SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------
FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 For the fiscal year
ended December 31, 1996
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)
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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 (Registrant's telephone number,
offices, including area code)
including zip code)
- ------------------------------------------------------------------------------ --------------------------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
- ------------------------------------------------------------------------------ --------------------------------------
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
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Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock
(Title of class)
(See Note 3 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 ]
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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 February 26, 1997 February 26, 1997
- --------------------------------------- -------------------------------------- --------------------------------------
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Cumulative Preferred Stock........ 4,095,373 $198,000,000(a)
- --------------------------------------- -------------------------------------- --------------------------------------
(a) Computed, with respect to shares listed on the New York Stock Exchange, by reference to the closing price on the
composite tape on February 26, 1997, 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 February 26, 1997, 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 20, 1997, 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............................................................................... 2
Item 2. Properties............................................................................. 11
Item 3. Legal Proceedings...................................................................... 14
Item 4. Submission of Matters to a Vote of Security Holders.................................... 14
Supplemental Item.
Executive Officers of the Registrant................................................... 15
PART II
Item 5. Market for Registrant's Common Stock and Related Security Holder Matters............... 16
Item 6. Selected Financial Data................................................................ 17
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.............................................................. 18
Item 8. Financial Statements and Supplementary Data............................................ 21
Item 9. Changes In and Disagreements with Accountants on Accounting
and Financial Disclosure............................................................... 46
PART III
Item 10. Directors and Executive Officers of the Registrant..................................... 46
Item 11. Executive Compensation................................................................. 46
Item 12. Security Ownership of Certain Beneficial Owners and Management......................... 46
Item 13. Certain Relationships and Related Transactions......................................... 46
PART IV
Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
and Reports on Form 8-K................................................................ 47
SIGNATURES ..........................................................................................65
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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
APB Opinion No. 25 --- Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees"
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
EPA --- United States Environmental Protection Agency
Energy Act --- National Energy Policy Act of 1992
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"
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 738,000 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
1996, no single purchaser or user of energy accounted for more than 3% of total
electric revenues. At December 31, 1996, the Company employed 6,365 people,
which includes employees assigned to joint projects where the Company is project
manager.
This document may contain "forward-looking statements" that involve risks
and uncertainties which could cause actual results or outcomes to differ
materially from those expressed in such forward-looking statements. The
following factors are among the factors that could cause actual results to
differ materially from the forward-looking statements: regulatory developments;
competitive developments; regional economic conditions; the cost of debt and
equity capital; regulatory, tax and environmental legislation; weather
variations affecting customer usage; and technological developments in the
electricity industry. See "Competition" in this Item for a discussion of some of
these factors. Any forward-looking statements should be considered in light 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 an open competition docket involving many parties.
In December 1996, the ACC adopted rules for introduction of retail electric
competition in Arizona in phases from 1999 through 2003. The Rules establish a
framework for introducing competition; however, with respect to certain matters,
they also contain requirements for further workshops and ACC consideration prior
to implementation. Recommendations to the ACC from the workshops are expected in
late 1997. The Rules indicate that the ACC will allow recovery of unmitigated
stranded costs, but do not set forth the mechanisms for determining or
recovering such costs. The Company believes that state legislation will
ultimately be
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required before significant implementation of retail electric competition can
lawfully occur in Arizona. See Note 2 of Notes to Financial Statements in Item 8
for further discussion of these Rules and of the lawsuits filed by the Company
challenging certain provisions of the Rules.
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 1996,
approximately 6% 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' facilities for wholesale transactions, establishes
information requirements and provides recovery for 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.
Federal Regulation
Several electric utility reform bills have been introduced during the
current legislative session, 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 rate synchronization cost
deferrals and deferred taxes. These items, combined with miscellaneous
regulatory assets and liabilities, amounted to approximately $1.1 billion at
December 31, 1996. In accordance with a 1996 regulatory agreement between the
Company and the ACC Staff, 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, 2, and 9
of Notes to Financial Statements in Item 8 for additional information.
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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) building 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
pursue strategies to enhance its competitive position.
Generating Fuel and Purchased Power
Generating Fuel and Purchased Power Costs
Fuel and purchased power costs were approximately $326 million during 1996,
a 20.7% increase over 1995. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations ___ Results of Operations" in Item
7 for a discussion of the factors contributing to this increase.
1996 Energy Mix
The Company's sources of energy during 1996 were: purchased power - 17.1%;
coal - 43.9%; nuclear - 35.4%; and other - 3.6%.
Generating Fuel Mix
Coal, nuclear, gas and other contributions to total net generation of
electricity by the Company in 1996, 1995 and 1994, and the average cost to the
Company of those fuels (in dollars per MWh), were as follows:
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Coal Nuclear Gas Other All Fuels
------------------- -------------------- ------------------- ------------------- ---------
Percent of Average Percent of Average Percent of Average Percent of Average Average
Generation Cost Generation Cost Generation Cost Generation Cost Cost
---------- ---- ---------- ---- ---------- ---- ---------- ---- ----
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1996 (estimate). 52.5% $14.83 42.7% $5.20 4.3% $38.43 0.5% $11.46 $11.72
1995............ 54.7 13.83 40.1 5.21 5.0 19.52 0.2 11.84 10.66
1994............ 59.7 13.84 33.8 6.09 6.3 24.64 0.2 16.26 11.90
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Other includes oil and hydro generation.
Coal Supply
The Company believes that Cholla has sufficient reserves of low sulfur coal
committed to that plant for the next four years, the term of the existing coal
contract. Sufficient reserves of low sulfur coal are available to continue
operating 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. The current
sulfur content of coal being used at Four Corners, NGS and Cholla is
approximately 0.73%, 0.60% and 0.44%, respectively. In 1996, average prices paid
for coal supplied from reserves dedicated under the
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existing contracts increased as a result of power market conditions that changed
the mix of coal. 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 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. The Company purchases all of the coal which fuels 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 11 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 forty natural gas operators and
marketers which allow the Company to purchase natural gas in the method it
determines to be most economic. During 1996, the principal sources of the
Company's natural gas generating fuel were twenty of these companies. The
Company is currently purchasing the majority of its natural gas requirements
from fifteen companies pursuant to contracts. During 1996 the price of natural
gas increased primarily due to a significant increase in the transportation
costs as well as increased natural gas prices. 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 2000 and with options for up to 70% 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 ruled that the DOE has an
obligation to start disposing of spent nuclear fuel no later than January 31,
1998. By way of letter dated December 17, 1996, DOE informed contract holders,
including the Company, that DOE anticipates that it will be unable to begin
acceptance of spent nuclear fuel for disposal in a
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repository or interim storage facility by January 31, 1998. 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 305 MW
through May 1996, at which time the capacity decreased to 297 MW. In 1996, the
Company received approximately 557,998 MWh of energy under the contract and paid
approximately $35 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: 1997 (175 megawatt firm capacity purchase; and 100 megawatt capacity
exchange effective May 15, 1997); 1998 (175 megawatt firm capacity purchase,
converting to capacity exchange in the summer of 1998; and 100 megawatt capacity
exchange); 1999 and beyond (275 megawatt capacity exchange; and 205 megawatt
capacity exchange beginning in the summer of 1999). In 1996, the generating
capacity available to the Company from PacifiCorp
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was 175 MW. The Company received approximately 404,000 MWh of energy and paid
approximately $18.5 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 1999.
Construction Program
During the years 1994 through 1996, the Company incurred approximately $824
million in capitalized expenditures. Utility capitalized expenditures for the
years 1997 through 1999 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 1997 through
1999 have been estimated as follows:
(Millions of Dollars)
By Year By Major Facilities
- -------------------------------- -------------------------------
1997 $296 Electric generation $267
1998 283 Electric transmission 64
1999 262 Electric distribution 412
---- General facilities 98
$841 ----
==== $841
====
The amounts for 1997 through 1999 exclude capitalized interest costs and
include capitalized property taxes and about $30 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 1996, the
replacement fund requirement amounted to approximately $129 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 Clean Air Act, the EPA has 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 becomes applicable to NGS Units 3, 2,
and 1 in 1997, 1998 and 1999, respectively. SRP, the NGS operating agent, has
estimated a capital cost of $470 million, most of which will be incurred through
1998, 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.
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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." On March 5, 1993, the EPA promulgated rules listing allowance
allocations applicable to Company-owned plants, which allocations will begin in
the year 2000. 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, which 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 challenging the classification of
Four Corners Unit 4 in these rules. Arizona Public Service Company v. United
States Environmental Protection Agency, No.
97-1091.
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 (see "Air Quality Standards"
below), which is expected by December 1997. 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.
With respect to hazardous air pollutants emitted by electric utility steam
generating units, the Amendments require two studies. The results of the first
study indicated an impact from mercury emissions from such units in certain
unspecified areas; 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.
