean Air Act. Pursuant to the 1977 amendments to the Clean Air Act, the
EPA adopted regulations that address visibility impairment in certain
federally-protected areas which can be reasonably attributed to specific
sources. In September 1991, the EPA issued a final rule that would limit sulfur
dioxide emissions at NGS. Compliance with the emission limitation became
applicable to one NGS unit in 1997 and becomes applicable to another unit in
1998 and to the last unit in 1999. SRP, the NGS operating agent, has estimated a
capital cost of
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$440 million and annual operations and maintenance costs of approximately $14
million for all three units, for NGS to meet these requirements. The Company is
required to fund 14% of these expenditures. Approximately 80% of these capital
costs have been incurred through 1997.
The Clean Air Act Amendments of 1990 (the "Amendments") address, among
other things, "acid rain," visibility in certain specified areas, toxic air
pollutants and the nonattainment of national ambient air quality standards. With
respect to "acid rain," the Amendments establish a system of sulfur dioxide
emissions "allowances." Each existing utility unit is granted a certain number
of "allowances." For Phase II plants, which includes Company-owned plants,
allowances will be required beginning in the year 2000 to operate the plants. On
March 5, 1993, the EPA promulgated rules listing allowance allocations
applicable to Company-owned plants. Based on those allocations, the Company will
have sufficient allowances to permit continued operation of its plants at
current levels without installing additional equipment. In addition, the
Amendments require the EPA to set nitrogen oxides emissions limitations which
would require certain plants to install additional pollution control equipment.
In December 1996, the EPA issued rules for nitrogen oxides emissions limitations
that may require the Company to install additional pollution control equipment
at Four Corners by January 1, 2000. Based on its initial evaluation, the Company
currently estimates its capital cost of complying with the rules may be
approximately $4 million. On February 14, 1997, the Company filed a Petition for
Review in the United States Court of Appeals for the District of Columbia
alleging 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. The Company cannot currently
predict how the EPA will respond.
With respect to protection of visibility in certain specified areas, the
Amendments require the EPA to conduct a study concerning visibility impairment
in those areas and identification of sources contributing to such impairment.
Interim findings of this study have indicated that any beneficial effect on
visibility as a result of the Amendments would be offset by expected population
and industry growth. The EPA has established a "Grand Canyon Visibility
Transport Commission" to complete a study on visibility impairment in the
"Golden Circle of National Parks" in the Colorado Plateau. NGS, Cholla and Four
Corners are located near the "Golden Circle of National Parks." The Commission
completed its study and on June 10, 1996 submitted its final recommendations to
the EPA. The Commission recommended that, beginning in 2000 and every 5 years
thereafter, if actual sulfur dioxide emissions from all stationary sources in an
eight-state region (including Arizona, New Mexico, Utah, Nevada and California)
exceed the projected emissions, which are projected to decline under the current
regulatory scheme, the projected total emissions will be changed to a "regional
emissions cap" and an emissions trading program would be implemented to limit
total sulfur dioxide emissions in the region. The EPA will consider these
recommendations before promulgating final requirements on a regional haze
regulatory program which is under EPA review, which is expected by June 1998. If
such a program were implemented, industry, including the Company's coal plants,
could be subject to further emissions limits. The Company cannot currently
estimate the capital expenditures, if any, which may be required as a result of
the EPA studies and the Commission's recommendations.
In July 1997, the EPA proposed regulations on regional haze. The proposal
would require states to submit plans to meet "presumptive reasonable progress
targets" for achieving perceptible improvements in visibility conditions in
Federal Class I areas (e.g., national parks) every 10-15 years. The proposal
also calls for states to conduct three year "best available retrofit technology"
("BART") review on point sources which became operational between 1962 and 1977
and which may normally be anticipated to contribute to regional haze visibility
impairment. EPA is currently reviewing public comments and final regulations are
expected to be promulgated by June 1998. Because the actual level of emissions
controls, if any, for any unit cannot be determined at this time, the Company
currently cannot estimate the capital expenditures, if any, which would result
from the final rules.
With respect to hazardous air pollutants emitted by electric utility steam
generating units, the Amendments require two studies. The results of the first
study indicated an impact from mercury emissions from such units in
9
<PAGE>
certain unspecified areas; however, the EPA has not yet stated whether or not
emissions limitations will be imposed. Next, the EPA will complete a general
study by 1999 concerning the necessity of regulating such units under the
Amendments. Due to the lack of historical data, and because the Company cannot
speculate as to the ultimate requirements by the EPA, the Company cannot
currently estimate the capital expenditures, if any, which may be required as a
result of these studies.
Certain aspects of the Amendments may require related expenditures by the
Company, such as permit fees, none of which the Company expects to have a
material impact on its financial position or results of operations.
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. The Company does not currently expect these rules to have
a material adverse effect 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 ("PRP's") and may be each
strictly, and often jointly and severally, liable for the cost of any necessary
remediation of the substances. The EPA had previously advised the Company that
the EPA considers the Company to be a PRP in the Indian Bend Wash Superfund
Site, South Area, where the Company's Ocotillo Power Plant is located. The
Company is in the process of conducting a voluntary investigation to determine
the extent and scope of contamination at the plant site. Based on the
information to date, the Company does not expect this matter to have a material
impact on its financial position or results of operations.
MGP Sites. The Company currently is investigating properties, either
presently or previously owned by the Company, which 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, if such materials
constitute an environmental or health risk, and if the Company has any
responsibility for remedial action. Where appropriate, the Company has begun
remediation of certain of these sites. The Company 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. The Company is the Four Corners operating agent and owns a 100%
interest in Four Corners Units 1, 2 and 3, and a 15% interest in Four Corners
Units 4 and 5. The Company 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 (i) their respective
leases and federal easements preclude the application of the Acts to the
operations of Four Corners and NGS, and (ii) 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 the
proceedings referenced in the preceding two sentences so that the parties may
attempt to resolve the dispute without litigation, and the Secretary and the
Court have stayed these
10
<PAGE>
proceedings pursuant to a request by the parties. The Company 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. The Company is reviewing
the regulations to determine what effect they might have on the application of
the Navajo Nation Air Pollution Prevention and Control Act on Four Corners and
NGS.
Water Supply
Assured supplies of water are important both to the Company (for its
generating plants) and to its customers and, at the present time, the Company
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 the Company's
operations have been the subject of inquiries, claims and legal proceedings
which will require a number of years to resolve. The Company 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 the Company 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, and the rights of the Palo Verde
participants, including the Company, to the use of groundwater and effluent at
Palo Verde is potentially at issue in this action. The Company, as project
manager of Palo Verde, 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 and, alternatively, seek confirmation of such
rights. Three of the Company's less-utilized power plants are also located
within the geographic area subject to the summons. The Company's claims dispute
the court's jurisdiction over the Company's groundwater rights with respect to
these plants and, alternatively, seek confirmation of such rights. On December
10, 1992, the Arizona Supreme Court heard oral argument on certain issues in
this matter which are pending on interlocutory appeal. Issues important to the
Company's claims were remanded to the trial court for further action and the
trial court certified its decision for interlocutory appeal to the Arizona
Supreme Court. On September 28, 1994, the Arizona Supreme Court granted review
of the trial court decision. No trial date concerning the water rights claims of
the Company has been set in this matter.
The Company 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). The Company's groundwater resource utilized at Cholla is
within the geographic area subject to the adjudication and is therefore
potentially at issue in the case. The Company's claims dispute the court's
jurisdiction over the Company's groundwater rights and, alternatively, seek
confirmation of such rights. The parties are in the process of settlement
negotiations with respect to this matter. No trial date concerning the water
rights claims of the Company has been set in this matter.
Although the foregoing matters remain subject to further evaluation, the
Company expects that the described litigation will not have a material adverse
impact on its financial position or results of operations.
11
<PAGE>
ITEM 2. PROPERTIES
Accredited Capacity
The Company's present generating facilities have an accredited capacity
aggregating 3,986,900 kW, comprised as follows:
<TABLE>
<CAPTION>
Capacity(kW)
------------
<S> <C>
Coal:
Units 1, 2 and 3 at Four Corners, aggregating...................................... 560,000
15% owned Units 4 and 5 at Four Corners, representing.............................. 222,000
Units 1, 2 and 3 at Cholla Plant, aggregating...................................... 615,000
14% owned Units 1, 2 and 3 at the Navajo Plant, representing....................... 315,000
---------
1,712,000
=========
Gas or Oil:
Two steam units at Ocotillo and two steam units at Saguaro, aggregating............ 435,000(1)
Eleven combustion turbine units, aggregating....................................... 493,000
Three combined cycle units, aggregating............................................ 255,000
---------
1,183,000
=========
Nuclear:
29.1% owned or leased Units 1, 2 and 3 at Palo Verde, representing................. 1,086,300
=========
Other................................................................................... 5,600
=========
</TABLE>
- ---------------
(1) West Phoenix steam units (108,300 kW) are currently mothballed.
-----------------------------------------------------
Reserve Margin
The Company's peak one-hour demand on its electric system was recorded on
August 22, 1997 at 4,608,600 kW, compared to the 1996 peak of 4,574,700 kW
recorded on July 31. Taking into account additional capacity then available to
it under purchase power contracts as well as its own generating capacity, the
Company's capability of meeting system demand on August 22, 1997, computed in
accordance with accepted industry practices, amounted to 4,544,600 kW, for an
installed reserve margin of (1.5%). The power actually available to the Company
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 1997 peak amounted to 5,877,600 kW, for a margin of 9.1%. Firm
purchases from neighboring utilities totaling 1,603,000 kW were in place at the
time of the peak ensuring the ability to meet the load requirement.
Plant Sites Leased from Navajo Nation
NGS and Four Corners are located on land held under easements from the
federal government and also under leases from the Navajo Nation. The risk with
respect to enforcement of these easements and leases is not deemed by the
Company to be material. The lease for Four Corners contains a waiver until 2001
of the requirement that the Company and its fuel supplier pay certain taxes to
the Navajo Nation. In September 1997, a settlement agreement was finalized
between the Company, the coal supplier to Four Corners, and the Navajo Nation
which settled certain issues in the Four Corners lease regarding the obligation
of the fuel supplier to pay taxes prior to the expiration of tax waivers in
2001. Pursuant to the agreement, the Company recognized approximately $14
million of pretax earnings related to a partial refund of possessory interest
taxes paid by the fuel supplier. The parties also
12
<PAGE>
agreed to renegotiate their business relationship before 2001 in an effort to
permit the electricity generated at Four Corners to be priced competitively. The
Company cannot currently predict the outcome of this matter. Certain of the
Company's transmission lines and almost all of its contracted coal sources are
also located on Indian reservations. See "Generating Fuel and Purchased Power
- --- Coal Supply" in Item 1.
Palo Verde Nuclear Generating Station
Palo Verde Leases
On August 18, 1986 and December 19, 1986, the Company entered into a total
of three sale and leaseback transactions under which it sold and leased back
approximately 42% of its 29.1% ownership interest in Palo Verde Unit 2. The
leases under each of the sale and leaseback transactions have initial lease
terms expiring on December 31, 2015. Each of the leases also allows the Company
to extend the term of the lease and/or to repurchase the leased Unit 2 interest
under certain circumstances at fair market value. The leases in the aggregate
require annual payments of approximately $40 million through 1999, approximately
$46 million in 2000 and approximately $49 million through 2015 (see Note 9 of
Notes to Financial Statements in Item 8).
Regulatory
Operation of each of the three Palo Verde units requires an operating
license from the NRC. Full power operating licenses for Units 1, 2 and 3 were
issued by the NRC in June 1985, April 1986 and November 1987, respectively. The
full power operating licenses, each valid for a period of approximately 40
years, authorize the Company, as operating agent for Palo Verde, to operate the
three Palo Verde units at full power.
Nuclear Decommissioning Costs
See Note 13 of Notes to Financial Statements in Item 8 for a discussion of
the Company's nuclear decommissioning costs.
Steam Generators
See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to
Financial Statements in Item 8 for a discussion of issues relating to the Palo
Verde steam generators.
Palo Verde Liability and Insurance Matters
See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to
Financial Statements in Item 8 for a discussion of the insurance maintained by
the Palo Verde participants, including the Company, for Palo Verde.
Other Information Regarding the Company's Properties
See "Environmental Matters" and "Water Supply" in Item 1 with respect to
matters having possible impact on the operation of certain of the Company's
power plants.
See "Construction Program" in Item 1 and "Financial Review --- Capital
Needs and Resources" in Item 7 for a discussion of the Company's construction
plans.
See Notes 5, 8 and 9 of Notes to Financial Statements in Item 8 with
respect to property of the Company not held in fee or held subject to any major
encumbrance.
13
<PAGE>
[MAP PAGE]
In accordance with Item 304 of Regulation S-T of the Securities Exchange
Act of 1934, the Company's Service Territory map contained in this Form 10-K is
a map of the State of Arizona showing the Company's service area, the location
of its major power plants and principal transmission lines, and the location of
transmission lines operated by the Company for others. The major power plants
shown on such map are the Navajo Generating Station located in Coconino County,
Arizona; the Four Corners Power Plant located near Farmington, New Mexico; the
Cholla Power Plant, located in Navajo County, Arizona; the Yucca Power Plant,
located near Yuma, Arizona; and the Palo Verde Nuclear Generating Station,
located about 55 miles west of Phoenix, Arizona (each of which plants is
reflected on such map as being jointly owned with other utilities), as well as
the Ocotillo Power Plant and West Phoenix Power Plant, each located near
Phoenix, Arizona, and the Saguaro Power Plant, located near Tucson, Arizona. The
Company's major transmission lines shown on such map are reflected as running
between the power plants named above and certain major cities in the State of
Arizona. The transmission lines operated for others shown on such map are
reflected as running from the Four Corners Plant through a portion of northern
Arizona to the California border.
14
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
Property Taxes
See "Environmental Matters" and "Water Supply" in Item 1 in regard to
pending or threatened litigation and other disputes. See "Regulatory Matters" in
Note 3 of Notes to Financial Statements in Item 8 for a discussion of
competition and the Rules regarding the introduction of retail electric
competition in Arizona. On February 28, 1997, a lawsuit was filed by the Company
to protect its legal rights regarding the Rules and in its complaint the Company
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. The Arizona Corporation Commission, in the
Superior Court of the State of Arizona in and for the County of Maricopa, No.
CV97-03753, and Arizona Public Service Company v. The Arizona Corporation
Commission, in the Court of Appeals, State of Arizona, Division One, No. 1
CA-CC-97-0002, ACC Docket No. R-0000-94-165). That lawsuit is pending but two
related cases filed by other utilities have been decided adversely to the
utilities' positions.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth
quarter of the fiscal year covered by this report, through the solicitation of
proxies or otherwise.