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
8
<PAGE>
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.
Air Quality Standards. In December 1996, the EPA proposed revised National
Ambient Air Quality Standards ("NAAQS") for ozone and particulate matter, and
related implementing regulations. The comment period for the proposed NAAQS
rules ended on March 12, 1997, and the final rules are expected by July 1997.
The EPA is also expected to propose rules to deal with regional haze by June
1997, and final rules are expected by December 1997. Due to these standards the
Company could be required to install additional pollution control equipment at
certain of its plants. The Company cannot currently estimate the capital
expenditures, if any, which may be required as a result of the final rules.
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 proceedings pursuant to a request by the parties. The
Company cannot currently predict the outcome of this matter.
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
9
<PAGE>
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.
10
<PAGE>
ITEM 2. PROPERTIES
Accredited Capacity
The Company's present generating facilities have an accredited capacity
aggregating 4,026,700 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, two steam units at Saguaro, and one
steam unit at Yucca, aggregating.......................................................... 463,400(1)
Eleven combustion turbine units, aggregating................................................ 500,600
Three combined cycle units, aggregating..................................................... 253,500
---------
1,217,500
=========
Nuclear:
29.1% owned or leased Units 1, 2 and 3 at Palo Verde, representing.......................... 1,091,600
=========
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
July 31, 1996 at 4,574,700 kW, compared to the 1995 peak of 4,420,400 kW
recorded on July 28. 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 July 31, 1996, computed in
accordance with accepted industry practices, amounted to 4,680,300 kW, for an
installed reserve margin of 2.7%. The power actually available to the Company
from its resources fluctuates from time to time due in part to planned outages,
technical problems and short-term purchases. The available capacity from sources
actually operable at the time of the 1996 peak amounted to 4,909,300 kW, for a
margin of 8.5%. Firm purchases from neighboring utilities totaling 650,000 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 pay certain taxes to the Navajo Nation. The
Company and the Navajo Nation are currently negotiating an agreement that would
settle certain issues regarding this waiver and other matters, including the
computation of royalties due on the sales of coal and possessory interest taxes
paid by the fuel supplier to Four Corners. If this settlement is consummated,
the fuel supplier, the Navajo Nation and the Four Corners participants
11
<PAGE>
would agree as a part of their settlement to restructure their relationships in
an effort to permit the power and energy generated at Four Corners to be priced
competitively. The Company cannot currently predict the outcome of these
settlement negotiations. 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 8 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 12 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 11 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 11 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 "Management's Discussion and
Analysis of Financial Condition and Results of Operations ___ Capital Needs and
Resources" in Item 7 for a discussion of the Company's construction plans.
See Notes 4, 7 and 8 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.
12
<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.
13
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
Property Taxes
On June 29, 1990, a new Arizona state property tax law was enacted,
effective as of December 31, 1989, which adversely impacted the Company's
earnings before income taxes in tax years 1990 through 1995 by an aggregate
amount of approximately $21 million per year. On December 20, 1990, the Palo
Verde participants, including the Company, filed a lawsuit in the Arizona Tax
Court, a division of the Maricopa County Superior Court, against the Arizona
Department of Revenue, the Treasurer of the State of Arizona, and various
Arizona counties, claiming, among other things, that portions of the new tax law
are unconstitutional. (Arizona Public Service Company, et al. v. Apache County,
et al., No. TX 90-01686 (Consol.), Maricopa County Superior Court). On April 23,
1996, the parties reached an agreement to settle the litigation and on July 18,
1996, the Governor signed a new Arizona property tax law that reduced the
aggregate property tax of the Company by approximately $18 million (before
income taxes) in 1996, with slightly lower amounts expected in future years.
Under the formula for potential future rate reduction pursuant to the 1996
regulatory agreement (see "1996 Regulatory Agreement" in Note 2 of Notes to
Financial Statements in Item 8 of this report), the property tax reduction is
expected to reduce future retail rates. The parties to the litigation have
reached a settlement pursuant to which the Company will relinquish its claims
for retrospective relief provided that the prospective relief provided by the
new law is not changed (other than by changes in law affecting taxpayers
generally) for a period of three years.
See "Environmental Matters" and "Water Supply" in Item 1 in regard to
pending or threatened litigation and other disputes. See "Regulatory Matters" in
Note 2 of Notes to Financial Statements in Item 8 for information regarding
lawsuits filed by the Company challenging certain provisions of rules adopted by
the ACC for the phased-in introduction of retail electric competition in Arizona
(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).
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.
14
<PAGE>
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS
OF THE REGISTRANT
The Company's executive officers are as follows:
<TABLE>
<CAPTION>
Age At
Name March 1, 1997 Position(s) At March 1, 1997
- ---- ------------- ----------------------------
<S> <C> <C>
Richard Snell 66 Chairman of the Board of Directors(1)
William J. Post 46 President and Chief Executive Officer(1)
Jack E. Davis 50 Executive Vice President, Commercial Operations
George A. Schreiber, Jr. 48 Executive Vice President and Chief Financial Officer(1)
William L. Stewart 53 Executive Vice President, Generation
Armando B. Flores 53 Senior Vice President, Human Resources and Corporate Services
James M. Levine 47 Senior Vice President, Nuclear
Jan H. Bennett 49 Vice President, Customer Service
Edward Z. Fox 43 Vice President, Environmental, Health and Safety
William E. Ide 50 Vice President, Nuclear Engineering
Nancy C. Loftin 43 Vice President, Chief Legal Counsel and Secretary
Leslie M. Mesh 50 Vice President, Marketing and Economic Development
Gregg R. Overbeck 50 Vice President, Nuclear Production
Nancy E. Felker 45 Treasurer
William J. Hemelt 43 Controller
</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);
Director, Fossil Generation (June 1992-December 1992); and Director, System
Development and Power Operations (May 1990-May 1992).
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. 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).
15
<PAGE>
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. 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. Mesh was elected to his current position in October 1995. Prior to that
time he was Vice President, Marketing and Business Development, Electronic Data
Systems (November 1993-October 1995) and Vice President, Northern Telecom, Inc.
(April 1984-October 1993).
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. Felker was elected to her present position in June 1993. Prior to that
time she was Assistant Treasurer (since October 1992). She is also Treasurer
(since June 1990) and Vice President (since February 1994) of Pinnacle West.
Mr. Hemelt was elected to his present position in June 1993. Prior to that
time he was Treasurer and Assistant Secretary (since April 1987).
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.
16
<PAGE>
The chart below sets forth the dividends declared on the Company's common
stock for each of the four quarters for 1996 and 1995.
Common Stock Dividends
(Thousands of Dollars)
<TABLE>
<CAPTION>
- --------------------------------------- -------------------------------------- --------------------------------------
Quarter 1996 1995
- --------------------------------------- -------------------------------------- --------------------------------------
<S> <C> <C> <C>
1st Quarter $42,500 $42,500
2nd Quarter 42,500 42,500
3rd Quarter 42,500 42,500
4th Quarter 42,500 42,500
- --------------------------------------- -------------------------------------- --------------------------------------
</TABLE>
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 3 and 4 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>
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Electric Operating Revenues.................. $1,718,272 $1,614,952 $1,626,168 $1,602,413 $1,587,582
Fuel and Purchased Power..................... 325,523 269,798 300,689 300,546 287,201
Operating Expenses........................... 1,027,541 963,400 957,046 929,379 908,123
---------- ---------- ---------- ---------- ----------
Operating Income.......................... 365,208 381,754 368,433 372,488 392,258
Other Income................................. 35,217 25,548 44,510 54,220 48,801
Interest Deductions --- Net.................. 156,954 167,732 169,457 176,322 194,254
---------- ---------- ---------- ---------- ----------
Net Income................................ 243,471 239,570 243,486 250,386 246,805
Preferred Dividends....................... 17,092 19,134 25,274 30,840 32,452
---------- ---------- ---------- ---------- ----------
Earnings for Common Stock................. $ 226,379 $ 220,436 $ 218,212 $ 219,546 $ 214,353
========== ========== ========== ========== ==========
Total Assets................................. $6,423,222 $6,418,262 $6,348,261 $6,357,262 $5,629,432
========== ========== ========== ========== ==========
Capital Structure:
Common Stock Equity....................... $1,729,390 $1,621,555 $1,571,120 $1,522,941 $1,476,390
Non-Redeemable Preferred Stock............ 165,673 193,561 193,561 193,561 168,561
Redeemable Preferred Stock................ 53,000 75,000 75,000 197,610 225,635
Long-Term Debt Less Current Maturities.... 2,029,482 2,132,021 2,181,832 2,124,654 2,052,763
---------- ---------- ---------- ---------- ----------
Total Capitalization.................... 3,977,545 4,022,137 4,021,513 4,038,766 3,923,349
Current Maturities of Long-Term Debt...... 153,780 3,512 3,428 3,179 94,217
Short-Term Debt........................... 16,900 177,800 131,500 148,000 195,000
---------- ---------- ---------- ---------- ----------
Total................................... $4,148,225 $4,203,449 $4,156,441 $4,189,945 $4,212,566
========== ========== ========== ========== ==========
</TABLE>
- ---------------
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 7 for a discussion of certain information in
the foregoing table.