15
<PAGE>
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS
OF THE REGISTRANT
The Company's executive officers are as follows:
<TABLE>
<CAPTION>
Age At
Name March 1, 1998 Position(s) At March 1, 1998
- ---- ------------- ----------------------------
<S> <C> <C>
Richard Snell 67 Chairman of the Board of Directors(1)
William J. Post 47 President and Chief Executive Officer(1)
Jack E. Davis 51 Executive Vice President, Commercial Operations
George A. Schreiber, Jr. 49 Executive Vice President and Chief Financial Officer(1)
William L. Stewart 54 Executive Vice President, Generation
Armando B. Flores 54 Senior Vice President, Corporate Business Services
James M. Levine 48 Senior Vice President, Nuclear
Jan H. Bennett 50 Vice President, Customer Service
John G. Bohon 52 Vice President, Procurement
John R. Denman 55 Vice President, Fossil
Edward Z. Fox 44 Vice President, Environmental/Health/Safety and
New Technology Ventures
William E. Ide 51 Vice President, Nuclear Engineering
Nancy C. Loftin 44 Vice President, Chief Legal Counsel and Secretary
Gregg R. Overbeck 51 Vice President, Nuclear Production
Patricia K. Vincent 39 Vice President, Marketing and Sales
Chris N. Froggatt 40 Controller
Michael V. Palmeri 39 Treasurer
</TABLE>
- ---------------
(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 and exclusive of
directorships) of such officers for the past five years have been as follows:
Mr. Snell was elected to his present position as of February 1990. He was
also elected Chairman of the Board, President and Chief Executive Officer of
Pinnacle West at that time, and he retired as President in February 1997.
Previously, he was Chairman of the Board (1989-1992) and Chief Executive Officer
(1989-1990) of Aztar Corporation.
Mr. Post assumed his present position in February 1997. Prior to that time
he was Senior Vice President and Chief Operating Officer (since September 1994),
Senior Vice President, Planning, Information and Financial Services (since June
1993), and Vice President, Finance & Rates (since April 1987). In February 1997,
Mr. Post became President of Pinnacle West.
Mr. Davis was elected to his present position in September 1996. Prior to
that time he was Vice President, Generation and Transmission (June
1993-September 1996); Director, Transmission Systems (January 1993-June 1993).
Mr. Schreiber was elected to his present position in February 1997. Prior
to that time he was Managing Director at PaineWebber, Inc. (since February
1990). Mr. Schreiber became Executive Vice President and Chief Financial Officer
of Pinnacle West in February 1997.
16
<PAGE>
Mr. Stewart was elected to his present position in September 1996. Prior to
that time he was Executive Vice President, Nuclear (since May 1994) and Senior
Vice President --- Nuclear for Virginia Power (since 1989).
Mr. Flores was elected to his present position in September 1996. Prior to
that time, he was Vice President, Human Resources (1991-1996) of the Company.
Mr. Levine was elected to his present position in September 1996. Prior to
that time he was Vice President, Nuclear Production (since September 1989).
Mr. Bennett was elected to his present position in May 1991.
Mr. Bohon was elected to his present position in April 1997. Prior to that
time he was Director, Corporate Services of the Company (December 1989-April
1997).
Mr. Denman was elected to his present position in April 1997. Prior to that
time he was Director of Fossil Generation (since 1990).
Mr. Fox was elected to his present position in October 1995. Prior to that
time he was Director, Arizona Department of Environmental Quality and Chairman,
Wastewater Management Authority of Arizona (July 1991-September 1995).
Mr. Ide was elected to his present position in September 1996. Prior to
that time he was Director, Palo Verde Operations (1994-1996) and Palo Verde Unit
1 Plant Manager (1988-1994).
Ms. Loftin was elected to the positions of Vice President and Chief Legal
Counsel in September 1996 and has been Secretary since April 1987. Prior to that
time, in addition to Secretary, she was Corporate Counsel (since February 1989).
Mr. Overbeck was elected to his current position in July 1995. Prior to
that time he was Assistant to Vice President of the Company (January 1994-July
1995) and Director, Nuclear Production Site Technical Support of the Company
(January 1991-January 1994).
Ms. Vincent was elected to her present position in October 1997. Prior to
that time she was Director, Marketing (August 1993-October 1997) and Group
Segment Manager (August 1992-August 1993) of the Company.
Mr. Froggatt was elected to his present position in July 1997. Prior to
that time he was Director, Accounting Services (since December 1992) of the
Company.
Mr. Palmeri was elected to his present position in July 1997. Prior to that
time he was Assistant Treasurer (February 1994-July 1997) and Manager of Finance
(June 1990-February 1994) of Pinnacle West. He also became Treasurer of Pinnacle
West in July 1997.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
STOCK AND RELATED SECURITY HOLDER MATTERS
The Company's common stock is wholly-owned by Pinnacle West and is not
listed for trading on any stock exchange. As a result, there is no established
public trading market for the Company's common stock.
17
<PAGE>
The chart below sets forth the dividends declared on the Company's common
stock for each of the four quarters for 1997 and 1996.
Common Stock Dividends
(Thousands of Dollars)
- --------------------------------------------------------------------------------
Quarter 1997 1996
- --------------------------------------------------------------------------------
1st Quarter $42,500 $42,500
2nd Quarter 42,500 42,500
3rd Quarter 42,500 42,500
4th Quarter 42,500 42,500
- --------------------------------------------------------------------------------
After payment or setting aside for payment of cumulative dividends and
mandatory sinking fund requirements, where applicable, on all outstanding issues
of preferred stock, the holders of common stock are entitled to dividends when
and as declared out of funds legally available therefor. See Notes 4 and 5 of
Notes to Financial Statements in Item 8 for restrictions on retained earnings
available for the payment of common stock dividends.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Electric Operating Revenues ................. $1,878,553 $1,718,272 $1,614,952 $1,626,168 $1,602,413
Fuel and Purchased Power .................... 436,627 325,523 269,798 300,689 300,546
Operating Expenses .......................... 1,070,101 1,027,541 963,400 957,046 929,379
---------- ---------- ---------- ---------- ----------
Operating Income ........................ 371,825 365,208 381,754 368,433 372,488
Other Income ................................ 21,586 35,217 25,548 44,510 54,220
Interest Deductions --- Net ................. 141,918 156,954 167,732 169,457 176,322
---------- ---------- ---------- ---------- ----------
Net Income .............................. 251,493 243,471 239,570 243,486 250,386
Preferred Dividends ..................... 12,803 17,092 19,134 25,274 30,840
---------- ---------- ---------- ---------- ----------
Earnings for Common Stock ............... $ 238,690 $ 226,379 $ 220,436 $ 218,212 $ 219,546
========== ========== ========== ========== ==========
Total Assets ................................ $6,331,142 $6,423,222 $6,418,262 $6,348,261 $6,357,262
========== ========== ========== ========== ==========
Capital Structure:
Common Stock Equity ..................... $1,849,324 $1,729,390 $1,621,555 $1,571,120 $1,522,941
Non-Redeemable Preferred Stock .......... 142,051 165,673 193,561 193,561 193,561
Redeemable Preferred Stock .............. 29,110 53,000 75,000 75,000 197,610
Long-Term Debt Less Current Maturities .. 1,953,162 2,029,482 2,132,021 2,181,832 2,124,654
---------- ---------- ---------- ---------- ----------
Total Capitalization ................ 3,973,647 3,977,545 4,022,137 4,021,513 4,038,766
Current Maturities of Long-Term Debt .... 104,068 153,780 3,512 3,428 3,179
Commercial Paper ........................ 130,750 16,900 177,800 131,500 148,000
---------- ---------- ---------- ---------- ----------
Total ............................... $4,208,465 $4,148,225 $4,203,449 $4,156,441 $4,189,945
========== ========== ========== ========== ==========
</TABLE>
- ---------------
See "Financial Review" in Item 7 for a discussion of certain information in
the foregoing table.
18
<PAGE>
ITEM 7. FINANCIAL REVIEW
References to "Notes" in the following discussion refer to Notes to Financial
Statements.
Results of Operations
1997 Compared with 1996 The Company's 1997 earnings increased $12.3 million
(5.4%) over 1996 earnings primarily because of customer growth; a $32 million
pretax charge in 1996 for a voluntary severance program; two fuel-related
settlements; and lower financing costs. These positive factors more than offset
the effects of the Company's 1996 regulatory agreement with the ACC, which
during 1997 resulted in approximately $60 million of additional regulatory asset
amortization and a $35 million revenue decrease caused by two retail price
reductions. See Note 3 and "Results of Operations --- Regulatory Agreements"
below for additional information about the 1996 regulatory agreement. In 1996,
the Company also recognized $12 million of income tax benefits, which were not
repeated in 1997.
The Company's operating revenues increased $160 million primarily because of
increases in sales for resale ($128 million); customer growth ($58 million); and
weather effects ($7 million). As mentioned in the preceding paragraph, these
positive factors were partially offset by a $35 million revenue decrease caused
by retail price reductions. Sales for resale are wholesale electricity sales to
third parties who resell the electricity to their customers. The increase in
sales for resale was a result of increased activity in competitive bulk power
markets. The increase in sales for resale did not significantly affect earnings
because it was substantially offset by power purchases.
The two fuel-related settlements increased the Company's 1997 pretax earnings by
approximately $21 million. The Company's income statement reflects these
settlements as reductions in fuel expense and as other income. Approximately $16
million of these settlements related to years prior to 1997 and $5 million
related to 1997. For at least the next several years, the total annual savings
from the settlements are expected to be about $10 million before income taxes.
The Company does not have a fuel adjustment clause as part of its retail rate
structure. As a result, changes in fuel and purchased power expenses are
reflected in current earnings.
Operations and maintenance expenses were lower in 1997 because of the charge for
the voluntary severance program recorded in 1996 and related savings in 1997.
These savings were partially offset by increased expenses for marketing,
information technology and power plant maintenance.
The Company's financing costs decreased $12 million during 1997 because of lower
amounts of outstanding debt and preferred stock.
1996 Compared with 1995 The Company's 1996 earnings increased $5.9 million
(2.7%) over 1995 earnings primarily because of customer growth and higher
residential usage; weather effects; tax and interest savings; and a $21 million
pretax write-down of certain assets in 1995. These positive factors more than
offset the earnings effects of the Company's 1996 regulatory agreement with the
ACC, which during 1996 resulted in $60 million of additional regulatory asset
amortization and a $30 million revenue decrease caused by a retail price
reduction. See Note 3 and "Results of Operations --- Regulatory Agreements"
below for additional information about the 1996 regulatory agreement.
Other important factors that made the comparison of 1996 earnings with 1995
earnings less favorable were a $32 million pretax charge for a voluntary
severance program; the recognition in 1995 of a $5 million after-tax gain on the
sale of a small subsidiary; and increased fuel expenses of $56 million primarily
because of increased retail and wholesale sales, higher natural gas costs, and
higher coal prices.
19
<PAGE>
The Company's operating revenues increased $103 million primarily because of
retail customer growth and higher residential usage ($75 million); weather
effects ($40 million); increases in sales for resale ($9 million); and other ($9
million). As mentioned above, these positive factors were partially offset by a
$30 million revenue decrease caused by a retail price reduction.
Other taxes decreased $21 million primarily because of a change in property tax
law. Income tax expense was lower because of the Company's recognition of $12
million of income tax benefits associated with capital loss carryforwards.
The Company's financing costs decreased $12 million during 1996 because of lower
average interest rates and lower amounts of outstanding debt.
Regulatory Agreements The Company's results of operations are affected, and will
be affected, by the impacts of existing regulatory agreements between the
Company and the ACC.
As part of the 1996 regulatory agreement with the ACC, the Company is recovering
substantially all of its present regulatory assets through accelerated
amortization over an eight-year period that began July 1, 1996. See Note 3. This
accelerated amortization increases annual amortization expense by approximately
$120 million ($72 million after taxes).
Also as part of the 1996 regulatory agreement, the Company agreed to decrease
retail prices effective July 1, 1996 by approximately $48.5 million annually
($29 million after income taxes), or 3.4%. In addition, the Company agreed to
share future cost savings with its customers through potential additional retail
price reductions. Pursuant to the agreed-upon price reduction formula, on July
1, 1997, the Company reduced its retail prices by approximately $17.6 million
annually ($10.5 million after income taxes), or 1.2%. Additionally, in March
1998, the Company filed with the ACC its calculation of an additional retail
price decrease of approximately $17 million annually ($10 million after income
taxes), or 1%, to become effective July 1, 1998. The amount and timing of the
price decrease are subject to ACC approval.
The factors that offset the earnings impact of the accelerated regulatory asset
amortization and the 1997 and 1996 price decreases are discussed above in
"Results of Operations."
As part of a 1994 rate settlement with the ACC, the Company accelerated
amortization of substantially all deferred investment tax credits (ITCs) over a
five-year period that ends on December 31, 1999. The amortization of ITCs is
shown on the Company's income statement as Other Income --- Income Taxes and
decreases annual income tax expense by approximately $28 million. See Note 10.
Capital Needs and Resources
The Company's capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt and preferred stock. The
Company funds its capital requirements from cash provided by operations, annual
equity infusions from its parent company of $50 million from 1996 through 1999
(see Note 3), and, to the extent necessary, external financing. During the
period 1995 through 1997, the Company funded all of its capital expenditures
from cash provided by operations and expects to do so in 1998 through 2000 as
well.
During 1997, the Company redeemed approximately $240 million of long-term debt
and $47 million of preferred stock, including premiums, with cash from
operations and long- and short-term debt.
The Company's projected capital expenditures for the next three years are: 1998,
$323 million; 1999, $313 million; and 2000, $306 million. These amounts include
about $30-$35 million each year for nuclear fuel. In general, most of the
projected capital expenditures are for expanding transmission and distribution
capabilities to
20
<PAGE>
meet customer growth, for upgrading existing facilities and for environmental
purposes. In addition, the Company is considering expanding certain of its
businesses over the next several years, which may result in increased
expenditures. The Company's construction plans through the year 2007 do not
include any major baseload generating plants.
The Company's long-term debt and preferred stock redemption requirements and
payment obligations on a capitalized lease for the next three years are: 1998,
$114 million; 1999, $174 million; and 2000, $114 million. Based on cash provided
by operations and the Company's capital requirements, the Company may make
optional redemptions of long-term debt and preferred stock from time to time.
As of December 31, 1997, the Company had credit commitments from various banks
totaling approximately $400 million, which were available either to support the
issuance of commercial paper or to be used as bank borrowings.
At the end of 1997, there were $130.8 million of commercial paper and $150
million of bank borrowings outstanding.
During 1997, the Company incurred $60 million of long-term debt under credit
agreements and issued $50 million of its senior notes. Until the Company has
repaid all of its first mortgage bonds (other than those that secure senior
notes), the senior notes are secured by first mortgage bonds that have the same
interest rate, interest payment dates, maturity and redemption provisions as the
senior notes. See Note 5 for additional information regarding the senior notes.