17
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Results of Operations
1996 Compared with 1995 Earnings in 1996 were $226.4 million compared with
$220.4 million in 1995. Earnings increased primarily due to increased operating
revenues, lower property taxes, the recognition of $12 million of income tax
benefits associated with capital loss carryforwards and lower interest expense.
The comparison of 1996 to 1995 was also positively impacted by asset write-downs
of $21 million before income taxes in 1995. Operating revenues were higher due
to increased sales resulting from customer growth, warmer weather in 1996 and
higher usage, particularly by residential customers. Property taxes decreased
primarily due to a change in tax law. Interest expense was lower due to lower
average interest rates and lower amounts of debt outstanding.
Partially offsetting these positive factors were $60 million of accelerated
regulatory asset amortization, higher fuel expenses, a pretax charge of $31.7
million for a voluntary severance program and a retail rate reduction. Also
negatively affecting the comparison of 1996 with 1995 was a gain on the sale of
a small subsidiary in 1995. The accelerated regulatory asset amortization and
the rate reduction were part of a regulatory agreement which became effective
July 1, 1996 (see Note 2 of Notes to Financial Statements). Fuel expenses were
up primarily due to higher natural gas costs, increased retail sales and higher
coal prices. The Company does not have a fuel adjustment clause as part of its
retail rate structure; therefore, changes in fuel and purchased power expenses
are reflected currently in earnings.
1995 Compared with 1994 Earnings in 1995 were $220.4 million compared with
$218.2 million in 1994. Earnings increased primarily due to customer growth,
lower fuel expenses, accelerated amortization of investment tax credits, lower
operations and maintenance expenses, lower preferred stock dividends and a gain
recognized on the sale of a small subsidiary. Fuel expenses decreased due to
lower fuel prices and a more favorable mix resulting from increased nuclear
generation. The accelerated amortization of investment tax credits was a result
of a 1994 rate settlement (see Note 2 of Notes to Financial Statements) and is
reflected as a $21 million decrease in income tax expense. Operations and
maintenance expense decreased as a result of lower fossil plant overhaul costs,
improved nuclear operations and severance costs incurred in 1994. Preferred
stock dividends decreased due to less preferred stock outstanding.
Substantially offsetting these positive factors were the absence of non-cash
income related to a 1991 rate settlement, milder weather, the reversal in 1994
of certain previously recorded depreciation, a retail rate reduction which
became effective June 1, 1994 and in 1995 a $13 million pretax write-down of an
office building and an $8 million pretax write-down of certain inventory.
Operating Revenues Operating revenues reflect changes in both the volume of
units sold and price per kilowatt-hour of electric sales. An analysis of the
increases (decreases) in 1996 and 1995 electric operating revenues compared with
the prior year follows (in millions of dollars):
1996 1995
---- ----
Volume variance:
Customer growth and usage $ 75.1 $ 57.9
Weather 40.1 (42.0)
Other --- (1.7)
Rate reductions (29.7) (11.4)
Interchange sales 8.5 (7.2)
Other 9.3 (6.8)
------ ------
Total change $103.3 $(11.2)
18
<PAGE>
Other Income Net income reflects accounting practices required for regulated
public utilities and represents a composite of cash and non-cash items,
including AFUDC and accretion income on Palo Verde Unit 3 (see Statements of
Cash Flows and Note 1 of Notes to Financial Statements). The after-tax accretion
income recorded in 1994 was $20.3 million. Also in 1994 was a one-time
depreciation reversal of $15 million, after income taxes, which was included in
"Other ___ net" in the Statements of Income (see Note 2 of Notes to Financial
Statements).
Capital Needs and Resources
During 1996, the Company redeemed approximately $223 million of long-term debt
and preferred stock. Required and optional redemptions of preferred stock and
repayments of long-term debt, including premiums thereon, and payments for a
capitalized lease obligation are expected to total approximately $222 million,
$114 million and $114 million for the years 1997, 1998 and 1999, respectively.
The Company's capital requirements consist primarily of capital expenditures and
optional and mandatory repayments of long-term debt and preferred stock. The
resources available to meet these requirements include funds provided by
operations, external financings and annual equity infusions from the parent
company of $50 million from 1997 through 1999 (see Note 2 of Notes to Financial
Statements).
Present construction plans through the year 2006 do not include any major
baseload generating plants. In general, most of the capital expenditures are for
expanding transmission and distribution capabilities to meet customer growth,
for upgrading existing facilities and for environmental purposes. Capital
expenditures are anticipated to be approximately $296 million, $283 million and
$262 million for 1997, 1998 and 1999, respectively. These amounts include about
$30 million each year for nuclear fuel.
During the period 1994 through 1996, the Company funded all capital expenditures
with funds from operations. The Company expects to have adequate resources to
meet its capital requirements for the period 1997 through 1999.
Although provisions in the Company's 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.
As of December 31, 1996, 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
1996, there were $16.9 million of commercial paper and $100 million of bank
borrowings outstanding.
Accounting Matters
See Note 12 of Notes to Financial Statements for a description of a proposed
standard on accounting for certain liabilities related to closure or removal of
long-lived assets.
Current Issues
The Company's ability to maintain and improve its current level of earnings will
depend on several factors. As the electric industry becomes more competitive,
the Company's ability to reduce costs and increase productivity and asset
utilization will be an important factor in maintaining a price structure that is
both attractive to customers and profitable to the Company. Other important
factors that could affect the Company's future earnings levels and any
forward-looking statements contained in this "Management's Discussion and
Analysis of Financial Condition and Results of Operations" include regulatory
developments; competitive developments; regional economic conditions;
19
<PAGE>
the cost of debt and equity capital; regulatory, tax and environmental
legislation; weather variations affecting customer usage; and technological
developments in the electricity industry.
Competition Competition continues to evolve in the electric utility industry. In
December 1996, the ACC adopted rules for the introduction of retail electric
competition in Arizona in phases from 1999 through 2003. The Rules establish a
framework for introducing competition; however, with respect to certain matters,
they also contain requirements for further workshops and ACC consideration prior
to implementation. Recommendations to the ACC from the workshops are expected in
late 1997. The Rules indicate that the ACC will allow recovery of unmitigated
stranded costs, but do not set forth the mechanisms for determining or
recovering such costs. Separately, the Arizona legislature established a joint
legislative committee to study retail electric competition and to report to the
legislature by the end of 1997. The Company believes that state legislation will
ultimately be required before significant implementation of retail electric
competition can lawfully occur in Arizona. Additionally, legislation related to
electric competition has been proposed in the U.S. Congress. See Note 2 of Notes
to Financial Statements for further discussion of competitive developments.
Until it has been determined how competition will be implemented in Arizona, the
Company cannot accurately predict the impact of full retail electric competition
on its financial position or results of operations.
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 $1.1 billion at December 31, 1996. In
accordance with the 1996 regulatory agreement, the ACC accelerated the
amortization of substantially all of the Company's regulatory assets over an
eight-year period. 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 Note 1 of Notes to Financial Statements for additional
information on regulatory accounting.
Rate Matters Pursuant to the price reduction formula in the 1996 regulatory
agreement (see Note 2 of Notes to Financial Statements), in March 1997, the
Company filed with the ACC its calculation of an annual retail rate reduction of
approximately $18 million ($11 million after income taxes) or 1.2%,to become
effective July 1, 1997. The amount and timing of the rate decrease is subject to
ACC approval.
20
<PAGE>
ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Management.......................................................................................... 22
Independent Auditors' Report.................................................................................. 23
Statements of Income for each of the three years in the period ended December 31, 1996........................ 25
Balance Sheets --- December 31, 1996 and 1995................................................................. 26
Statements of Cash Flows for each of the three years in the period ended December 31, 1996.................... 28
Statements of Retained Earnings for each of the three years in the period ended December 31, 1996............. 29
Notes to Financial Statements................................................................................. 29
</TABLE>
See Note 13 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.