In January 1998, the Company issued $100 million of unsecured debt.
Although provisions in the Company's first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds and preferred stock that the Company may issue, management
does not expect any of these provisions to limit the Company's ability to meet
its capital requirements.
Competition and Industry Restructuring
The electric industry is undergoing significant change to a competitive,
market-based structure from a highly-regulated, cost-based environment in which
companies have been entitled to recover their costs and to earn fair returns on
their invested capital in exchange for commitments to serve all customers within
designated service territories. In December 1996, the ACC adopted rules that
provide a framework for the introduction of retail electric competition in
Arizona in phases from 1999 to 2003. See Note 3 for additional information about
these rules and other competitive developments.
The ACC ordered in the rules that numerous issues require additional
consideration prior to the implementation of retail electric competition in
Arizona. During 1997, the ACC held workshops to gather input from various
constituencies with respect to those issues.
The rules indicate that the ACC will allow recovery of unmitigated stranded
costs, but do not set forth the mechanisms for determining and recovering such
costs. In February 1998, the ACC completed a formal, generic hearing on stranded
cost determination and recovery. Based on various assumptions, estimates and
methodologies, the Company currently estimates that its stranded costs to be
recovered (excluding regulatory assets which have already been addressed by the
ACC) will be less than $500 million. The Company is seeking full recovery of
stranded costs during a transition period proposed to go through 2006. Decisions
by the ACC have not yet been made with respect to this issue.
An Arizona joint legislative committee studied electric utility restructuring
issues in 1996 and 1997. In February 1998, a bill was introduced in the Arizona
legislature to facilitate implementation of retail electric competition in the
state. The bill has progressed through several stages to date. Additionally,
legislation related to electric competition has been proposed in the United
States Congress. See Note 3 for a discussion of legislative developements.
21
<PAGE>
The Company believes that further ACC decisions, legislation at the Arizona and
federal levels and perhaps amendments to the Arizona Constitution will
ultimately be required before significant implementation of retail electric
competition can lawfully occur in Arizona. Until it has been determined how
competition will be implemented in Arizona, including the manner in which
stranded costs will be addressed, the Company cannot accurately predict the
impact of full retail competition on its financial position, cash flows or
results of operations. As competition in the electric industry continues to
evolve, the Company will continue to evaluate strategies and alternatives that
will position the Company to compete effectively in a restructured industry.
The Company prepares its financial statements in accordance with the provisions
of 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. The Company's existing regulatory orders and current
regulatory environment support its accounting practices related to regulatory
assets which amounted to approximately $1.0 billion at December 31, 1997. In
accordance with the 1996 regulatory agreement, the ACC accelerated the
amortization of substantially all of the Company's regulatory assets to an
eight-year period that began July 1, 1996. If the Company ceases to be
cost-based regulated, it would no longer be able to apply the provisions of SFAS
No. 71 to all or some part of its operations, which could have a material impact
on the Company's financial statements. See Note 1 for additional information on
regulatory accounting.
Year 2000 Technology Issues
The Company has made, and will continue to make, certain modifications to its
computer hardware and software systems and applications to ensure they are
capable of handling dates in the year 2000 and thereafter. The Company's major
computer systems have been updated and other systems are being analyzed for
potential modifications. The financial impact on the Company is not anticipated
to be material to is financial position, cash flows or results of operations.
The Company is in the process of formal communications with its significant
suppliers, business partners, and large customers to determine the extent to
which it may be affected by these third parties' plans to remediate their own
year 2000 issues in a timely manner.
Accounting Matters
Note 2 describes three new accounting standards related to comprehensive income,
segment disclosures and disclosures about pensions and other postretirement
benefits, which are effective in 1998. These standards are not expected to have
a material effect on the Company's financial position, cash flows or results of
operation. Also, see Note 13 for a description of a proposed standard on
accounting for certain liabilities related to closure or removal of long-lived
assets.
Risk Management
The Company's 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 The Company's 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. The Company's policy is to manage interest rates through the use of a
combination of fixed and floating rate debt. The nuclear decommissioning fund
also has risks associated with changing market values of equity investments.
Nuclear decommissioning costs are recovered in rates.
22
<PAGE>
The table below presents contractual balances of the Company's long-term debt
and commercial paper at the expected maturity dates as well as the fair value of
those instruments on December 31, 1997. The weighted average interest rates for
the various debt presented are actual as of December 31, 1997.
Expected Maturity/Principal Repayment
December 31,
(Thousands of Dollars)
Variable Fixed
Commercial Long Long
Paper Term Term
Weighted Average Rates ....... 6.27% 4.29% 7.69%
1998 .................... $130,750 $ ___ $ 104,068
1999 .................... ___ ___ 164,378
2000 .................... ___ ___ 104,711
2001 .................... ___ ___ 2,488
2002 .................... ___ 150,000 125,000
Years thereafter ........ ___ 439,990 973,628
-------- -------- ----------
Total ................... $130,750 $589,990 $1,474,273
======== ======== ==========
Fair Value ................... $130,750 $589,990 $1,504,417
======== ======== ==========
Commodity Price Risk The Company enters into forwards, futures and other similar
contracts to hedge the price risks associated with a portion of anticipated
future electricity production and gas purchases. Most of these agreements are
settled in physical delivery, with the balance settled in cash at or prior to
expiration. Under certain of these agreements, payments are sometimes made or
received based on the differential between a fixed and a variable product price.
The Company does not obtain collateral to support the agreements, but monitors
the financial viability of counterparties and believes it has minimized its
credit risk on these transactions. In the event of nonperformance by
counterparties, the Company would be exposed to price risk. The Company may
recognize an accounting gain or loss where actual delivery occurs and the price
in the contract may differ from the prevailing price at the delivery point in
completing the transaction. The Company defers the impact of changes in the
market value of contracts that serve as hedges until the related transaction is
completed.
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 the Company 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; and technological developments in the electric
industry.
These factors and the other matters discussed above may cause future results to
differ materially from historical results, or from results or outcomes currently
expected or sought by the Company.
23
<PAGE>
ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Management........................................................................................25
Independent Auditors' Report................................................................................26
Statements of Income for each of the three years in the period ended December 31, 1997......................27
Balance Sheets --- December 31, 1997 and 1996...............................................................28
Statements of Cash Flows for each of the three years in the period ended December 31, 1997..................30
Statements of Retained Earnings for each of the three years in the period ended December 31, 1997...........31
Notes to Financial Statements...............................................................................31
</TABLE>
See Note 14 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.
24
<PAGE>
REPORT OF MANAGEMENT
The primary responsibility for the integrity of the Company's financial
information rests with management, which has prepared the accompanying financial
statements and related information. Such information was prepared in accordance
with generally accepted accounting principles appropriate in the circumstances,
based on management's best estimates and judgments and giving due consideration
to materiality. These financial statements have been audited by independent
auditors and their report is included.
Management maintains and relies upon systems of internal accounting controls. A
limiting factor in all systems of internal accounting control is that the cost
of the system should not exceed the benefits to be derived. Management believes
that the Company's system provides the appropriate balance between such costs
and benefits.
Periodically the internal accounting control system is reviewed by both the
Company's internal auditors and its independent auditors to test for compliance.
Reports issued by the internal auditors are released to management, and such
reports or summaries thereof are transmitted to the Audit Review Committee of
the Board of Directors and the independent auditors on a timely basis.
The Audit Review Committee, composed solely of outside directors, meets
periodically with the internal auditors and independent auditors (as well as
management) to review the work of each. The internal auditors and independent
auditors have free access to the Audit Review Committee, without management
present, to discuss the results of their audit work.
Management believes that the Company's systems, policies and procedures provide
reasonable assurance that operations are conducted in conformity with the law
and with management's commitment to a high standard of business conduct.
William J. Post George A. Schreiber, Jr.
William J. Post George A. Schreiber, Jr.
President and Executive Vice President
Chief Executive Officer and Chief Financial Officer
25
<PAGE>
INDEPENDENT AUDITORS' REPORT
We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 1997 and 1996 and the related statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1997. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Company at December 31, 1997 and 1996
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1997 in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
March 4, 1998
26
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1997 1996 1995
----------- ----------- -----------
(Thousands of Dollars)
<S> <C> <C> <C>
Electric Operating Revenues ................... $ 1,878,553 $ 1,718,272 $ 1,614,952
----------- ----------- -----------
Fuel Expenses:
Fuel for electric generation ......... 201,341 230,393 208,928
Purchased power ...................... 235,286 95,130 60,870
----------- ----------- -----------
Total ....................... 436,627 325,523 269,798
----------- ----------- -----------
Operating Revenues Less Fuel Expenses ......... 1,441,926 1,392,749 1,345,154
----------- ----------- -----------
Other Operating Expenses:
Operations and maintenance excluding
fuel expenses ...................... 399,434 430,714 400,814
Depreciation and amortization (Note 1) 365,671 297,210 242,098
Income taxes (Note 10) ............... 184,737 178,513 178,865
Other taxes .......................... 120,259 121,104 141,623
----------- ----------- -----------
Total ....................... 1,070,101 1,027,541 963,400
----------- ----------- -----------
Operating Income .............................. 371,825 365,208 381,754
----------- ----------- -----------
Other Income (Deductions):
Allowance for equity funds used during
construction ....................... -- 5,209 4,982
Income taxes (Note 10) ............... 31,413 45,552 37,598
Other --- net ........................ (9,827) (15,544) (17,032)
----------- ----------- -----------
Total ....................... 21,586 35,217 25,548
----------- ----------- -----------
Income Before Interest Deductions ............. 393,411 400,425 407,302
----------- ----------- -----------
Interest Deductions:
Interest on long-term debt ........... 140,931 147,666 160,032
Interest on short-term borrowings .... 9,404 10,621 8,143
Debt discount, premium and expense ... 7,791 8,176 8,622
Capitalized interest ................. (16,208) (9,509) (9,065)
----------- ----------- -----------
Total ....................... 141,918 156,954 167,732
----------- ----------- -----------
Net Income .................................... 251,493 243,471 239,570
Preferred Stock Dividend Requirements ......... 12,803 17,092 19,134
----------- ----------- -----------
Earnings for Common Stock ..................... $ 238,690 $ 226,379 $ 220,436
=========== =========== ===========
</TABLE>
See Notes to Financial Statements.
27
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31,
----------------------------
1997 1996
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
Utility Plant (Notes 5, 8 and 9):
Electric plant in service and held for future use............. $ 7,009,059 $ 6,803,211
Less accumulated depreciation and amortization ............... 2,620,607 2,426,143
----------- -----------
Total ...................................................... 4,388,452 4,377,068
Construction work in progress ................................ 237,492 226,935
Nuclear fuel, net of amortization of $66,081
and $63,892 ................................................ 51,624 51,137
----------- -----------
Utility Plant --- net ...................................... 4,677,568 4,655,140
----------- -----------
Investments and Other Assets (Note 13) ................................ 164,906 113,666
----------- -----------
Current Assets:
Cash and cash equivalents .................................... 12,552 12,521
Accounts receivable:
Service customers .......................................... 141,022 111,715
Other ...................................................... 31,313 49,898
Allowance for doubtful accounts ............................ (1,338) (1,685)
Accrued utility revenues (Note 1) ............................ 58,559 55,470
Materials and supplies (at average cost) ..................... 70,634 74,120
Fossil fuel (at average cost) ................................ 9,621 13,928
Deferred income taxes (Note 10) .............................. 3,496 8,424
Other ........................................................ 24,529 22,767
----------- -----------
Total Current Assets ....................................... 350,388 347,158
----------- -----------
Deferred Debits:
Regulatory asset for income taxes (Note 10) .................. 458,369 516,722
Rate synchronization cost deferral (Note 1) .................. 358,871 414,082
Unamortized costs of reacquired debt ......................... 63,501 69,554
Unamortized debt issue costs ................................. 15,303 16,692
Other ........................................................ 242,236 290,208
----------- -----------
Total Deferred Debits ...................................... 1,138,280 1,307,258
----------- -----------
Total ...................................................... $ 6,331,142 $ 6,423,222
=========== ===========
</TABLE>
See Notes to Financial Statements.
28
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES
<TABLE>
<CAPTION>
December 31,
-------------------------
1997 1996
---------- ----------
(Thousands of Dollars)
<S> <C> <C>
Capitalization (Notes 4 and 5):
Common stock .................................................. $ 178,162 $ 178,162
Premiums and expenses --- net ................................. 1,142,364 1,091,122
Retained earnings ............................................. 528,798 460,106
---------- ----------
Common stock equity .................................. 1,849,324 1,729,390
Non-redeemable preferred stock ................................ 142,051 165,673
Redeemable preferred stock .................................... 29,110 53,000
Long-term debt less current maturities ........................ 1,953,162 2,029,482
---------- ----------
Total Capitalization ................................. 3,973,647 3,977,545
---------- ----------
Current Liabilities:
Commercial paper (Note 6) ..................................... 130,750 16,900
Current maturities of long-term debt (Note 5) ................. 104,068 153,780
Accounts payable .............................................. 107,423 174,394
Accrued taxes ................................................. 85,886 86,327
Accrued interest .............................................. 31,660 39,115
Customer deposits ............................................. 29,116 32,137
Other ......................................................... 19,588 21,150
---------- ----------
Total Current Liabilities ............................ 508,491 523,803
---------- ----------
Deferred Credits and Other:
Deferred income taxes (Note 10) ............................... 1,345,177 1,414,242
Deferred investment tax credit (Note 10) ...................... 60,093 87,723
Unamortized gain --- sale of utility plant (Note 9) ........... 82,363 86,939
Customer advances for construction ............................ 29,294 24,044
Other ......................................................... 332,077 308,926
---------- ----------
Total Deferred Credits and Other ..................... 1,849,004 1,921,874
---------- ----------
Commitments and Contingencies (Note 12)
Total ......................................................... $6,331,142 $6,423,222
========== ==========
</TABLE>
29
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1997 1996 1995
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows from Operations:
Net income ......................................................... $ 251,493 $ 243,471 $ 239,570
Items not requiring cash:
Depreciation and amortization ............................. 365,671 297,210 242,098
Nuclear fuel amortization ................................. 32,702 33,566 31,587
Allowance for equity funds used during construction ....... -- (5,209) (4,982)
Deferred income taxes --- net ............................. (55,278) (12,717) 15,344
Deferred investment tax credit --- net .................... (27,630) (27,630) (27,641)
Changes in certain current assets and liabilities:
Accounts receivable --- net ............................... (11,069) (33,044) 1,659
Accrued utility revenues .................................. (3,089) (1,951) 1,913
Materials, supplies and fossil fuel ....................... 7,793 11,945 25,606
Other current assets ...................................... (1,762) (4,928) (3,677)
Accounts payable .......................................... (56,710) 68,788 6,333
Accrued taxes ............................................. (441) 3,500 (6,585)
Accrued interest .......................................... (7,455) (2,565) (3,621)
Other current liabilities ................................. (3,997) (522) 3,393
Other --- net ...................................................... 64,280 17,216 21,328
--------- --------- ---------
Net cash provided ......................................... 554,508 587,130 542,325
--------- --------- ---------
Cash Flows from Investing:
Capital expenditures ............................................... (307,876) (258,598) (295,772)
Capitalized interest ............................................... (16,208) (9,509) (9,065)
Other .............................................................. (33,637) (9,702) (22,645)
--------- --------- ---------
Net cash used ............................................. (357,721) (277,809) (327,482)
--------- --------- ---------
Cash Flows from Financing:
Long-term debt ..................................................... 109,906 205,830 87,130
Short-term borrowings --- net ...................................... 113,850 (160,900) 46,300
Common equity infusion from parent ................................. 50,000 50,000 --
Dividends paid on common stock ..................................... (170,000) (170,000) (170,000)
Dividends paid on preferred stock .................................. (13,307) (17,416) (19,134)
Repayment of preferred stock ....................................... (47,201) (50,360) --
Repayment and reacquisition of long-term debt ...................... (240,004) (172,343) (147,282)
--------- --------- ---------
Net cash used ............................................. (196,756) (315,189) (202,986)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents .................. 31 (5,868) 11,857
Cash and cash equivalents at beginning of year ........................ 12,521 18,389 6,532
--------- --------- ---------
Cash and cash equivalents at end of year .............................. $ 12,552 $ 12,521 $ 18,389
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest (excluding capitalized interest) ................. $ 141,991 $ 150,603 $ 163,592
Income taxes .............................................. $ 236,676 $ 158,553 $ 164,261
</TABLE>
See Notes to Financial Statements.