21
<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
22
<PAGE>
INDEPENDENT AUDITORS' REPORT
We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 1996 and 1995 and the related statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1996. 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, 1996 and 1995
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1996 in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 28, 1997
23
<PAGE>
[THIS PAGE INTENTIONALLY LEFT BLANK]
24
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------
1996 1995 1994
----------- ----------- -----------
(Thousands of Dollars)
<S> <C> <C> <C>
Electric Operating Revenues......................... $ 1,718,272 $ 1,614,952 $ 1,626,168
----------- ----------- -----------
Fuel Expenses:
Fuel for electric generation..................... 230,393 208,928 237,103
Purchased power.................................. 95,130 60,870 63,586
----------- ----------- -----------
Total.......................................... 325,523 269,798 300,689
----------- ----------- -----------
Operating Revenues Less Fuel Expenses............... 1,392,749 1,345,154 1,325,479
----------- ----------- -----------
Other Operating Expenses:
Operations excluding fuel expenses............... 321,959 284,842 292,292
Maintenance...................................... 108,755 115,972 119,629
Depreciation and amortization (Note 1)........... 297,210 242,098 236,108
Income taxes (Note 9)............................ 178,513 178,865 168,202
Other taxes...................................... 121,104 141,623 140,815
----------- ----------- -----------
Total.......................................... 1,027,541 963,400 957,046
----------- ----------- -----------
Operating Income.................................... 365,208 381,754 368,433
----------- ----------- -----------
Other Income (Deductions):
Allowance for equity funds used during
construction................................... 5,209 4,982 3,941
Income taxes (Note 9)............................ 45,552 37,598 (9,042)
Palo Verde accretion income (Note 1)............. --- --- 33,596
Other --- net.................................... (15,544) (17,032) 16,015
----------- ----------- -----------
Total.......................................... 35,217 25,548 44,510
----------- ----------- -----------
Income Before Interest Deductions................... 400,425 407,302 412,943
----------- ----------- -----------
Interest Deductions:
Interest on long-term debt....................... 147,666 160,032 159,840
Interest on short-term borrowings................ 10,621 8,143 6,205
Debt discount, premium and expense............... 8,176 8,622 8,854
Allowance for borrowed funds used during
construction................................... (9,509) (9,065) (5,442)
----------- ----------- -----------
Total.......................................... 156,954 167,732 169,457
----------- ----------- -----------
Net Income.......................................... 243,471 239,570 243,486
Preferred Stock Dividend Requirements............... 17,092 19,134 25,274
----------- ----------- -----------
Earnings for Common Stock........................... $ 226,379 $ 220,436 $ 218,212
============ ============ ============
</TABLE>
See Notes to Financial Statements.
25
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31,
------------------------------------
1996 1995
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
Utility Plant (Notes 4, 7 and 8):
Electric plant in service and held for future use........................ $ 6,803,211 $ 6,544,860
Less accumulated depreciation and amortization........................... 2,426,143 2,231,614
----------- -----------
Total.................................................................. 4,377,068 4,313,246
Construction work in progress............................................ 226,935 281,757
Nuclear fuel, net of amortization of $63,892
and $68,275............................................................ 51,137 52,084
----------- -----------
Utility Plant --- net.................................................. 4,655,140 4,647,087
----------- -----------
Investments and Other Assets (Note 12)...................................... 113,666 97,742
----------- -----------
Current Assets:
Cash and cash equivalents................................................ 12,521 18,389
Accounts receivable:
Service customers...................................................... 111,715 100,433
Other.................................................................. 49,898 28,107
Allowance for doubtful accounts........................................ (1,685) (1,656)
Accrued utility revenues (Note 1)........................................... 55,470 53,519
Materials and supplies (at average cost).................................... 74,120 78,271
Fossil fuel (at average cost)............................................... 13,928 21,722
Deferred income taxes (Note 9).............................................. 8,424 5,653
Other....................................................................... 22,767 17,839
----------- -----------
Total Current Assets..................................................... 347,158 322,277
----------- -----------
Deferred Debits:
Regulatory asset for income taxes (Note 9)............................... 516,722 548,464
Rate synchronization cost deferral (Note 1).............................. 414,082 449,299
Unamortized costs of reacquired debt..................................... 69,554 63,518
Unamortized debt issue costs............................................. 16,692 17,772
Other.................................................................... 290,208 272,103
----------- -----------
Total Deferred Debits.................................................. 1,307,258 1,351,156
----------- -----------
Total.................................................................. $ 6,423,222 $ 6,418,262
=========== ===========
</TABLE>
See Notes to Financial Statements.
26
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES
<TABLE>
<CAPTION>
December 31,
------------------------------------
1996 1995
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
Capitalization (Notes 3 and 4):
Common stock............................................................. $ 178,162 $ 178,162
Premiums and expenses --- net............................................ 1,091,122 1,039,550
Retained earnings........................................................ 460,106 403,843
------------ ------------
Common stock equity.................................................... 1,729,390 1,621,555
Non-redeemable preferred stock........................................... 165,673 193,561
Redeemable preferred stock............................................... 53,000 75,000
Long-term debt less current maturities................................... 2,029,482 2,132,021
------------ ------------
Total Capitalization................................................... 3,977,545 4,022,137
------------ ------------
Current Liabilities:
Commercial paper (Note 5)................................................ 16,900 177,800
Current maturities of long-term debt (Note 4)............................ 153,780 3,512
Accounts payable......................................................... 174,394 106,583
Accrued taxes............................................................ 86,327 82,827
Accrued interest......................................................... 39,115 41,549
Customer deposits........................................................ 32,137 32,746
Other.................................................................... 21,150 21,134
------------ ------------
Total Current Liabilities.............................................. 523,803 466,151
------------ ------------
Deferred Credits and Other:
Deferred income taxes (Note 9)........................................... 1,414,242 1,429,482
Deferred investment tax credit (Note 9).................................. 87,723 115,353
Unamortized gain ___ sale of utility plant (Note 8)...................... 86,939 91,514
Customer advances for construction....................................... 24,044 19,846
Other.................................................................... 308,926 273,779
------------ ------------
Total Deferred Credits and Other....................................... 1,921,874 1,929,974
------------ ------------
Commitments and Contingencies (Note 11)
Total.................................................................... $ 6,423,222 $ 6,418,262
=========== ===========
</TABLE>
27
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
--------- ---------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows from Operations:
Net income...................................................... $ 243,471 $ 239,570 $ 243,486
Items not requiring cash:
Depreciation and amortization................................. 297,210 242,098 236,108
Nuclear fuel amortization..................................... 33,566 31,587 32,564
Allowance for equity funds used during construction........... (5,209) (4,982) (3,941)
Deferred income taxes --- net................................. (12,717) 15,344 83,249
Deferred investment tax credit --- net........................ (27,630) (27,641) (6,825)
Rate refund reversal.......................................... --- --- (9,308)
Palo Verde accretion income................................... --- --- (33,596)
Changes in certain current assets and liabilities:
Accounts receivable --- net................................... (33,044) 1,659 (7,276)
Accrued utility revenues...................................... (1,951) 1,913 4,924
Materials, supplies and fossil fuel........................... 11,945 25,606 4,795
Other current assets.......................................... (4,928) (3,677) (1,509)
Accounts payable.............................................. 68,788 6,333 21,666
Accrued taxes................................................. 3,500 (6,585) (22,881)
Accrued interest.............................................. (2,565) (3,621) (577)
Other current liabilities..................................... (522) 3,393 (9)
Other --- net................................................... 17,216 21,328 (418)
--------- --------- ---------
Net cash provided............................................. 587,130 542,325 540,452
--------- --------- ---------
Cash Flows from Investing:
Capital expenditures............................................ (258,598) (295,772) (245,925)
Allowance for borrowed funds used during construction........... (9,509) (9,065) (5,442)
Other........................................................... (9,702) (22,645) (7,251)
--------- --------- ---------
Net cash used................................................. (277,809) (327,482) (258,618)
--------- --------- ---------
Cash Flows from Financing:
Long-term debt.................................................. 205,830 87,130 516,612
Short-term borrowings --- net................................... (160,900) 46,300 (16,500)
Equity infusion................................................. 50,000 --- ---
Dividends paid on common stock.................................. (170,000) (170,000) (170,000)
Dividends paid on preferred stock............................... (17,416) (19,134) (26,232)
Repayment of preferred stock.................................... (50,360) --- (124,096)
Repayment and reacquisition of long-term debt................... (172,343) (147,282) (462,643)
--------- --------- ---------
Net cash used................................................. (315,189) (202,986) (282,859)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............... (5,868) 11,857 (1,025)
Cash and cash equivalents at beginning of year..................... 18,389 6,532 7,557
--------- --------- ---------
Cash and cash equivalents at end of year........................... $ 12,521 $ 18,389 $ 6,532
========== ========== ===========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest (excluding capitalized interest)..................... $ 150,603 $ 163,592 $ 161,294
Income taxes.................................................. $ 158,553 $ 164,261 $ 121,578
</TABLE>
See Notes to Financial Statements.
28
<PAGE>
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
--------- ---------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Retained earnings at beginning of year............................. $ 403,843 $ 353,655 $ 307,098
Add: Net income................................................... 243,471 239,570 243,486
--------- --------- ---------
Total........................................................... 647,314 593,225 550,584
--------- --------- ---------
Deduct:
Dividends:
Common stock (Notes 3 and 4).................................. 170,000 170,000 170,000
Preferred stock (at required rates) (Note 3).................. 17,092 19,134 25,274
Other........................................................... 116 248 1,655
--------- --------- ---------
Total deductions.............................................. 187,208 189,382 196,929
--------- --------- ---------
Retained earnings at end of year................................... $ 460,106 $ 403,843 $ 353,655
========= ========= =========
</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
738,000 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 rate synchronization cost deferrals
(see "Rate Synchronization Cost Deferrals" in this note) and deferred taxes (see
Note 9). These items, combined with miscellaneous regulatory assets and
liabilities, amounted to approximately $1.1 billion and $1.2 billion at December
31, 1996 and 1995, respectively, most of which are included in "Deferred Debits"
on the Balance Sheets. In accordance with the 1996 regulatory agreement (see
Note 2), the ACC accelerated the amortization of substantially all of the
Company's regulatory assets to an eight-year period beginning July 1, 1996. The
accelerated portion of the regulatory asset amortization, approximately $60
million pretax in 1996, is included in depreciation and amortization expense on
the Statements of Income.
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
29
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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.
Common Stock All of the outstanding shares of common stock of the Company are
owned by Pinnacle West. See Note 3.
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 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 12 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 for 1994 through 1996 ranged from 1.51% to 20%, which resulted
in an annual composite rate of 3.32% for 1996.
Allowance for Funds Used During Construction AFUDC represents the cost of debt
and equity funds used to finance construction of utility plant. Plant
construction costs, including AFUDC, are recovered in authorized rates through
depreciation when completed projects are placed into commercial operation. AFUDC
does not represent current cash earnings.
AFUDC has been calculated using composite rates of 7.75% for 1996; 8.52% for
1995; and 7.70% for 1994. The Company compounds AFUDC semiannually and ceases to
accrue AFUDC when construction is completed and the property is placed in
service. Effective in 1997, the Company will no longer accrue AFUDC. In place of
AFUDC, the Company will capitalize interest in accordance with SFAS No. 34,
"Capitalization of Interest Cost."
Revenues Operating revenues are recognized on the accrual basis and include
estimated amounts for service rendered but unbilled at the end of each
accounting period.
Palo Verde Accretion Income In 1991, the carrying value of Palo Verde Unit 3 was
discounted to reflect the present value of lost cash flows resulting from a 1991
rate settlement agreement deeming a portion of the unit to temporarily be excess
capacity. In accordance with generally accepted accounting principles, accretion
income was recorded over a thirty-month period ended May 1994 in the aggregate
amount of the original discount. The after-tax accretion income recorded in 1994
was $20.3 million.
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 date (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 2). Prior to July 1, the deferrals were amortized over
thirty-five year periods. Amortization of the deferrals is included in
depreciation and amortization expense on the Statements of Income.
Nuclear Fuel 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.
30
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
Under federal law, the 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 11 for information on spent fuel
disposal and Note 12 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 2), the ACC accelerated
the Company's amortization of the regulatory asset for reacquired debt costs 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.
Stock-Based Compensation The FASB issued a new statement on "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 APB
Opinion No. 25. The effects on net income of applying the fair value method
would not be material.
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 1996 presentation.
2. Regulatory Matters
Electric Industry Restructuring
State The ACC has been conducting an ongoing investigation into the
restructuring of the Arizona electric industry in an open competition docket
involving many parties. In December 1996, the ACC adopted rules that provide a
framework for the introduction of retail electric competition. The ACC has
ordered that reliability, stranded cost recovery, the phase-in process, and
bundled, unbundled and metering services, as well as legal issues, will require
additional consideration and will be addressed through workshops and working
groups which will issue recommendations to the ACC during 1997. The 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.
o Each affected utility would be required to make available at least 20
percent of its 1995 system retail peak demand for competitive generation
supply to all customer classes not later than January 1, 1999; at least 50
percent not later than January 1, 2001; and all of its retail demand not
later than January 1, 2003.
o Electric service providers that obtain a Certificate of Convenience and
Necessity (CC&N) 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 is required to file
with the ACC proposed tariffs for bundled service 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
31
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
separately. Affected utilities would be required to provide bundled
service, as well as unbundled transmission, distribution and miscellaneous
other services, at regulated, cost-based rates.
o The Rules indicate that the ACC will allow recovery of unmitigated stranded
costs. Each affected utility would be required to file with the ACC
estimates of unmitigated stranded costs. The ACC would then, after hearing
and consideration of various factors, determine the magnitude of stranded
cost and appropriate stranded cost recovery mechanisms and charges.
The Company continues to focus on working with the ACC to bring competitive
benefits to Arizona but believes that certain provisions of the Rules are
deficient. In February 1997, the Company filed lawsuits to protect its legal
rights regarding the Rules.
A joint legislative committee has been appointed to study electric utility
industry restructuring issues and report back to the legislature by the end of
1997. The Company believes that legislation will ultimately be required before
significant implementation of the Rules can lawfully occur.
Until it has been further determined how competition will be implemented in
Arizona, the Company cannot accurately predict the impact of full retail
competition on its financial position or results of operations.
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 the current
legislative session, 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.
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 beginning 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.
32
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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 March 1997 the Company filed with
the ACC its calculation of an annual retail rate reduction of approximately $18
million ($11 million after income taxes), or 1.2%, to become effective July 1,
1997. The amount and timing of the rate decrease is subject to ACC approval.
1994 Settlement Agreement
In May 1994, the ACC approved a retail rate settlement agreement which provided
for a net annual retail rate reduction of 2.2% on average, or approximately $32
million ($19 million after income taxes), effective June 1, 1994. As part of the
settlement, in 1994 the Company reversed approximately $20 million of
depreciation ($15 million after income taxes) related to a 1991 Palo Verde
write-off. It also provided for the accelerated amortization of substantially
all deferred investment tax credits over a five-year period beginning in 1995.
33
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
3. 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. In addition, Series V redeemable preferred stock is callable by the
Company. 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 1996 1995 Share 1996 1995 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..................... 160,000 152,740 155,945 $ 25.00 $ 3,818 $ 3,898 $ 27.50
$2.50..................... 105,000 102,532 103,254 50.00 5,127 5,163 51.00
$2.36..................... 120,000 40,000 40,000 50.00 2,000 2,000 51.00
$4.35..................... 150,000 75,000 75,000 100.00 7,500 7,500 102.00
Serial preferred.......... 1,000,000
$2.40 Series A.......... 239,900 240,000 50.00 11,995 12,000 50.50
$2.625 Series C......... 240,000 240,000 50.00 12,000 12,000 51.00
$2.275 Series D......... 199,655 200,000 50.00 9,983 10,000 50.50
$3.25 Series E.......... 320,000 320,000 50.00 16,000 16,000 51.00
Serial preferred.......... 4,000,000(b)
Adjustable rate ---
Series Q.............. 372,851 500,000 100.00 37,285 50,000 (c)
Serial preferred.......... 10,000,000
$1.8125 Series W........ 2,398,615 3,000,000 25.00 59,965 75,000 (d)
---------- ---------- --------- --------
Total................. 4,141,293 4,874,199 $ 165,673 $ 193,561
========== ========== ========= =========
Redeemable:
Serial preferred:
$10.00 Series U......... 410,000 500,000 $100.00 $ 41,000 $ 50,000 ---
$7.875 Series V......... 120,000 250,000 100.00 12,000 25,000 (e)
---------- ---------- --------- --------
Total................. 530,000 750,000 $ 53,000 $ 75,000
========== ========== ========= =========
</TABLE>
- ---------------
(a) In each case plus 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.
(e) Redeemable at $104.73 through May 31, 1997, and thereafter declining by a
predetermined amount each year to par after May 31, 2002.
34
<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 five years are: $10.0 million in each of the years 1997
through 2000, and $1.0 million in 2001.