30
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1997 1996 1995
-------- -------- --------
(Thousands of Dollars)
<S> <C> <C> <C>
Retained earnings at beginning of year ....................... $460,106 $403,843 $353,655
Add: Net income ............................................. 251,493 243,471 239,570
-------- -------- --------
Total ............................................... 711,599 647,314 593,225
-------- -------- --------
Deduct:
Dividends:
Common stock (Notes 4 and 5) ............... 170,000 170,000 170,000
Preferred stock (at required rates) (Note 4) 12,801 17,092 19,134
Other ............................................... -- 116 248
-------- -------- --------
Total deductions ........................... 182,801 187,208 189,382
-------- -------- --------
Retained earnings at end of year ............................. $528,798 $460,106 $403,843
======== ======== ========
</TABLE>
See Notes to Financial Statements.
APS
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Nature of Operations The Company is Arizona's largest electric utility, with
767,000 customers, and 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.
Accounting Records The 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 The Company is regulated by the ACC and the FERC and the
accompanying financial statements reflect the rate-making policies of these
commissions. The Company prepares its financial statements in accordance with
the provisions of 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.
The Company's major regulatory assets are deferred income taxes (see Note 10)
and rate synchronization cost deferrals (see "Rate Synchronization Cost
Deferrals" in this note). These items, combined with miscellaneous regulatory
assets and liabilities, amounted to approximately $1.0 billion and $1.1 billion
at December 31, 1997 and 1996, respectively, most of which are included in
"Deferred Debits" on the Balance Sheets. In accordance with the 1996 regulatory
agreement (see Note 3), the ACC accelerated the amortization of substantially
all of the Company's regulatory assets to an eight-year period that began July
1, 1996. The accelerated portion of the regulatory asset amortization,
approximately $120 million pretax in 1997 and $60 million pretax in 1996, is
included in depreciation and amortization expense on the Statements of Income.
31
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) issued EITF 97-4, which requires that SFAS No. 71 be
discontinued no later than when legislation is passed or a rate order is issued
that contains sufficient detail to determine its effect on the portion of the
business being deregulated, which could result in write-downs or write-offs of
physical and/or regulatory assets. Additionally, the EITF determined that
regulatory assets should not be written off if they are to be recovered from a
portion of the entity which continues to apply SFAS No. 71.
Although the ACC has issued rules for transitioning generation services to
competition, there are many unresolved issues. The Company continues to apply
SFAS No. 71 to all of its operations. If rate recovery of regulatory assets is
no longer probable, whether due to competition or regulatory action, the Company
would be required to write off the remaining balance as an extraordinary charge
to expense.
Common Stock All of the outstanding shares of common stock of the Company are
owned by Pinnacle West. See Note 4.
Utility Plant and Depreciation Utility plant represents the buildings, equipment
and other facilities used to provide electric service. The cost of utility plant
includes labor, materials, contract services, other related items and
capitalized interest or an allowance for funds used during construction. The
cost of retired depreciable utility plant, plus removal costs less salvage
realized, is charged to accumulated depreciation. See Note 13 for information on
a proposed accounting standard which impacts accounting for removal costs.
Depreciation on utility property is recorded on a straight-line basis. The
applicable rates as prescribed by regulators for 1995 through 1997 ranged from
1.51% to 20%, which resulted in an annual composite rate of 3.35% for 1997.
Depreciation and amortization of non-utility property and equipment are provided
over the estimated useful lives of the related assets, ranging from 3 to 50
years.
Capitalized Interest In 1997 the Company began capitalizing interest in
accordance with SFAS No. 34, "Capitalization of Interest Cost." Capitalized
interest represents the cost of debt funds used to finance construction of
utility plant. Plant construction costs, including capitalized interest, are
recovered in authorized rates through depreciation when completed projects are
placed into commercial operation. Capitalized interest does not represent
current cash earnings. The rate used to calculate capitalized interest for 1997
was 7.25%.
Prior to 1997 the Company accrued an allowance for funds used during
construction (AFUDC). AFUDC represented the cost of debt and equity funds used
to finance construction of utility plant, and did not represent current cash
earnings. AFUDC has been calculated using composite rates of 7.75% for 1996 and
8.52% for 1995.
Revenues Electric operating revenues are recognized on the accrual basis and
include 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 and January 1988,
respectively) until the date the units were included in a rate order (April 1988
and December 1991, respectively). Beginning July 1, 1996, the deferrals are
being amortized over an eight-year period in accordance with the 1996 regulatory
agreement (see Note 3). Prior to July 1, 1996 the deferrals were amortized over
thirty-five year periods. Amortization of the deferrals is included in
depreciation and amortization expense on the Statements of Income.
32
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
Nuclear Fuel Nuclear fuel is charged to fuel expense using the
unit-of-production method under which the number of units of thermal energy
produced in the current period is related to the total thermal units expected to
be produced over the remaining life of the fuel.
Under federal law, the United States Department of Energy (DOE) is responsible
for the permanent disposal of spent nuclear fuel and assesses $0.001 per kWh of
nuclear generation. This amount is charged to nuclear fuel expense. See Note 12
for information on spent fuel disposal and Note 13 for information on nuclear
decommissioning costs.
Reacquired Debt Costs The Company amortizes gains and losses on reacquired debt
over the remaining life of the original debt, consistent with ratemaking. In
accordance with the 1996 regulatory agreement (see Note 3), the ACC accelerated
the Company's amortization of the regulatory asset for reacquired debt costs to
an eight-year period that began July 1, 1996. The accelerated portion of the
regulatory asset amortization is included in depreciation and amortization
expense on the Statements of Income.
Cash and Cash Equivalents For purposes of the statements of cash flows, the
Company considers all highly liquid debt instruments purchased with an initial
maturity of three months or less to be cash equivalents.
Reclassifications Certain prior year balances have been restated to conform to
the 1997 presentation.
2. Accounting Matters
The Financial Accounting Standards Board has issued SFAS No. 130 "Reporting
Comprehensive Income," SFAS No. 131 "Disclosures about Segments of an Enterprise
and Related Information" and SFAS No. 132 "Employers' Disclosures about Pensions
and Other Postretirement Benefits," all of which are effective in 1998.
SFAS No. 130 changes the reporting of certain items currently reported in the
common stock equity section of the balance sheet and is not expected to have a
material effect on the Company's financial statements.
SFAS No. 131 requires that public companies report certain information about
operating segments in their financial statements. It also establishes related
disclosures about products and services, geographic areas, and major customers.
The Company is currently evaluating what impact this standard will have on its
disclosures.
SFAS No. 132 standardizes the disclosure requirements for pensions and other
postretirement benefits to provide information that is more comparable,
understandable and concise. It is not expected to have a material effect on the
Company's financial statement disclosures.
3. Regulatory Matters
Electric Industry Restructuring
State The ACC has been conducting an ongoing investigation into the
restructuring of the Arizona electric industry. In December 1996, the ACC
adopted rules that provide a framework for the introduction of retail electric
competition. The ACC framework rules include the following major provisions:
o The rules are intended to apply to virtually all of the Arizona electric
utilities regulated by the ACC, including the Company.
33
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
o Each affected utility would be required to make available at least 20% of
its 1995 system retail peak demand for competitive generation supply to all
customer classes not later than January 1, 1999; at least 50% not later
than January 1, 2001; and all of its retail demand not later than January
1, 2003.
o Electric service providers that obtain Certificates of Convenience and
Necessity (CC&Ns) from the ACC would be allowed to supply, market, and/or
broker specified electric services at retail. These services would include
electric generation, but exclude electric transmission and distribution.
o On or before December 31, 1997, each affected utility was required to file
with the ACC proposed tariffs for bundled service, if different than
current tariffs, and unbundled service. Bundled service means electric
service elements (i.e., generation, transmission, distribution, and
ancillary services) provided as a package to consumers within an affected
utility's current service area. Unbundled service means electric service
elements provided and priced separately.
o The rules indicate that the ACC will allow recovery of unmitigated stranded
costs. Stranded costs are the costs of generating plants, other assets and
contract commitments that were prudently incurred to serve power customers
that could go unrecovered if these customers are allowed to use open access
to move to another supplier. Each affected utility would be required to
file with the ACC its estimates of unmitigated stranded costs. The ACC
would then, after hearing and consideration of various factors, determine
the magnitude of stranded costs and appropriate stranded cost recovery
mechanisms and charges.
The ACC ordered in the rules that numerous issues (including reliability;
stranded cost measurement and recovery; the phase-in process, bundled, unbundled
and metering services; legal issues; and independent system operator and spot
market development) require additional consideration prior to implementation of
retail electric competition. During 1997, the ACC conducted workshops to gather
input from various constituencies with respect to those issues.
In February 1998, the ACC completed a formal, generic hearing on stranded cost
determination and recovery. Based on various assumptions, estimates and
methodologies, the Company currently estimates that its stranded costs to be
recovered (excluding regulatory assets which have already been addressed by the
ACC) will be less than $500 million. The Company is seeking full recovery of
stranded costs during a transition period proposed to go through 2006. Decisions
by the ACC have not yet been made with respect to this issue.
An Arizona joint legislative committee studied electric utility industry
restructuring issues in 1996 and 1997. In conjunction with that study, Arizona
legislative counsel prepared memoranda in late 1997 related to the legal
authority of the ACC to deregulate the Arizona electric utility industry. The
memoranda raise a question as to the degree to which the ACC may, under the
Arizona Constitution, deregulate any portion of the electric utility industry
and allow rates to be determined by market forces.
In February 1998, a bill to facilitate implementation of retail electric
competition in the state was introduced in the Arizona legislature. The bill has
progressed through several stages to date. The bill includes the following major
provisions: (a) requirements that large government-operated electric utilities
(i) enter into intergovernmental agreements with the ACC to promote consistent
statewide practices; (ii) implement retail electric generation competition for
20% of each utility's 1995 retail peak demand by December 31, 1998 and for all
customers by December 31, 1999; (iii) decrease rates by at least 10% over a ten-
year period beginning as early as January 1, 1991; and (iv) recover unmitigated
stranded costs through a surcharge on distribution prices; and (b) a proposal
that the ACC adopt provisions for public service corporations (including
investor-owned utilities such as APS) consistent with some of the bill's
provisions for certain government-operated electric utilities as described
above.
34
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The Company believes that certain provisions of the ACC framework rules are
deficient. In February 1997, a lawsuit was filed by the Company to protect its
legal rights regarding those rules. That lawsuit is pending but two related
cases filed by other utilities have been decided adversely to the utilities'
positions.
The Company believes that further ACC decisions, legislation at the Arizona and
federal levels and perhaps amendments to the Arizona Constitution (which
amendments would require a vote of the people) will ultimately be required
before significant implementation of retail electric competition can lawfully
occur in Arizona. Until the manner of implementation of competition, including
addressing stranded costs, is determined, the Company 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, the Company will continue to evaluate strategies and alternatives that
will position the Company to compete in the new regulatory environment.
Federal The Energy Policy Act of 1992 and recent rulemakings by FERC have
promoted increased competition in the wholesale electric power markets. The
Company does not expect these rules to have a material impact on its financial
statements.
Several electric utility reform bills have been introduced during recent
congressional sessions, which as currently written, would allow consumers to
choose their electricity suppliers by 2000 or 2003. These bills, other bills
that are expected to be introduced, and ongoing discussions at the federal level
suggest a wide range of opinion that will need to be narrowed before any
substantial restructuring of the electric utility industry can occur.
1996 Regulatory Agreement
In April 1996, the ACC approved a regulatory agreement between the Company and
the ACC Staff. The major provisions of this agreement are:
o An annual rate reduction of approximately $48.5 million ($29 million after
income taxes), or 3.4% on average for all customers except certain contract
customers, effective July 1, 1996.
o Recovery of substantially all of the Company's present regulatory assets
through accelerated amortization over an eight-year period that began July
1, 1996, increasing annual amortization by approximately $120 million ($72
million after income taxes). See Note 1.
o A formula for sharing future cost savings between customers and
shareholders (price reduction formula) referencing a return on equity (as
defined) of 11.25%.
o A moratorium on filing for permanent rate changes prior to July 2, 1999,
except under the price reduction formula and under certain other limited
circumstances.
o Infusion of $200 million of common equity into the Company by Pinnacle
West, in annual payments of $50 million starting in 1996.