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 1996 1995 1994 1996 1995 1994
- -------------------------------- -------- ------- --------- -------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Balance, January 1.............. 750,000 750,000 1,976,100 $75,000 $75,000 $ 197,610
Retirements:
$8.80 Series K............. --- --- (142,100) --- --- (14,210)
$11.50 Series R............ --- --- (284,000) --- --- (28,400)
$8.48 Series S............. --- --- (300,000) --- --- (30,000)
$8.50 Series T............. --- --- (500,000) --- --- (50,000)
$10.00 Series U............ (90,000) --- --- (9,000) --- ---
$7.875 Series V............ (130,000) --- --- (13,000) --- ---
-------- ------- --------- -------- ------- ---------
Balance, December 31............ 530,000 750,000 750,000 $53,000 $75,000 $ 75,000
======= ======= ======= ======= ======= =========
</TABLE>
4. Long-Term Debt
The following table presents long-term debt outstanding:
<TABLE>
<CAPTION>
December 31,
------------------------
Maturity Dates Interest Rates 1996 1995
-------------- -------------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
First mortgage bonds 1997-2028 5.5%-10.25% (a) $1,448,848 $1,604,317
Pollution control indebtedness 2024-2031 Adjustable (b) 439,990 433,280
Senior notes 2006 6.75% 100,000 ---
Debentures 2025 10% 75,000 75,000
Bank loans 2001 Adjustable (c) 100,000 ---
Capitalized lease obligation (d) 1996-2001 7.48% 19,424 22,936
---------- ----------
Total long-term debt 2,183,262 2,135,533
Less current maturities 153,780 3,512
---------- ----------
Total long-term debt less current maturities $2,029,482 $2,132,021
========== ==========
</TABLE>
- ---------------
(a) The weighted-average rate at December 31, 1996 and 1995 was 7.66% and
7.79%, respectively. The weighted-average years to maturity at December 31,
1996 and 1995 was 18 years and 19 years, respectively.
(b) The weighted-average rates for the years ended December 31, 1996 and 1995
were 3.40% and 4.31%, respectively. Changes in short-term interest rates
would affect the costs associated with this debt.
(c) The weighted-average rate for the year ended December 31, 1996 was 5.76%.
Changes in short-term interest rates would affect the costs associated with
this debt.
(d) 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 8).
35
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
Aggregate annual principal payments due on long-term debt and for sinking fund
requirements through 2001 are as follows: 1997, $153.8 million; 1998, $104.1
million; 1999, $104.4 million; 2000, $104.7 million; and 2001, $102.5 million.
See Note 3 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, 1996.
5. Lines of Credit
The Company had committed lines of credit with various banks of $400 million at
December 31, 1996 and $300 million at December 31, 1995, which were available
either to support the issuance of commercial paper or to be used for bank
borrowings. The commitment fees at December 31, 1996 and 1995 for these lines of
credit ranged from .10% to .15% per annum. The Company had long-term bank
borrowings of $100 million outstanding at December 31, 1996 and commercial paper
borrowings outstanding of $16.9 million and $177.8 million at December 31, 1996
and 1995, respectively, under these lines of credit. The weighted average
interest rate on commercial paper borrowings was 6.40% and 6.06% on December 31,
1996 and 1995, respectively. By Arizona statute, the Company's short-term
borrowings cannot exceed 7% of its total capitalization without the consent of
the ACC.
6. 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,
1996 and 1995 due to their short maturities. Investments in debt and equity
securities are held for purposes other than trading. The December 31, 1996 and
1995 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, 1996 and 1995 was $2.16 billion and $2.11 billion, respectively,
and the estimated fair value was $2.13 billion and $2.14 billion, respectively.
The fair value estimates are based on quoted market prices of the same or
similar issues.
36
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
7. Jointly-Owned Facilities
At December 31, 1996, 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 operating expenses.
<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% $1,825,459 $547,750 $15,130
Palo Verde Nuclear Generating Station
Unit 2 (see Note 8) 17.0% 568,647 175,926 7,109
Four Corners Steam Generating Station
Units 4 and 5 15.0% 144,080 58,447 674
Navajo Steam Generating Station
Units 1, 2 and 3 14.0% 141,178 82,430 61,289(a)
Cholla Steam Generating Station
Common Facilities (b) 62.8%(c) 71,154 37,962 549
Transmission Facilities:
ANPP 500KV System 35.8%(c) 62,593 17,848 1,469
Navajo Southern System 31.4%(c) 27,113 16,135 46
Palo Verde-Yuma 500KV System 23.9%(c) 11,376 3,727 ---
Four Corners Switchyards 27.5%(c) 3,068 1,634 3
Phoenix-Mead System 17.1%(c) 36,089 (876) 325
</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.
8. 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 ratemaking treatment, an amount equal to the annual lease
payments is included in rent expense. A regulatory asset is recognized for the
37
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
difference between lease payments and rent expense calculated on a straight-line
basis. In accordance with the 1996 regulatory agreement (see Note 2), the ACC
accelerated the Company's amortization of the regulatory asset for leases to an
eight-year period beginning 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, 1996 was $57.3 million.
Lease expense for 1996, 1995 and 1994 was $41.8 million, $41.7 million and $42.2
million, respectively.
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, 1996 was $44.6 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 1996, 1995 and 1994 was
approximately $9.7 million, $9.9 million and $10.1 million, respectively. Annual
future minimum rental commitments, excluding the Palo Verde and combined cycle
leases, for the period 1997 through 2001 range between $12 million and $13
million. Total rental commitments after the year 2001 are estimated at $107
million.
9. 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 the 1994 rate settlement agreement
(see Note 2). Prior to 1995, ITCs were deferred and amortized to other income
over the estimated lives of the related assets as directed by the ACC.
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
2), 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.
38
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The components of income tax expense are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
--------- ---------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Current:
Federal......................................................... $137,531 $120,196 $ 74,272
State........................................................... 35,777 33,368 26,447
-------- -------- ---------
Total current................................................. 173,308 153,564 100,719
Deferred........................................................... (869) 17,933 83,350
Change in valuation allowance...................................... (11,848) (2,589) ---
Investment tax credit amortization................................. (27,630) (27,641) (6,825)
-------- -------- ---------
Total expense................................................. $132,961 $141,267 $177,244
======== ======== ========
</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,
--------------------------------------------
1996 1995 1994
--------- ---------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Federal income tax expense at statutory rate, 35%.................. $131,751 $133,293 $147,256
Increases (reductions) in tax expense resulting from:
Tax under book depreciation..................................... 19,229 18,186 17,236
ITC amortization................................................ (27,630) (27,641) (6,825)
State income tax ___ net of federal income tax benefit.......... 20,790 21,770 24,947
Change in valuation allowance................................... (10,269) (2,245) ---
Other........................................................... (910) (2,096) (5,370)
-------- -------- ---------
Income tax expense............................................ $132,961 $141,267 $177,244
======== ======== ========
</TABLE>
39
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows:
<TABLE>
<CAPTION>
December 31,
-----------------------------
1996 1995
----------- -----------
(Thousands of Dollars)
Deferred tax assets:
<S> <C> <C>
Deferred gain on Palo Verde Unit 2 sale/leaseback................................ $ 35,105 $ 36,945
Other............................................................................ 71,725 77,539
Valuation allowance.............................................................. --- (12,483)
----------- -----------
Total deferred tax assets...................................................... 106,830 102,001
----------- -----------
Deferred tax liabilities:
Plant related.................................................................... 1,104,902 1,081,290
Income taxes recoverable through future rates --- net............................ 208,647 221,418
Rate synchronization deferrals................................................... 167,202 181,384
Other............................................................................ 31,897 41,738
----------- -----------
Total deferred tax liabilities................................................. 1,512,648 1,525,830
----------- -----------
Accumulated deferred income taxes --- net........................................... $1,405,818 $1,423,829
========== ==========
</TABLE>
10. Retirement Plans and Other Benefits
Voluntary Severance Plan The Company sponsored a voluntary severance plan in
1996 which resulted in a before income tax 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 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 1996, 1995 and 1994 was
approximately $14.9 million, $9.6 million and $11.9 million, respectively.
40
<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 and $1.4 million in 1994 are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
--------- ---------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost --- benefits earned during the period................. $22,861 $16,038 $20,345
Interest cost on projected benefit obligation...................... 44,602 39,328 39,377
Return on plan assets.............................................. (62,460) (82,209) 6,105
Net amortization and deferral...................................... 19,734 45,976 (44,000)
------- ------- -------
Net periodic pension cost.......................................... $24,737 $19,133 $21,827
======= ======= =======
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized in
the balance sheets is presented below:
<TABLE>
<CAPTION>
1996 1995
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
Plan assets at fair value........................................................... $ 533,444 $ 469,820
--------- ---------
Less:
Accumulated benefit obligation, including vested benefits
of $413,004 and $396,138 in 1996 and 1995, respectively........................ 467,037 428,258
Effect of projected future compensation increases................................ 134,057 149,836
--------- ---------
Total projected benefit obligation.................................................. 601,094 578,094
--------- ---------
Plan assets less than projected benefit obligation.................................. (67,650) (108,274)
Plus:
Unrecognized net loss from past experience
different from that assumed.................................................... 2,818 44,614
Unrecognized prior service cost.................................................. 20,478 23,800
Unrecognized net transition asset................................................ (29,593) (32,809)
--------- ---------
Accrued pension liability........................................................... $ (73,947) $ (72,669)
========= =========
Principal actuarial assumptions used were:
Discount rate.................................................................... 7.75% 7.25%
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 1996, 1995 and 1994 were $3.4
million, $3.1 million and $3.2 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.