Pursuant to the price reduction formula, in May 1997, the ACC approved a retail
price decrease of approximately $17.6 million ($10.5 million after income
taxes), or 1.2%, effective July 1, 1997. In March 1998, the Company filed with
the ACC its calculation of an annual price reduction of approximately $17
million ($10 million after income taxes), or 1%, to become effective July 1,
1998. The amount and timing of the price decrease are subject to ACC approval.
35
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
4. Common and Preferred Stocks
Non-redeemable preferred stock is not redeemable except at the option of the
Company. Redeemable preferred stock is redeemable through sinking fund
obligations. Common and preferred stock balances at December 31 are shown below:
<TABLE>
<CAPTION>
Number
of Shares Par Par Value Call
Outstanding Value Outstanding Price
---------------------- Per -------------------- Per
Authorized 1997 1996 Share 1997 1996 Share(a)
----------- ---------- ---------- ------- --------- --------- -------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Common Stock ............ 100,000,000 71,264,947 71,264,947 $ 2.50 $ 178,162 $ 178,162 --
========== ========== ========= =========
Preferred Stock:
Non-Redeemable:
$1.10 ................ 160,000 145,559 152,740 $ 25.00 $ 3,639 $ 3,818 $ 27.50
$2.50 ................ 105,000 97,252 102,532 50.00 4,863 5,127 51.00
$2.36 ................ 120,000 38,506 40,000 50.00 1,925 2,000 51.00
$4.35 ................ 150,000 68,386 75,000 100.00 6,839 7,500 102.00
Serial preferred ..... 1,000,000
$2.40 Series A ... 234,839 239,900 50.00 11,742 11,995 50.50
$2.625 Series C ... 231,572 240,000 50.00 11,579 12,000 51.00
$2.275 Series D ... 164,101 199,655 50.00 8,205 9,983 50.50
$3.25 Series E ... 312,991 320,000 50.00 15,649 16,000 51.00
Serial preferred ..... 4,000,000(b)
Adjustable rate ---
Series Q ......... 352,851 372,851 100.00 35,285 37,285 (c)
Serial preferred ..... 10,000,000
$1.8125 Series W ... 1,693,016 2,398,615 25.00 42,325 59,965 (d)
--------- --------- --------- ---------
Total ............ 3,339,073 4,141,293 $ 142,051 $ 165,673
========= ========= ========= =========
Redeemable:
Serial preferred:
$10.00 Series U . 291,098 410,000 $100.00 $ 29,110 $ 41,000 --
$7.875 Series V . -- 120,000 100.00 -- 12,000 --
------- ------- --------- ---------
Total ............ 291,098 530,000 $ 29,110 $ 53,000
======= ======= ========= =========
</TABLE>
- ---------------
(a) The actual call price per share is the indicated amount plus any accrued
dividends.
(b) This authorization also covers all outstanding redeemable preferred stock.
(c) Dividend rate adjusted quarterly to 2% below that of certain United States
Treasury securities, but in no event less than 6% or greater than 12% per
annum. Redeemable at par.
(d) Redeemable at par after December 1, 1998.
36
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
If there were to be any arrearage in dividends on any of its preferred stock or
in the sinking fund requirements applicable to any of its redeemable preferred
stock, the Company could not pay dividends on its common stock or acquire any
shares thereof for consideration. The redemption requirements for the above
issues for the next three years are: 1998, $10.0 million; 1999, $10.0 million;
and 2000, $9.1 million. There are no redemption requirements in 2001 and 2002.
Redeemable preferred stock transactions during each of the three years in the
period ended December 31 are as follows:
<TABLE>
<CAPTION>
Number of Shares Par Value
Outstanding Outstanding
------------------------------- ------------------------------
(Thousands of Dollars)
Description 1997 1996 1995 1997 1996 1995
- --------------------------------- --------- --------- ------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Balance, January 1 .............. 530,000 750,000 750,000 $ 53,000 $ 75,000 $ 75,000
Retirements:
$10.00 Series U ........... (118,902) (90,000) -- (11,890) (9,000) --
$7.875 Series V ........... (120,000) (130,000) -- (12,000) (13,000) --
------- ------- ------- -------- -------- --------
Balance, December 31 ............ 291,098 530,000 750,000 $ 29,110 $ 53,000 $ 75,000
======= ======= ======= ======== ======== ========
</TABLE>
37
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
5. Long-Term Debt
The following table presents long-term debt outstanding:
<TABLE>
<CAPTION>
December 31,
----------------------
Maturity Dates (a) 1997 1996
------------------ -------- --------
(Thousands of Dollars)
<S> <C> <C> <C>
First Mortgage Bonds
7.125% Series .................................. 1997 $ -- $150,000
7.625% Series .................................. 1998 100,000 100,000
7.625% Series .................................. 1999 100,000 100,000
5.75% Series .................................. 2000 100,000 100,000
8.125% Series .................................. 2002 125,000 125,000
6.625% Series .................................. 2004 85,000 100,000
10.25% Series .................................. 2020 109,550 114,550
9.5% Series .................................. 2021 45,140 50,810
9% Series .................................. 2021 72,370 72,500
7.25% Series .................................. 2023 97,150 100,000
8.75% Series .................................. 2024 121,918 148,500
8% Series .................................. 2025 88,500 116,900
5.5% Series .................................. 2028 25,000 25,000
5.875% Series .................................. 2028 154,000 154,000
Unamortized discount and premium ................. (7,033) (8,412)
Pollution control indebtedness, adjustable rate (b) ....... 2024-2031 439,990 439,990
Collateralized Loan, 6.125% ............................... 1999 10,000 --
Senior notes, 6.75% (c) ................................... 2006 100,000 100,000
Senior notes, 6.72% (c) ................................... 1999 50,000 --
Debentures, 10% ........................................... 2025 75,000 75,000
Bank loans, adjustable rate (d) ........................... 2002 150,000 100,000
Capitalized lease obligation, 7.48% (e) ................... 1997-2001 15,645 19,424
---------- ----------
Total long-term debt ................................... 2,057,230 2,183,262
Less current maturities ................................... 104,068 153,780
---------- ----------
Total long-term debt less current maturities ........... $1,953,162 $2,029,482
========== ==========
</TABLE>
- ---------------
(a) This schedule does not reflect the timing of redemptions which may occur
prior to maturity.
(b) The weighted-average rate for the years ended December 31, 1997 and 1996
was 3.62% and 3.40%, respectively. Changes in short-term interest rates
would affect the costs associated with this debt.
(c) The Company has issued $150 million of first mortgage bonds ("senior note
mortgage bonds") to the senior note trustee as collateral for the senior
notes. The senior note mortgage bonds have the same interest rate, interest
payment dates, maturity, and redemption provisions as the senior notes. The
Company's payments of principal, premium, and/or interest on the senior
notes satisfy the Company's 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 pari passu with the
first mortgage bonds. On the date that the Company has repaid 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.
38
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
(d) The weighted-average rate at December 31, 1997 and 1996 was 6.25% and
5.76%, respectively. Changes in short-term interest rates would affect the
costs associated with this debt.
(e) Represents the present value of future lease payments (discounted at an
interest rate of 7.48%) on a combined cycle plant sold and leased back from
the independent owner-trustee formed to own the facility (see Note 9).
Aggregate annual principal payments due on total long-term debt and for sinking
fund requirements through 2002 are as follows: 1998, $104.1 million; 1999,
$164.4 million; 2000, $104.7 million; 2001, $2.5 million; and 2002, $275
million. See Note 4 for redemption and sinking fund requirements of redeemable
preferred stock of the Company.
Substantially all utility plant (other than nuclear fuel, transportation
equipment and the combined cycle plant) is subject to the lien of the mortgage
bond indenture. The mortgage bond indenture includes provisions which would
restrict the payment of common stock dividends under certain conditions which
did not exist at December 31, 1997.
6. Lines of Credit
The Company had committed lines of credit with various banks of $400 million at
December 31, 1997 and 1996, which were available either to support the issuance
of commercial paper or to be used for bank borrowings. The commitment fees at
December 31, 1997 and 1996 for these lines of credit ranged from .07% to .15%
per annum. The Company had long-term bank borrowings of $150 million and $100
million outstanding at December 31, 1997 and 1996, respectively, under these
lines of credit.
The Company had commercial paper borrowings outstanding of $130.8 million and
$16.9 million at December 31, 1997 and 1996, respectively. The weighted average
interest rate on commercial paper borrowings was 6.27% and 6.40% on December 31,
1997 and 1996, respectively. By Arizona statute, the Company's short-term
borrowings cannot exceed 7% of its total capitalization without the consent of
the ACC.
7. Fair Value of Financial Instruments
The Company estimates that the carrying amounts of its cash equivalents and
commercial paper are reasonable estimates of their fair values at December 31,
1997 and 1996 due to their short maturities. Investments in debt and equity
securities are held for purposes other than trading. The December 31, 1997 and
1996 fair values of such investments, determined by using quoted market values
or by discounting cash flows at rates equal to the Company's cost of capital,
approximate their carrying amounts.
The carrying value of long-term debt (excluding a capitalized lease obligation)
on December 31, 1997 and 1996 was $2.04 billion and $2.16 billion, respectively,
and the estimated fair value was $2.08 billion and $2.13 billion, respectively.
The fair value estimates are based on quoted market prices of the same or
similar issues.
39
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
8. Jointly-Owned Facilities
At December 31, 1997, the Company owned interests in the following jointly-owned
electric generating and transmission facilities. The Company's share of related
operating and maintenance expenses is included in utility operations and
maintenance.
<TABLE>
<CAPTION>
Percent Construction
Owned by Plant in Accumulated Work in
Company Service Depreciation Progress
-------- -------- ------------ ------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Generating Facilities:
Palo Verde Nuclear Generating Station
Units 1 and 3 29.1% $1,830,794 $ 628,960 $ 14,498
Palo Verde Nuclear Generating Station
Unit 2 (see Note 9) 17.0% 572,054 213,717 9,338
Four Corners Steam Generating Station
Units 4 and 5 15.0% 148,342 66,470 1,369
Navajo Steam Generating Station
Units 1, 2 and 3 14.0% 182,637 82,326 33,081(a)
Cholla Steam Generating Station
Common Facilities (b) 62.8%(c) 66,106 34,551 580
Transmission Facilities:
ANPP 500KV System 35.8%(c) 62,593 19,107 4,903
Navajo Southern System 31.4%(c) 27,159 16,710 --
Palo Verde-Yuma 500KV System 23.9%(c) 11,376 3,971 --
Four Corners Switchyards 27.5%(c) 3,071 1,707 1
Phoenix-Mead System 17.1%(c) 36,418 (2,169) 337
</TABLE>
- ---------------
(a) The construction costs at Navajo are primarily related to the installation
of scrubbers required by recent environmental legislation.
(b) The Company is the operating agent for Cholla Unit 4, which is owned by
PacifiCorp. The common facilities at the Cholla Plant are jointly-owned.
(c) Weighted average of interests.
9. Leases
In 1986, the Company entered into sale and leaseback transactions under which it
sold approximately 42% of its share of Palo Verde Unit 2 and certain common
facilities. The gain of approximately $140.2 million has been deferred and is
being amortized to operations expense over the original lease term. The leases
are being accounted for as operating leases. The amounts to be paid each year
approximate $40.1 million through 1999, $46.3 million in 2000 and $49.0 million
through 2015. Options to renew for two additional years and to purchase the
property at fair market value at the end of the lease terms are also included.
Consistent with the
40
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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.
In accordance with the 1996 regulatory agreement (see Note 3), the ACC
accelerated the Company's amortization of the regulatory asset for leases to an
eight-year period that began July 1, 1996. The accelerated amortization is
included in depreciation and amortization expense on the Statements of Income.
The balance of this regulatory asset at December 31, 1997 was $53.2 million.
Lease expense was approximately $42 million in each of the years 1995 through
1997.
The Company has a capital lease on a combined cycle plant which it sold and
leased back. The lease requires semiannual payments of $2.6 million through June
2001, and includes renewal and purchase options based on fair market value. This
plant is included in plant in service at its original cost of $54.4 million;
accumulated amortization at December 31, 1997 was $46.5 million.
In addition, the Company leases certain land, buildings, equipment and
miscellaneous other items through operating rental agreements with varying
terms, provisions and expiration dates. Rent expense for 1997, 1996 and 1995 was
approximately $7.8 million, $9.7 million and $9.9 million, respectively. Annual
future minimum rental commitments, excluding the Palo Verde and combined cycle
leases, for the period 1998 through 2002 range between $13 million and $15
million. Total rental commitments after the year 2002 are estimated at $99
million.
10. Income Taxes
The Company is included in the consolidated income tax returns of Pinnacle West.
Income taxes are allocated to the Company based on its separate company taxable
income or loss. Beginning in 1995, substantially all ITCs are being amortized
over a five-year period in accordance with a 1994 rate settlement agreement.
The Company follows the liability method of accounting for income taxes which
requires that deferred income taxes be recorded for all temporary differences
between the tax bases of assets and liabilities and the amounts recognized for
financial reporting. Deferred taxes are recorded using currently enacted tax
rates.
In accordance with SFAS No. 71, a regulatory asset has been established for
certain temporary differences, primarily AFUDC equity, to reflect the ratemaking
treatment. This regulatory asset is being amortized as the related differences
reverse. In accordance with the 1996 regulatory agreement (see Note 3), the ACC
accelerated the Company's amortization of the regulatory asset for income taxes
to an eight-year period beginning July 1, 1996. The accelerated portion of the
regulatory asset amortization is included in depreciation and amortization
expense on the Statements of Income.
41
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The components of income tax expense are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1997 1996 1995
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Current:
Federal ................................................. $ 187,701 $ 137,531 $ 120,196
State ................................................... 48,531 35,777 33,368
--------- --------- ---------
Total current ............................ 236,232 173,308 153,564
Deferred ................................................... (55,278) (869) 17,933
Change in valuation allowance .............................. -- (11,848) (2,589)
Investment tax credit amortization ......................... (27,630) (27,630) (27,641)
--------- --------- ---------
Total expense ............................ $ 153,324 $ 132,961 $ 141,267
========= ========= =========
</TABLE>
Income tax expense differed from the amount computed by multiplying income
before income taxes by the statutory federal income tax rate due to the
following:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1997 1996 1995
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Federal income tax expense at statutory rate, 35% ........... $ 141,686 $ 131,751 $ 133,293
Increases (reductions) in tax expense resulting from:
Tax under book depreciation .............................. 14,694 19,229 18,186
Investment tax credit amortization ....................... (27,630) (27,630) (27,641)
State income tax --- net of federal income tax benefit ... 23,160 20,790 21,770
Change in valuation allowance ............................ -- (10,269) (2,245)
Other .................................................... 1,414 (910) (2,096)
--------- --------- ---------
Income tax expense .............................. $ 153,324 $ 132,961 $ 141,267
========= ========= =========
</TABLE>
42
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows:
<TABLE>
<CAPTION>
December 31,
-------------------------
1997 1996
---------- ----------
(Thousands of Dollars)
<S> <C> <C>
Deferred tax assets:
Deferred gain on Palo Verde Unit 2 sale/leaseback ........................ $ 33,257 $ 35,105
Other .................................................................... 77,412 71,725
---------- ----------
Total deferred tax assets .............................................. 110,669 106,830
---------- ----------
Deferred tax liabilities:
Plant related ............................................................ 1,096,222 1,104,902
Regulatory asset for income taxes......................................... 185,084 208,647
Rate synchronization deferrals ........................................... 144,908 167,202
Other .................................................................... 26,136 31,897
---------- ----------
Total deferred tax liabilities ......................................... 1,452,350 1,512,648
---------- ----------
Deferred income taxes --- net .............................................. $1,341,681 $1,405,818
========== ==========
</TABLE>
11. Retirement Plans and Other Benefits
Voluntary Severance Plan The Company sponsored a voluntary severance plan in
1996, which resulted in a pretax charge of $31.7 million (including pension and
postretirement benefit expense) recorded primarily as operations and maintenance
expense. Employees participating in the plan were credited with an additional
year of age and service for purposes of calculating pension and postretirement
benefits. The total additional pension and postretirement benefit expense
recorded in 1996 for this program was $2.3 million and $5.4 million,
respectively.