41
<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 1996, 1995 and 1994 was
approximately $16 million, $13 million and $13 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>
1996 1995 1994
--------- ---------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost --- benefits earned during the period................. $ 7,974 $ 6,735 $ 8,785
Interest cost on accumulated benefit obligation.................... 13,395 13,743 14,026
Return on plan assets.............................................. (12,550) (15,133) (6,459)
Net amortization and deferral...................................... 12,733 17,142 11,619
-------- -------- --------
Net periodic postretirement benefit cost........................... $ 21,552 $ 22,487 $ 27,971
======== ======== ========
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized in
the balance sheet is presented below:
<TABLE>
<CAPTION>
1996 1995
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
Plan assets at fair value........................................................... $109,763 $ 81,309
-------- ---------
Less accumulated postretirement benefit obligation:
Retirees......................................................................... 86,747 90,222
Fully eligible plan participants................................................. 3,351 15,497
Other active plan participants................................................... 89,452 106,568
-------- ---------
Total accumulated postretirement benefit obligation............................ 179,550 212,287
-------- ---------
Plan assets less than accumulated benefit obligation................................ (69,787) (130,978)
Plus:
Unrecognized transition obligation............................................... 122,439 155,481
Unrecognized net gain from past experience different from that
assumed........................................................................ (62,299) (24,561)
-------- ---------
Accrued postretirement liability.................................................... $ (9,647) $ (58)
======== =========
Principal actuarial assumptions used were:
Discount rate.................................................................... 7.75% 7.25%
Annual salary increases for life insurance obligation............................ 4.50% 4.50%
Expected long-term rate of return on assets ___ after tax........................ 7.75% 7.64%
Initial health care cost trend rate ___ under age 65............................. 9.00% 9.50%
Initial health care cost trend rate ___ age 65 and over.......................... 8.00% 8.50%
Ultimate health care cost trend rate (reached in the year 2002).................. 5.50% 5.50%
</TABLE>
Assuming a one percent increase in the health care cost trend rate, the 1996
cost of postretirement benefits other than pensions would increase by
approximately $5 million and the accumulated benefit obligation as of December
31, 1996 would increase by approximately $31 million.
42
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
11. 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 1996 dollars and including installation and
replacement power costs) will be approximately $50 million, most of which will
be incurred after the year 2000. 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. 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.
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 1997 through 2020 that
include required purchase provisions. The Company estimates its 1997 contract
requirements to be approximately $120 million. However, this amount may vary
significantly
43
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
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 $114 million. The portion of the coal mine
reclamation obligation related to coal already burned is approximately $68
million at December 31, 1996 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 2), 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,
1996 was approximately $69 million.
Construction Program Total capital expenditures in 1997 are estimated at $296
million.
12. Nuclear Decommissioning Costs
In 1996, the Company recorded $11.4 million for decommissioning expense. The
Company estimates it will cost approximately $2.0 billion ($440 million in 1996
dollars), over a fourteen 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 currently 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,
1996, the Company had deposited a total of $68.1 million. The trust accounts are
included in "Investments and Other Assets" on the Balance Sheets at a market
value of $95.5 million on December 31, 1996. 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 indicated a revised exposure draft or a final statement will be issued
in the second quarter of 1997.
44
<PAGE>
APS
NOTES TO FINANCIAL STATEMENTS
13. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 1996 and 1995 is as follows:
<TABLE>
<CAPTION>
Electric
Operating Operating Net Earnings for
Quarter Revenues Income(a) Income Common Stock
- ------- -------- --------- ------ ------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
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)
1995
First $336,968 $ 73,214 $ 37,832 $ 33,025
Second 380,178 88,719 53,452 48,676
Third 549,082 162,602 128,345 123,570
Fourth 348,724 57,219 19,941 15,165
</TABLE>
- ---------------
(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 income for the fourth quarter of 1996 includes an after-tax charge of
$18.9 million for a voluntary severance program.
45
<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 20,
1997 (the "1997 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 and sixth 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 1997 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 1997 Proxy
Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to the last paragraph under the heading "The Board
and its Committees" and to "Executive Benefit Plans --- Employment and Severance
Agreements" in the 1997 Proxy Statement.
46
<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 21.
Exhibits Filed
Exhibit No. Description
- ----------- -----------
10.1(a) --- 1997 Senior Management Variable Pay Plan
10.2(a) --- 1997 Officers Variable Pay Plan
10.3(a) --- Fifth Amendment to the Arizona Public Service Company Deferred
Compensation Plan
10.4 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS
Unit 1) dated as of July 1, 1991
10.5 --- Amendment No. 4 to Amended and Restated Decommissioning Trust
Agreement (PVNGS Unit 2) dated as of January 31, 1992
10.6 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS
Unit 3) dated as of July 1, 1991
10.7 --- Letter Agreement dated October 9, 1996 between the Company and
Jaron B. Norberg
10.8 --- Letter Agreement dated August 16, 1996 between the Company and
William L. Stewart
10.9 --- Letter Agreement dated November 27, 1996 between the Company
and George A. Schreiber, Jr.
23.1 --- Consent of Deloitte & Touche LLP
27.1 --- Financial Data Schedule
99.1 --- Arizona Corporation Commission Order, Decision No. 59943,
dated December 26, 1996, including the Rules regarding the
introduction of retail competition in Arizona
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
</TABLE>
47
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
Indenture Form 8-K Report 1-4473 9-27-93
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
</TABLE>
48
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
4.8 Agreement, dated March 21, 4.1 to 1993 Form 10-K 1-4473 3-30-94
1994, relating to the filing of Report
instruments defining the
rights of holders of long-term
debt not in excess of 10% of
the Company's total assets
4.9 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
4.10 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
4.11 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
4.12 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
4.13 Agreement of Resignation, 4.1 to September 25, 1995
Appointment, Acceptance and Form 8-K Report 1-4473 10-24-95
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
10.10 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
</TABLE>
49
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.11 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
10.12 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
10.13 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
10.14 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
10.15 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
10.16 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
</TABLE>
50
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.17 Asset Purchase and Power 10.1 to June 1991 Form 1-4473 8-8-91
Exchange Agreement dated 10-Q Report
September 21, 1990 between
the Company and PacifiCorp,
as amended as of October 11,
1990 and as of July 18, 1991
10.18 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
10.19 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
10.20 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
10.21 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
10.22 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
10.23 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
10.24 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77
Navajo Tribe of Indians, Four Registration Statement
Corners Plant
</TABLE>
51
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.25 Supplemental and Additional 5.02 to Form S-7 2-59644 9-1-77
Indenture of Lease, including Registration Statement
amendments and supplements
to original lease with Navajo
Tribe of Indians, Four Corners
Plant
10.26 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
10.27 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
10.28 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
10.29 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
10.30 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
10.31 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70
Units 1, 2, and 3 Registration Statement
10.32 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70
rights-of-way and easements, Registration Statement
Navajo Plant
10.33 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>
52
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.34 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
10.35 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
10.36(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>
53
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.37(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
10.38(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
10.39(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
10.40 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
10.41 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>
54
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.42 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
10.43(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
10.44(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
10.45(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
10.46(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
10.47(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
10.48(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>
55
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
10.49(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
10.50(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
10.51(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
10.52(a) Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95
December 21, 1993, between Report
the Company and William L.
Stewart
10.53(a) Agreement for Utility 10.6 to 1988 Form 10-K 1-4473 3-8-89
Consulting Services, dated Report
March 1, 1985, between the
Company and Thomas G.
Woods, Jr., and Amendment
No. 1 thereto, dated January
6, 1986
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 July 10.1 to September 1995 1-4473 11-14-95
28, 1995, between the 10-Q Report
Company and Jaron B.
Norberg regarding certain of
Mr. Norberg's retirement
benefits
</TABLE>
56
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
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
</TABLE>
57
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
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
99.2 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93
among PVNGS II Funding Report
Corp., Inc., the Company and
Chemical Bank, as Trustee
99.3 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
99.4(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92
dated as of August 1, 1986, Form 10-Q Report
among PVNGS Funding
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
</TABLE>
58
<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. 1 dated as of 10.8 to September 1986 1-4473 12-4-86
November 1, 1986, to Form 10-Q Report by
Participation Agreement, means of Amendment No.
dated as of August 1,1986, 1, on December 3, 1986
among PVNGS Funding Form 8
Corp., Inc., Bank of America
National Trust and Savings
Association, State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, in
its individual capacity and as
Owner Trustee, Chemical
Bank, in its individual
capacity and as Indenture
Trustee, the Company, and
the Equity Participant named
therein
99.6(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
99.7(c) Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86
Security Agreement and Registration Statement
Assignment of Facility Lease,
dated as of August 1, 1986,
between State Street Bank
and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
</TABLE>
59
<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. 10.6 to September 1986 1-4473 12-4-86
1, dated as of November 1, Form 10-Q Report by
1986 to Trust Indenture, means of Amendment No.