Pension Plan The Company sponsors a defined benefit pension plan covering
substantially all employees. Benefits are based on years of service and
compensation utilizing a final average pay benefit formula. Company policy is to
fund not less than the minimum required contribution nor greater than the
maximum tax-deductible contribution. Plan assets consist primarily of domestic
and international common stocks and bonds and real estate. Pension expense,
including administrative and severance costs, for 1997, 1996 and 1995 was
approximately $8.7 million, $14.9 million and $9.6 million, respectively.
43
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The components of net periodic pension costs before consideration of amounts
capitalized or billed to others and excluding severance costs of $2.9 million in
1996 are as follows:
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost --- benefits earned during the period ............. $ 19,881 $ 22,861 $ 16,038
Interest cost on projected benefit obligation .................. 47,824 44,602 39,328
Return on plan assets .......................................... (87,582) (62,460) (82,209)
Net amortization and deferral .................................. 39,007 19,734 45,976
-------- -------- --------
Net periodic pension cost ...................................... $ 19,130 $ 24,737 $ 19,133
======== ======== ========
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized in
the balance sheets is presented below:
<TABLE>
<CAPTION>
1997 1996
--------- ---------
(Thousands of Dollars)
<S> <C> <C>
Plan assets at fair value ................................................. $ 612,392 $ 533,444
--------- ---------
Less:
Accumulated benefit obligation, including vested benefits
of $493,838 and $413,004 in 1997 and 1996, respectively......... 552,391 467,037
Effect of projected future compensation increases ................ 147,209 134,057
--------- ---------
Total projected benefit obligation ........................................ 699,600 601,094
--------- ---------
Plan assets less than projected benefit obligation ........................ (87,208) (67,650)
Plus:
Unrecognized net loss from past experience
different from that assumed .................................... 16,989 2,818
Unrecognized prior service cost .................................. 24,625 20,478
Unrecognized net transition asset ................................ (26,376) (29,593)
--------- ---------
Accrued pension liability ................................................. $ (71,970) $ (73,947)
========= =========
Principal actuarial assumptions used were:
Discount rate .................................................... 7.25% 7.75%
Rate of increase in compensation levels .......................... 4.50% 4.50%
Expected long-term rate of return on assets ...................... 9.00% 9.00%
</TABLE>
In addition to the defined benefit pension plan, the Company also sponsors
qualified defined contribution plans. Collectively, these plans cover
substantially all employees. The plans provide for employee contributions and
partial employer matching contributions after certain eligibility requirements
are met. Expenses related to these plans for 1997, 1996 and 1995 were $3.7
million, $3.4 million and $3.1 million, respectively.
Postretirement Plans The Company provides medical and life insurance benefits to
its retired employees. Employees must retire to become eligible for these
retirement benefits, which are based on years of service and age. The retiree
medical insurance plans are contributory; the retiree life insurance plans are
noncontributory. In accordance with the governing plan documents, the Company
retains the right to change or eliminate these benefits.
44
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
Funding is based upon actuarially determined contributions that take tax
consequences into account. Plan assets consist primarily of domestic stocks and
bonds. The postretirement benefit expense for 1997, 1996 and 1995 was
approximately $9.4 million, $15.8 million and $13.3 million, respectively.
The components of net periodic postretirement benefit costs before consideration
of amounts capitalized or billed to others and excluding severance costs of $9.6
million in 1996 are as follows:
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost --- benefits earned during the period.............. $ 6,865 $ 7,974 $ 6,735
Interest cost on accumulated benefit obligation ................ 14,315 13,395 13,743
Return on plan assets .......................................... (30,846) (12,550) (15,133)
Net amortization and deferral .................................. 27,145 12,733 17,142
-------- -------- --------
Net periodic postretirement benefit cost ....................... $ 17,479 $ 21,552 $ 22,487
======== ======== ========
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized in
the balance sheet is presented below:
<TABLE>
<CAPTION>
1997 1996
--------- ---------
(Thousands of Dollars)
<S> <C> <C>
Plan assets at fair value .................................................. 151,146 $ 109,763
--------- ---------
Less accumulated postretirement benefit obligation:
Retirees .......................................................... 94,839 86,747
Fully eligible plan participants .................................. 5,927 3,351
Other active plan participants .................................... 96,815 89,452
--------- ---------
Total accumulated postretirement benefit obligation ...... 197,581 179,550
--------- ---------
Plan assets less than accumulated benefit obligation ....................... (46,435) (69,787)
Plus:
Unrecognized transition obligation ................................ 114,787 122,439
Unrecognized net gain from past experience different from that
assumed ......................................................... (78,209) (62,299)
--------- ---------
Accrued postretirement liability ........................................... $ (9,857) $ (9,647)
========= =========
Principal actuarial assumptions used were:
Discount rate ..................................................... 7.25% 7.75%
Annual salary increases for life insurance obligation ............. 4.50% 4.50%
Expected long-term rate of return on assets --- after tax ......... 7.75% 7.75%
Initial health care cost trend rate --- under age 65 .............. 8.00% 9.00%
Initial health care cost trend rate --- age 65 and over ........... 7.00% 8.00%
Ultimate health care cost trend rate (reached in the year 2002).... 5.00% 5.50%
</TABLE>
Assuming a 1% increase in the health care cost trend rate, the 1997 cost of
postretirement benefits other than pensions would increase by approximately $6
million and the accumulated benefit obligation as of December 31, 1997 would
increase by approximately $34 million.
45
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
12. Commitments and Contingencies
Litigation The Company is a party to various claims, legal actions and
complaints arising in the ordinary course of business. In the opinion of
management, the ultimate resolution of these matters will not have a material
adverse effect on the Company's financial statements.
Palo Verde Nuclear Generating Station The Company has encountered tube cracking
in steam generators and has taken, and will continue to take, remedial actions
that it believes have slowed the rate of tube degradation. The projected service
life of the steam generators is reassessed periodically and these analyses
indicate that it will be economically desirable for the Company to replace the
Unit 2 steam generators between 2003 and 2008. The Company estimates that its
share of the replacement costs (in 1997 dollars and including installation and
replacement power costs) will be approximately $50 million, most of which will
be incurred after the year 2000.
During the fourth quarter of 1997, the Palo Verde participants, including the
Company, entered into a contract for the fabrication of two replacement steam
generators. The cost to the Company is estimated at approximately $26 million.
These generators will be used as replacements if performance of existing
generators deteriorates to less than acceptable levels. The generators are
expected on site in 2002. The Company's share of installation costs is
approximately $24 million.
Based on the latest available data, the Company estimates that the Unit 1 and
Unit 3 steam generators should operate for the license periods (until 2025 and
2027, respectively), although the Company will continue its normal periodic
assessment of these steam generators.
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
November 1997 the Court of Appeals for the D.C. Circuit affirmed its previous
decision that DOE must begin accepting spent fuel by 1998 and issued an order
precluding DOE from excusing its own delay on the grounds that DOE has not yet
prepared a permanent repository or interim storage facility.
The Company 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. The Company 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 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, the Company
could be assessed retrospective premium adjustments. The maximum assessment per
reactor under the program for each nuclear incident is approximately $79
million, subject to an annual limit of $10 million per incident. Based upon the
Company's 29.1% interest in the three Palo Verde units, the Company's maximum
potential assessment per incident for all three units is approximately $69
million, with an annual payment limitation of approximately $9 million.
46
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. The Company 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 The Company is a party to various fuel and
purchased power contracts with terms expiring from 1998 through 2020 that
include required purchase provisions. The Company estimates its 1998 contract
requirements to be approximately $136 million. However, this amount may vary
significantly pursuant to certain provisions in such contracts which permit the
Company to decrease its required purchases under certain circumstances.
The Company is contractually obligated to reimburse certain coal providers for
amounts incurred for coal mine reclamation. The Company's share of the total
obligation is estimated at $110 million. The portion of the coal mine
reclamation obligation related to coal already burned is approximately $66
million at December 31, 1997 and is included in "Deferred Credits --- Other" in
the Balance Sheet. A regulatory asset has been established for amounts not yet
recovered from ratepayers. In accordance with the 1996 regulatory agreement (see
Note 3), the ACC began accelerated amortization of the Company's regulatory
asset for coal mine reclamation costs over an eight-year period beginning July
1, 1996. Amortization is included in depreciation and amortization expense on
the Statements of Income. The balance of the regulatory asset at December 31,
1997 was approximately $60 million.
Construction Program Total capital expenditures in 1998 are estimated at $323
million.
13. Nuclear Decommissioning Costs
The Company recorded $11.4 million for decommissioning expense in each of the
years 1997 and 1996. The Company estimates it will cost approximately $2.0
billion ($460 million in 1997 dollars), over a 14 year period beginning in 2024,
to decommission its 29.1% interest in the three Palo Verde units.
Decommissioning costs are charged to expense over the respective unit's
operating license term and are included in the accumulated depreciation balance
until each unit is retired. Nuclear decommissioning costs are recovered in
rates.
The Company is utilizing a 1995 site-specific study for Palo Verde, prepared for
the Company by an independent consultant, that assumes the prompt
removal/dismantlement method of decommissioning. The Company is required to
update the study every three years.
As required by regulation, the Company has established external trust accounts
into which quarterly deposits are made for decommissioning. As of December 31,
1997 and 1996, the Company had deposited a total of $79.5 million and $68.1
million, respectively. The trust accounts are included in "Investments and Other
Assets" on the Balance Sheets at a market value of $124.6 million and $95.5
million on December 31, 1997 and 1996, respectively. The trust funds are
invested primarily in fixed-income securities and domestic stock and are
classified as available for sale. Realized and unrealized gains and losses are
reflected in accumulated depreciation.
In February 1996, the FASB issued an exposure draft "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets" which would
require the estimated present value of the cost of decommissioning and certain
other removal costs to be recorded as a liability, along with an offsetting
plant asset when a decommissioning or other removal obligation is incurred. The
FASB has not determined when a revised exposure draft or a final statement will
be issued.
47
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
14. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 1997 and 1996 is as follows:
Electric Net Earnings (Loss)
Operating Operating Income for
Quarter Revenues Income(a) (Loss) Common Stock
- ------- --------- --------- ------ ---------------
(Thousands of Dollars)
1997
First $ 379,021 $ 61,439 $ 28,645 $ 25,019
Second 458,751 99,706 69,493 66,298
Third 632,821 150,892 129,699 126,715
Fourth 407,960 59,788 23,656 20,658
1996
First $ 345,261 $ 77,522 $ 45,606 $ 41,129
Second 426,658 102,978 70,440 66,114
Third 566,899 152,307 128,484 124,331
Fourth (b) 379,454 32,401 (1,059) (5,195)
- ---------------
(a) The Company's operations are subject to seasonal fluctuations primarily as
a result of weather conditions. The results of operations for interim
periods are not necessarily indicative of the results to be expected for
the full year.
(b) Net loss for the fourth quarter of 1996 includes an after-tax charge of
$18.9 million for a voluntary severance program.
48
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
15. Stock Options
Pinnacle West, the Company's parent, has incentive plans under which it may
grant non-qualified stock options (NQSOs), incentive stock options (ISOs) and
restricted stock awards to Pinnacle West and APS officers and key employees.
The plans provide for the granting of new options or awards of up to 3.5 million
shares at a price per option not less than fair market value on the date the
option is granted. The plans also provide for the granting of any combination of
stock appreciation rights or dividend equivalents. The awards outstanding under
the various incentive plans at December 31, 1997 approximate 1,486,417 NQSOs,
183,190 restricted shares, and no dividend equivalent shares, ISOs or stock
appreciation rights.
The FASB issued SFAS No. 123 "Accounting for Stock-Based Compensation" which was
effective for 1996. The statement encourages, but does not require, companies to
recognize compensation expense based on the fair value method. The Company
continues to recognize expense based on Accounting Principles Board Opinion No.
25. Had the Company determined compensation expense based on the fair value
method, the Company's net income would have been reduced to the pro forma
amounts indicated below:
1997 1996 1995
-------- -------- --------
(Thousands of Dollars)
Net income
As reported ............ $251,493 $243,471 $239,570
Pro forma .............. $251,142 $243,291 $239,547
The fair value of each fixed stock option is estimated on the date of grant
using the Black-Scholes option-pricing model with the following weighted-average
assumptions:
1997 1996 1995
------ ------ ------
Risk-free interest rate ....... 5.66% 5.77% 5.43%
Dividend growth ............... 4.50% 4.50% 4.50%
Volatility .................... 15.63% 17.10% 12.60%
Expected life (months) ........ 60 58 56
The effects of applying SFAS No. 123 for disclosing compensation cost may not be
representative of the effects on reported net income for future years because
pro forma net income does not consider compensation costs for stock options
granted prior to January 1, 1995.
49
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" in the Company's Proxy
Statement relating to the annual meeting of shareholders to be held on May 19,
1998 (the "1998 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, fifth, sixth and seventh paragraphs
under the heading "The Board and its Committees," to "Executive Compensation,"
to "Report of the Human Resources Committee," to "Performance Graph" and to
"Executive Benefit Plans" in the 1998 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Principal Holders of Voting Securities" and
"Ownership of Pinnacle West Securities by Management" in the 1998 Proxy
Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to the last two paragraphs under the heading "The
Board and its Committees" and to "Executive Benefit Plans --- Employment and
Severance Agreements" in the 1998 Proxy Statement.
50
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements
See the Index to Financial Statements in Part II, Item 8 on page 24.
Exhibits Filed
Exhibit No. Description
- ----------- -----------
10.1(a) --- 1998 Management Variable Incentive Plan
10.2(a) --- 1998 Senior Management Variable Incentive Plan
10.3(a) --- 1998 Officers Variable Incentive Plan
23.1 --- Consent of Deloitte & Touche LLP
27.1 --- Financial Data Schedule
In addition to those Exhibits shown above, the Company hereby incorporates
the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation
ss.229.10(d) by reference to the filings set forth below:
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96
February 20, 1996 Report
3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95
Directors temporarily Report
suspending Bylaws in part
3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, 1988 Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report
3.4 Certificates pursuant to 4.3 to Form S-3 1-4473 9-29-93
Sections 10-152.01 and Registration Nos.
10-016, Arizona Revised 33-33910 and 33-55248 by
Statutes, establishing Series A means of September 24,
through V of the Company's 1993 Form 8-K Report
Serial Preferred Stock
</TABLE>
51
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
3.5 Certificate pursuant to 4.4 to Form S-3 1-4473 9-29-93
Section 10-016, Arizona Registration Nos.
Revised Statutes, establishing 33-33910 and 33-55248 by
Series W of the Company's means of September 24,
Serial Preferred Stock 1993 Form 8-K Report
4.1 Mortgage and Deed of Trust 4.1 to September 1992 1-4473 11-9-92
Relating to the Company's Form 10-Q Report
First Mortgage Bonds,
together with forty-eight
indentures supplemental
thereto
4.2 Forty-ninth Supplemental 4.1 to 1992 Form 10-K 1-4473 3-30-93
Indenture Report
4.3 Fiftieth Supplemental 4.2 to 1993 Form 10-K 1-4473 3-30-94
Indenture Report
4.4 Fifty-first Supplemental 4.1 to August 1, 1993 1-4473 9-27-93
Indenture Form 8-K Report
4.5 Fifty-second Supplemental 4.1 to September 30, 1993 1-4473 11-15-93
Indenture Form 10-Q Report
4.6 Fifty-third Supplemental 4.5 to Registration 1-4473 3-1-94
Indenture Statement No. 33-61228
by means of February 23,
1994 Form 8-K Report
4.7 Fifty-fourth Supplemental 4.1 to Registration 1-4473 11-22-96
Indenture Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996
Form 8-K Report
4.8 Fifty-fifth Supplemental 4.8 to Registration 1-4473 4-9-97
Indenture Statement Nos. 33-55473,
33-64455 and 333-15379
by means of April 7, 1997
Form 8-K Report
4.9 Agreement, dated March 21, 4.1 to 1993 Form 10-K 1-4473 3-30-94
1994, relating to the filing of Report
instruments defining the
rights of holders of long-term
debt not in excess of 10% of
the Company's total assets
</TABLE>
52
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
4.10 Indenture dated as of January 4.6 to Registration 1-4473 1-11-95
1, 1995 among the Company Statement Nos. 33-61228
and The Bank of New York, and 33-55473 by means of
as Trustee January 1, 1995 Form 8-K
Report
4.11 First Supplemental Indenture 4.4 to Registration 1-4473 1-11-95
dated as of January 1, 1995 Statement Nos. 33-61228
and 33-55473 by means of
January 1, 1995 Form 8-K
Report
4.12 Indenture dated as of 4.5 to Registration 1-4473 11-22-96
November 15, 1996 among Statements Nos. 33-61228,
the Company and The Bank 33-55473, 33-64455 and
of New York, as Trustee 333-15379 by means of
November 19, 1996
Form 8-K Report
4.13 First Supplemental Indenture 4.6 to Registration 1-4473 11-22-96
Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996
Form 8-K Report
4.14 Second Supplemental Indenture 4.10 to Registration 1-4473 4-9-97
dated as of April 1, 1997 Statement Nos. 33-55473,
33-64455 and 333-15379
by means of April 7, 1997
Form 8-K Report
4.15 Indenture dated as of January 4.10 to Registration 1-4473 1-16-98
15, 1998 among the Company Statement Nos. 333-15379
and The Chase Manhattan and 333-27551 by means
Bank, as Trustee of January 13, 1998
Form 8-K Report
4.16 First Supplemental Indenture 4.3 to Registration 1-4473 1-16-98
dated as of January 15, 1998 Statement Nos. 333-15379
and 333-27551 by means
of January 13, 1998
Form 8-K Report
</TABLE>
53
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
4.17 Agreement of Resignation, 4.1 to September 25, 1995 1-4473 10-24-95
Appointment, Acceptance and Form 8-K Report
Assignment dated as of
August 18, 1995 by and
among the Company, Bank of
America National Trust and
Savings Association and The
Bank of New York
10.4 Two separate 10.2 to September 1991 1-4473 11-14-91
Decommissioning Trust Form 10-Q
Agreements (relating to
PVNGS Units 1 and 3,
respectively), each dated July
1, 1991, between the Company
and Mellon Bank, N.A., as
Decommissioning Trustee
10.5 Amendment No. 1 to 10.1 to 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 1)
dated as of December 1, 1994
10.6 Amendment No. 2 to 10.4 to 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 1)
dated as of July 1, 1991
10.7 Amendment No. 1 to 10.2 to 1994 Form 10-K 1-4473 3-30-95
Decommissioning Trust Report
Agreement (PVNGS Unit 3)
dated as of December 1, 1994
10.8 Amendment No. 2 to 10.6 to 1996 Form 10-K 1-4473 3-28-97
Decommissioning Trust Report
Agreement (PVNGS Unit 3)
dated as of July 1, 1991
</TABLE>
54
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.9 Amended and Restated 10.1 to Pinnacle West 1-8962 3-26-92
Decommissioning Trust 1991 Form 10-K Report
Agreement (PVNGS Unit 2)
dated as of January 31, 1992,
among the Company, Mellon
Bank, N.A., as
Decommissioning Trustee, and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
under two separate Trust
Agreements, each with a
separate Equity Participant,
and as Lessor under two
separate Facility Leases, each
relating to an undivided
interest in PVNGS Unit 2
10.10 First Amendment to Amended 10.2 to 1992 Form 10-K 1-4473 3-30-93
and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2),
dated as of November 1, 1992
10.11 Amendment No. 2 to Amended 10.3 to 1994 Form 10-K 1-4473 3-30-95
and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2)
dated as of November 1, 1994
10.12 Amendment No. 3 to Amended 10.1 to June 1996 Form 1-4473 8-9-96
and Restated 10-Q Report
Decommissioning Trust
Agreement (PVNGS Unit 2)
dated as of January 31, 1992
10.13 Amendment No. 4 to Amended 10.5 to 1996 Form 10-K 1-4473 3-28-97
and Restated Report
Decommissioning Trust
Agreement (PVNGS Unit 2)
dated as of January 31, 1992
10.14 Asset Purchase and Power 10.1 to June 1991 Form 1-4473 8-8-91
Exchange Agreement dated 10-Q Report
September 21, 1990 between
the Company and PacifiCorp,
as amended as of October 11,
1990 and as of July 18, 1991
</TABLE>
55
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.15 Long-Term Power 10.2 to June 1991 Form 1-4473 8-8-91
Transactions Agreement dated 10-Q Report
September 21, 1990 between
the Company and PacifiCorp,
as amended as of October 11,
1990 and as of July 8, 1991
10.16 Contract, dated July 21, 1984, 10.31 to Pinnacle West's 2-96386 3-13-85
with DOE providing for the Form S-14 Registration
disposal of nuclear fuel and/or Statement
high-level radioactive waste,
ANPP
10.17 Amendment No. 1 dated 10.3 to 1995 Form 10-K 1-4473 3-29-96
April 5, 1995 to the Long-Term Report
Power Transactions Agreement
and Asset Purchase and Power
Exchange Agreement between
PacifiCorp and the Company
10.18 Restated Transmission 10.4 to 1995 Form 10-K 1-4473 3-29-96
Agreement between PacifiCorp Report
and the Company dated
April 5, 1995
10.19 Contract among PacifiCorp, 10.5 to 1995 Form 10-K 1-4473 3-29-96
the Company and United Report
States Department of Energy
Western Area Power
Administration, Salt Lake
Area Integrated Projects
for Firm Transmission
Service dated May 5, 1995
10.20 Reciprocal Transmission 10.6 to 1995 Form 10-K 1-4473 3-29-96
Service Agreement between Report
the Company and PacifiCorp
dated as of March 2, 1994
10.21 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Four Registration Statement
Corners Plant
10.22 Supplemental and Additional 5.02 to Form S-7 2-59644 9-1-77
Indenture of Lease, including Registration Statement
amendments and supplements
to original lease with Navajo
Tribe of Indians, Four Corners
Plant
</TABLE>
56
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.23 Amendment and Supplement 10.36 to Registration 1-8962 7-25-85
No. 1 to Supplemental and Statement on Form 8-B of
Additional Indenture of Lease, Pinnacle West
Four Corners, dated April 25,
1985
10.24 Application and Grant of 5.04 to Form S-7 2-59644 9-1-77
multi-party rights-of-way and Registration Statement
easements, Four Corners
Plant Site
10.25 Application and Amendment 10.37 to Registration 1-8962 7-25-85
No. 1 to Grant of multi-party Statement on Form 8-B of
rights-of-way and easements, Pinnacle West
Four Corners Power Plant
Site, dated April 25, 1985
10.26 Application and Grant of 5.05 to Form S-7 2-59644 9-1-77
Arizona Public Service Registration Statement
Company rights-of-way and
easements, Four Corners
Plant Site
10.27 Application and Amendment 10.38 to Registration 1-8962 7-25-85
No. 1 to Grant of Arizona Statement on Form 8-B of
Public Service Company Pinnacle West
rights-of-way and easements,
Four Corners Power Plant
Site, dated April 25, 1985
10.28 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.29 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70
rights-of-way and easements, Registration Statement
Navajo Plant
10.30 Water Service Contract 5(l) to Form S-7 2-39442 3-16-71
Assignment with the United Registration Statement
States Department of Interior,
Bureau of Reclamation,
Navajo Plant
</TABLE>
57
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.31 Arizona Nuclear Power 10.1 to 1988 Form 10-K 1-4473 3-8-89
Project Participation Report
Agreement, dated August 23,
1973, among the Company,
Salt River Project Agricultural
Improvement and Power
District, Southern California
Edison Company, Public
Service Company of New
Mexico, El Paso Electric
Company, Southern California
Public Power Authority, and
Department of Water and
Power of the City of Los
Angeles, and amendments
1-12 thereto
10.32 Amendment No. 13 dated as 10.1 to March 1991 Form 1-4473 5-15-91
of April 22, 1991, to Arizona 10-Q Report
Nuclear Power Project
Participation Agreement,
dated August 23, 1973, among
the Company, Salt River
Project Agricultural
Improvement and Power
District, Southern California
Edison Company, Public
Service Company of New
Mexico, El Paso Electric
Company, Southern California
Public Power Authority, and
Department of Water and
Power of the City of Los
Angeles
10.33(c) Facility Lease, dated as of 4.3 to Form S-3 33-9480 10-24-86
August 1, 1986, between Registration Statement
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor, and
the Company, as Lessee
</TABLE>
58
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.34(c) Amendment No. 1, dated as of 10.5 to September 1986 1-4473 12-4-86
November 1, 1986, to Facility Form 10-Q Report by
Lease, dated as of August 1, means of Amendment No.
1986, between State Street 1 on December 3, 1986
Bank and Trust Company, as Form 8
successor to The First
National Bank of Boston, in
its capacity as Owner Trustee,
as Lessor, and the Company,
as Lessee
10.35(c) Amendment No. 2 dated as of 10.3 to 1988 Form 10-K 1-4473 3-8-89
June 1, 1987 to Facility Lease Report
dated as of August 1, 1986
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and APS, as Lessee
10.36(c) Amendment No. 3, dated as of 10.3 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and the Company, as
Lessee
10.37 Facility Lease, dated as of 10.1 to November 18, 1986 1-4473 1-20-87
December 15, 1986, between Form 8-K Report
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its capacity as
Owner Trustee, as Lessor, and
the Company, as Lessee
10.38 Amendment No. 1, dated as of 4.13 to Form S-3 1-4473 8-24-87
August 1, 1987, to Facility Registration Statement
Lease, dated as of December No. 33-9480 by means of
15, 1986, between State Street August 1, 1987 Form 8-K
Bank and Trust Company, as Report
successor to The First
National Bank of Boston, as
Lessor, and the Company, as
Lessee
</TABLE>
59
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.39 Amendment No. 2, dated as of 10.4 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Facility Report
Lease, dated as of December
15, 1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Lessor, and the Company, as
Lessee
10.40(a) Directors' Deferred 10.1 to June 1986 Form 1-4473 8-13-86
Compensation Plan, as 10-Q Report
restated, effective January 1,
1986
10.41(a) Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Directors' Deferred
Compensation Plan, effective
as of January 1, 1993
10.42(a) Third Amendment to the 10.1 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q
Company Directors' Deferred
Compensation Plan effective
as of May 1, 1993
10.43(a) Arizona Public Service 10.4 to 1988 Form 10-K 1-4473 3-8-89
Company Deferred Report
Compensation Plan, as
restated, effective January 1,
1984, and the second and
third amendments thereto,
dated December 22, 1986, and
December 23, 1987,
respectively
10.44(a) Third Amendment to the 10.3 to 1993 Form 10-K 1-4473 3-30-94
Arizona Public Service Report
Company Deferred
Compensation Plan, effective
as of January 1, 1993
10.45(a) Fourth Amendment to the 10.2 to September 1994 1-4473 11-10-94
Arizona Public Service Form 10-Q Report
Company Deferred
Compensation Plan effective
as of May 1, 1993
</TABLE>
60
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.46(a) Fifth Amendment to the 10.3 to 1997 Form 10-K 1-4473 3-28-97
Arizona Public Service Report
Company Deferred
Compensation Plan
10.47(a) Pinnacle West Capital 10.10 to 1995 Form 10-K 1-4473 3-29-96
Corporation, Arizona Public Report
Service Company, SunCor
Development Company
and El Dorado Investment
Company Deferred
Compensation Plan as
amended and restated
effective January 1, 1996
10.48(a) Arizona Public Service 10.11 to 1995 Form 10-K 1-4473 3-29-96
Company Supplemental Report
Excess Benefit Retirement
Plan as amended and
restated on December 20, 1995
10.49(a) Pinnacle West Capital 10.7 to 1994 Form 10-K 1-4473 3-30-95
Corporation and Arizona Report
Public Service Company
Directors' Retirement Plan
effective as of January 1, 1995
10.50(a) Arizona Public Service 10.1 to September 1997 1-4473 11-12-97
Company Director Form 10-K Report
Equity Plan
10.51(a) Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95
December 21, 1993, between Report
the Company and William L.
Stewart
10.52(a) Letter Agreement dated 10.8 to 1996 Form 10-K 1-4473 3-28-97
August 16, 1996 between Report
the Company and
William L. Stewart
10.53(a) Letter Agreement between 10.2 to September 1997 1-4473 11-12-97
the Company and Form 10-Q Report
William L. Stewart
</TABLE>
61
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.54(a) Letter Agreement, dated April 10.7 to 1988 Form 10-K 1-4473 3-8-89
3, 1978, between the Company Report
and O. Mark DeMichele,
regarding certain retirement
benefits granted to Mr.
DeMichele
10.55(a) Letter Agreement dated 10.9 to 1996 Form 10-K 1-4473 3-28-97
November 27, 1996 between Report
the Company and
George A. Schreiber, Jr.
10.56(a) Letter Agreement dated as 10.8 to 1995 Form 10-K 1-4473 3-29-96
of January 1, 1996 between Report
the Company and Robert G.
Matlock & Associates, Inc.
for consulting services
10.57(a)(d) Key Executive Employment 10.3 to 1989 Form 10-K 1-4473 3-8-90
and Severance Agreement Report
between the Company and
certain executive officers of
the Company
10.58(a)(d) Revised form of Key Executive 10.5 to 1993 Form 10-K 1-4473 3-30-94
Employment and Severance Report
Agreement between the
Company and certain
executive officers of the
Company
10.59(a)(d) Second revised form of Key 10.9 to 1994 Form 10-K 1-4473 3-30-95
Executive Employment and Report
Severance Agreement between
the Company and certain
executive officers of the
Company
10.60(a)(d) Key Executive Employment 10.4 to 1989 Form 10-K 1-4473 3-8-90
and Severance Agreement Report
between the Company and
certain managers of the
Company
</TABLE>
62
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.61(a)(d) Revised form of Key Executive 10.4 to 1993 Form 10-K 1-4473 3-30-94
Employment and Severance Report
Agreement between the
Company and certain key
employees of the Company
10.62(a)(d) Second revised form of Key 10.8 to 1994 Form 10-K 1-4473 3-30-95
Executive Employment and Report
Severance Agreement between
the Company and certain key
employees of the Company
10.63(a) Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93
Corporation Stock Option and Report
Incentive Plan
10.64(a) Pinnacle West Capital A to the Proxy Statement 1-8962 4-16-94
Corporation 1994 Long-Term for the Plan Report
Incentive Plan effective as of Pinnacle West 1994
March 23, 1994 Annual Meeting of
Shareholders
10.65 Agreement No. 13904 (Option 10.3 to 1991 Form 10-K 1-4473 3-19-92
and Purchase of Effluent) Report
with Cities of Phoenix,
Glendale, Mesa, Scottsdale,
Tempe, Town of Youngtown,
and Salt River Project
Agricultural Improvement and
Power District, dated April 23,
1973
10.66 Agreement for the Sale and 10.4 to 1991 Form 10-K 1-4473 3-19-92
Purchase of Wastewater Report
Effluent with City of Tolleson
and Salt River Agricultural
Improvement and Power
District, dated June 12, 1981,
including Amendment No. 1
dated as of November 12,
1981 and Amendment No. 2
dated as of June 4, 1986
99.1 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93
among PVNGS II Funding Report
Corp., Inc., the Company and
Chemical Bank, as Trustee
</TABLE>
63
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.2 Supplemental Indenture to 4.3 to 1992 Form 10-K 1-4473 3-30-93
Collateral Trust Indenture Report
among PVNGS II Funding
Corp., Inc., the Company and
Chemical Bank, as Trustee
99.3(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92
dated as of August 1, 1986, Form 10-Q Report
among PVNGS Funding
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
99.4(c) Amendment No. 1 dated as of 10.8 to September 1986 1-4473 12-4-86
November 1, 1986, to Form 10-Q Report by
Participation Agreement, means of Amendment No.
dated as of August 1,1986, 1, on December 3, 1986
among PVNGS Funding Form 8
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
</TABLE>
64
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.5(c) Amendment No. 2, dated as of 28.4 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of August 1, 1986,
among PVNGS Funding
Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in its
individual capacity and as
Indenture Trustee, the
Company, and the Equity
Participant named therein
99.6(c) Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86
Security Agreement and Registration Statement
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.7(c) Supplemental Indenture No. 10.6 to September 1986 1-4473 12-4-86
1, dated as of November 1, Form 10-Q Report by
1986 to Trust Indenture, means of Amendment No.
Mortgage, Security Agreement 1 on December 3, 1986
and Assignment of Facility Form 8
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
</TABLE>
65
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.8(c) Supplemental Indenture No. 2 4.4 to 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture, Mortgage, Report
Security Agreement and
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston,
as Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.9(c) Assignment, Assumption and 28.3 to Form S-3 33-9480 10-24-86
Further Agreement, dated as Registration Statement
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.10(c) Amendment No. 1, dated as of 10.10 to September 1986 1-4473 12-4-86
November 1, 1986, to Form 10-Q Report by
Assignment, Assumption and means of Amendment No.
Further Agreement, dated as 1 on December 3, 1986
of August 1, 1986, between Form 8
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.11(c) Amendment No. 2, dated as of 28.6 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
</TABLE>
66
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.12 Participation Agreement, 28.2 to September 1992 1-4473 11-9-92
dated as of December 15, Form 10-Q Report
1986, among PVNGS Funding
Corp., Inc., State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee under a Trust
Indenture, the Company, and
the Owner Participant named
therein
99.13 Amendment No. 1, dated as of 28.20 to Form S-3 1-4473 8-10-87
August 1, 1987, to Registration Statement
Participation Agreement, No. 33-9480 by means of a
dated as of December 15, November 6, 1986 Form
1986, among PVNGS Funding 8-K Report
Corp., Inc. as Funding
Corporation, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, Chemical
Bank, as Indenture Trustee,
the Company, and the Owner
Participant named therein
99.14 Amendment No. 2, dated as of 28.5 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS Funding
Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in its
individual capacity and as
Indenture Trustee, the
Company, and the Owner
Participant named therein
</TABLE>
67
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.15 Trust Indenture, Mortgage, 10.2 to November 18, 1986 1-4473 1-20-87
Security Agreement and Form 8-K Report
Assignment of Facility Lease,
dated as of December 15,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.16 Supplemental Indenture No. 4.13 to Form S-3 1-4473 8-24-87
1, dated as of August 1, 1987, Registration Statement
to Trust Indenture, Mortgage, No. 33-9480 by means of
Security Agreement and August 1, 1987 Form 8-K
Assignment of Facility Lease, Report
dated as of December 15,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.17 Supplemental Indenture No. 2 4.5 to 1992 Form 10-K 1-4473 3-30-93
to Trust Indenture, Mortgage, Report
Security Agreement and
Assignment of Facility Lease,
dated as of December 15,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.18 Assignment, Assumption and 10.5 to November 18, 1986 1-4473 1-20-87
Further Agreement, dated as Form 8-K Report
of December 15, 1986,
between the Company and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
</TABLE>
68
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.19 Amendment No. 1, dated as of 28.7 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of December 15, 1986,
between the Company and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
99.20(c) Indemnity Agreement dated 28.3 to 1992 Form 10-K 1-4473 3-30-93
as of March 17, 1993 by the Report
Company
99.21 Extension Letter, dated as of 28.20 to Form S-3 1-4473 8-10-87
August 13, 1987, from the Registration Statement
signatories of the No. 33-9480 by means of a
Participation Agreement to November 6, 1986 Form
Chemical Bank 8-K Report
99.22 Arizona Corporation 28.1 to 1991 Form 10-K 1-4473 3-19-92
Commission Order dated Report
December 6, 1991
99.23 Arizona Corporation 10.1 to June Form 10-Q 1-4473 8-12-94
Commission Order dated Report
June 1, 1994
99.24 Rate Reduction Agreement 10.1 to December 4, 1995 1-4473 12-14-95
dated December 4, 1995 Form 8-K Report
between the Company and the
ACC Staff
99.25 Arizona Corporation 10.1 to March 1996 1-4473 5-14-96
Commission Order Form 10-Q Report
dated April 24, 1996
99.26 Arizona Corporation 99.1 to 1996 Form 10-K 1-4473 3-28-97
Commission Order, Report
Decision No. 59943, dated
December 26, 1996,
including the Rules regarding
the introduction of retail
competition in Arizona
</TABLE>
69
<PAGE>
- ------------------
(a) Management contract or compensatory plan or arrangement to be filed as
an exhibit pursuant to Item 14(c) of Form 10-K.
(b) Reports filed under File No. 1-4473 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
(c) An additional document, substantially identical in all material
respects to this Exhibit, has been entered into, relating to an additional
Equity Participant. Although such additional document may differ in other
respects (such as dollar amounts, percentages, tax indemnity matters, and dates
of execution), there are no material details in which such document differs from
this Exhibit.
(d) Additional agreements, substantially identical in all material respects
to this Exhibit have been entered into with additional officers and key
employees of the Company. Although such additional documents may differ in other
respects (such as dollar amounts and dates of execution), there are no material
details in which such agreements differ from this Exhibit.
Reports on Form 8-K
During the quarter ended December 31, 1996, and the period ended March 27,
1998, the Company filed the following Report on Form 8-K:
Report dated January 13, 1998 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-15379 and 333-27551)
relating to the Company's offering of $100 million of Notes.
70
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Date: March 27, 1998 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.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
WILLIAM J. POST Principal Executive Officer March 27, 1998
- ---------------------------------------------------- and Director
(William J. Post, President
and Chief Executive Officer)
GEORGE A. SCHREIBER, JR. Principal Accounting Officer, March 27, 1998
- ---------------------------------------------------- Principal Financial Officer
(George A. Schreiber, Jr.) and Director
O. MARK DEMICHELE Director March 27, 1998
- ----------------------------------------------------
(O. Mark DeMichele)
MICHAEL L. GALLAGHER Director March 27, 1998
- ----------------------------------------------------
(Michael L. Gallagher)
MARTHA O. HESSE Director March 27, 1998
- ----------------------------------------------------
(Martha O. Hesse)
MARIANNE M. JENNINGS Director March 27, 1998
- ----------------------------------------------------
(Marianne M. Jennings)
ROBERT E. KEEVER Director March 27, 1998
- ----------------------------------------------------
(Robert E. Keever)
ROBERT G. MATLOCK Director March 27, 1998
- ----------------------------------------------------
(Robert G. Matlock)
</TABLE>
71
<PAGE>
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
BRUCE J. NORDSTROM Director March 27, 1998
- ----------------------------------------------------
(Bruce J. Nordstrom)
JOHN R. NORTON III Director March 27, 1998
- ----------------------------------------------------
(John R. Norton III)
DONALD M. RILEY Director March 27, 1998
- ----------------------------------------------------
(Donald M. Riley)
QUENTIN P. SMITH, JR. Director March 27, 1998
- ----------------------------------------------------
(Quentin P. Smith, Jr.)
Director
- ----------------------------------------------------
(Richard Snell)
DIANNE C. WALKER Director March 27, 1998
- ----------------------------------------------------
(Dianne C. Walker)
BEN F. WILLIAMS, JR. Director March 27, 1998
- ----------------------------------------------------
(Ben F. Williams, Jr.)
</TABLE>
72
<PAGE>
Commission File Number 1-4473
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------
EXHIBITS TO
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
-----------------
Arizona Public Service Company
(Exact name of registrant as specified in charter)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
INDEX TO EXHIBITS
Exhibit No. Description
- ----------- -----------
10.1a ___ 1998 Management Variable Incentive Plan
10.2a ___ 1998 Senior Management Variable Incentive Plan
10.3a ___ 1998 Officers Variable Incentive Plan
23.1 ___ Consent of Deloitte & Touche LLP
27.1 ___ Financial Data Schedule
- ---------------
(a) Management contract or compensatory plan or arrangement required to
be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
For a description of the Exhibits incorporated in this filing by
reference, see Part IV, Item 14.
Exhibit 10.1a
Under the Company's 1998 Management Variable Incentive Plan, the President of
the Company, with the approval of the Human Resources Committee of the Board of
Directors, annually designates employees to participate in the program,
establishes their participation level, and establishes certain financial and
operational goals for the Company which must be satisfied in order for variable
pay awards to be made. The impact, if any, of each employee's performance on his
or her variable pay award is determined by his or her officer. Subject to final
approval by the Human Resources Committee of the Board of Directors, the
President of the Company also determines at year-end the degree to which those
goals have been satisfied and the amount of variable pay to be awarded to
participating employees, if any.
Exhibit 10.2a
Under the Company's 1998 Senior Management Variable Incentive Plan, the
President of the Company, with the approval of the Human Resources Committee of
the Board of Directors, annually designates employees to participate in the
program, establishes their participation level, and establishes certain
financial and operational goals for the Company which must be satisfied in order
for variable pay awards to be made. The impact, if any, of each employee's
performance on his or her variable pay award is determined by his or her
officer. Subject to final approval by the Human Resources Committee of the Board
of Directors, the President of the Company also determines at year-end the
degree to which those goals have been satisfied and the amount of variable pay
to be awarded to participating employees, if any.
Exhibit 10.3a
Under the Company's 1998 Officers Variable Incentive Plan, the President of the
Company, with the approval of the Human Resources Committee of the Board of
Directors, annually designates the officers who will participate in the program,
establishes their participation level, and establishes certain financial and
operational goals for the Company which must be satisfied in order for variable
pay awards to be made. The impact, if any, of each officer's performance on his
or her variable pay award is determined by the President of the Company, with
the approval of the Human Resources Committee. Subject to final approval by the
Human Resources Committee of the Board of Directors, the President also
determines at year-end the degree to which those goals have been satisfied and
the amount of variable pay to be awarded to participating officers, if any.
Exhibit 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-51085, 33-57822, 333-15379 and 333-27551 of Arizona Public Service Company on
Form S-3 and in Registration Statement No. 333-46161 of Arizona Public Service
Company on Form S-8 of our report dated March 4, 1998, appearing in this Annual
Report on Form 10-K of Arizona Public Service Company for the year ended
December 31, 1997.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
March 26, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<CURRENCY> U.S. Dollars
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,677,568
<OTHER-PROPERTY-AND-INVEST> 164,906
<TOTAL-CURRENT-ASSETS> 350,388
<TOTAL-DEFERRED-CHARGES> 1,138,280
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 6,331,142
<COMMON> 178,162
<CAPITAL-SURPLUS-PAID-IN> 1,142,364
<RETAINED-EARNINGS> 528,798
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,849,324
29,110
142,051
<LONG-TERM-DEBT-NET> 1,953,162
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 130,750
<LONG-TERM-DEBT-CURRENT-PORT> 104,068
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,122,677
<TOT-CAPITALIZATION-AND-LIAB> 6,331,142
<GROSS-OPERATING-REVENUE> 1,878,553
<INCOME-TAX-EXPENSE> 184,737
<OTHER-OPERATING-EXPENSES> 1,321,991
<TOTAL-OPERATING-EXPENSES> 1,506,728
<OPERATING-INCOME-LOSS> 371,825
<OTHER-INCOME-NET> 21,586
<INCOME-BEFORE-INTEREST-EXPEN> 393,411
<TOTAL-INTEREST-EXPENSE> 141,918
<NET-INCOME> 251,493
12,803
<EARNINGS-AVAILABLE-FOR-COMM> 238,690
<COMMON-STOCK-DIVIDENDS> 170,000
<TOTAL-INTEREST-ON-BONDS> 126,426
<CASH-FLOW-OPERATIONS> 554,508
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