Mortgage, Security Agreement 1 on December 3, 1986
and Assignment of Facility Form 8
Lease, dated as of August 1,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
99.9(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
99.10(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
99.11(c) Amendment No. 1, dated as of 10.10 to September 1986 1-4473 12-4-86
November 1, 1986, to Form 10-Q Report by
Assignment, Assumption and means of Amendment No.
Further Agreement, dated as 1 on December 3, 1986
of August 1, 1986, between Form 8
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
</TABLE>
60
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.12(c) Amendment No. 2, dated as of 28.6 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
99.13 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
99.14 Amendment No. 1, dated as of 28.20 to Form S-3 1-4473 8-10-87
August 1, 1987, to Registration Statement
Participation Agreement, No. 33-9480 by means of a
dated as of December 15, November 6, 1986 Form
1986, among PVNGS Funding 8-K Report
Corp., Inc. as Funding
Corporation, State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, Chemical
Bank, as Indenture Trustee,
the Company, and the Owner
Participant named therein
</TABLE>
61
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.15 Amendment No. 2, dated as of 28.5 to 1992 Form 10-K 1-4473 3-30-93
March 17, 1993, to Report
Participation Agreement,
dated as of December 15,
1986, among PVNGS Funding
Corp., Inc., PVNGS II
Funding Corp., Inc., State
Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, in its individual
capacity and as Owner
Trustee, Chemical Bank, in its
individual capacity and as
Indenture Trustee, the
Company, and the Owner
Participant named therein
99.16 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
99.17 Supplemental Indenture No. 4.13 to Form S-3 1-4473 8-24-87
1, dated as of August 1, 1987, Registration Statement
to Trust Indenture, Mortgage, No. 33-9480 by means of
Security Agreement and August 1, 1987 Form 8-K
Assignment of Facility Lease, Report
dated as of December 15,
1986, between State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee, and Chemical
Bank, as Indenture Trustee
</TABLE>
62
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.18 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
99.19 Assignment, Assumption and 10.5 to November 18, 1986 1-4473 1-20-87
Further Agreement, dated as Form 8-K Report
of December 15, 1986,
between the Company and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
99.20 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
99.21(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
99.22 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
99.23 Arizona Corporation 28.1 to 1991 Form 10-K 1-4473 3-19-92
Commission Order dated Report
December 6, 1991
99.24 Arizona Corporation 10.1 to June Form 10-Q 1-4473 8-12-94
Commission Order dated Report
June 1, 1994
</TABLE>
63
<PAGE>
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
99.25 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
99.26 Arizona Corporation Commission 10.1 to March 1996 Form 1-4473 5-14-96
Order dated April 24, 1996 10-Q Report
</TABLE>
- ---------------
(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,
1997, the Company did not file any Reports on Form 8-K.
64
<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, 1997 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, 1997
- -------------------------------------------------- and Director
(William J. Post, President
and Chief Executive Officer)
George A. Schreiber, Jr. Principal Accounting Officer, March 27, 1997
- -------------------------------------------------- Principal Financial Officer
(George A. Schreiber, Jr.) and Director
O. Mark DeMichele Director March 27, 1997
- --------------------------------------------------
(O. Mark DeMichele)
Martha O. Hesse Director March 27, 1997
- --------------------------------------------------
(Martha O. Hesse)
Marianne Moody Jennings Director March 27, 1997
- --------------------------------------------------
(Marianne Moody Jennings)
Robert G. Matlock Director March 27, 1997
- --------------------------------------------------
(Robert G. Matlock)
Jaron B. Norberg Director March 27, 1997
- --------------------------------------------------
(Jaron B. Norberg)
</TABLE>
65
<PAGE>
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
John R. Norton III Director March 27, 1997
- --------------------------------------------------
(John R. Norton III)
Donald M. Riley Director March 27, 1997
- --------------------------------------------------
(Donald M. Riley)
Wilma W. Schwada Director March 27, 1997
- --------------------------------------------------
(Wilma W. Schwada)
Richard Snell Director March 27, 1997
- --------------------------------------------------
(Richard Snell)
Dianne C. Walker Director March 27, 1997
- --------------------------------------------------
(Dianne C. Walker)
Ben F. Williams, Jr. Director March 27, 1997
- --------------------------------------------------
(Ben F. Williams, Jr.)
Thomas G. Woods, Jr. Director March 27, 1997
- --------------------------------------------------
(Thomas G. Woods, Jr.)
</TABLE>
66
<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, 1996
-----------------
Arizona Public Service Company
(Exact name of registrant as specified in charter)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
INDEX TO EXHIBITS
Exhibit No. Description
- ----------- -----------
10.1(a) --- 1997 Senior Management Variable Pay Plan
10.2(a) --- 1997 Officers Variable Pay Plan
10.3(a) --- Fifth Amendment to the Arizona Public Service Company Deferred
Compensation Plan
10.4 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS
Unit 1) dated as of July 1, 1991
10.5 --- Amendment No. 4 to Amended and Restated Decommissioning Trust
Agreement (PVNGS Unit 2) dated as of January 31, 1992
10.6 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS
Unit 3) dated as of July 1, 1991
10.7 --- Letter Agreement dated October 9, 1996 between the Company and
Jaron B. Norberg
10.8 --- Letter Agreement dated August 16, 1996 between the Company and
William L. Stewart
10.9 --- Letter Agreement dated November 27, 1996 between the Company
and George A. Schreiber, Jr.
23.1 --- Consent of Deloitte & Touche LLP
27.1 --- Financial Data Schedule
99.1 --- Arizona Corporation Commission Order, Decision No. 59943, dated
December 26, 1996, including the Rules regarding the
introduction of retail competition in Arizona
- ---------------
(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 1997 Senior Management Variable Pay 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 1997 Officers Variable Pay 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 10.3.a
FIFTH AMENDMENT TO THE
ARIZONA PUBLIC SERVICE COMPANY
DEFERRED COMPENSATION PLAN
Effective January 1, 1978, ARIZONA PUBLIC SERVICE COMPANY (the
"Company") adopted the ARIZONA PUBLIC SERVICE COMPANY DEFERRED COMPENSATION PLAN
(the "Plan"). The Plan was subsequently amended and restated several times and
was the most recent amendment and restatement becoming effective January 1,
1984. The Plan was thereafter amended on December 22, 1986, December 23, 1987,
April 4, 1993, and August 1, 1994. By this instrument, the Company desires to
amend the Plan to change the retirement date on which participants may retire
and receive benefits.
1. This Amendment shall amend only the provisions of the Plan as set
forth herein, and those provisions not expressly amended hereby shall be
considered in full force and effect.
2. Section IV.A.2 is hereby amended to read as follows:
2. Separation from employment after attainment by the
Participant of the age of fifty-five (55) years if such
Participant has been credited with ten (10) Years of Service
(as defined below); for purposes of this Section, "Years of
Service" shall have the same meaning as that given it in the
Arizona Public Service Company Employees' Retirement Plan, as
amended (which definition is incorporated herein by this
reference);
3. The provisions of this Amendment shall be effective as of
January 1, 1997.
<PAGE>
Except as amended and supplemented by this instrument, the Company
hereby ratifies the Plan as restated effective January 1, 1984, and thereafter
amended.
DATED: December 18, 1996
ARIZONA PUBLIC SERVICE COMPANY
By: Nancy C. Loftin
---------------------------------
Its: Vice President, Chief Legal Counsel and Secretary
----------------------------------------------------
Exhibit 10.4
AMENDMENT NO. 2
Decommissioning Trust Agreement
(PVNGS Unit 1)
Dated as of July 1, 1991,
as Amended by Amendment No. 1
Dated as of December 1, 1994
between
Arizona Public Service Company
and
Mellon Bank, N.A.
as Decommissioning Trustee
This Amendment No. 2, dated as of December 16, 1996, to the
Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991 as
amended by Amendment No. 1 thereto dated as of December 1, 1994 (the
"Decommissioning Trust Agreement"; terms used herein as therein defined), is
entered into between Arizona Public Service Company ("APS") and Mellon Bank,
N.A., as Decommissioning Trustee ("Decommissioning Trustee").
R E C I T A L S
- - - - - - - -
WHEREAS, the parties hereto wish to amend the limitations of
the parties' ability to modify the Decommissioning Trust Agreement under certain
circumstances;
NOW THEREFORE, in consideration of the premises and of other
good and valuable consideration, receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:
A G R E E M E N T S:
- - - - - - - - - -
SECTION 1. Amendments.
The Decommissioning Trust Agreement is hereby amended by
adding the following as the last sentence of Section 13: "Notwithstanding the
foregoing, this Agreement may not be amended or modified in violation of Section
468A of the Code or the regulations thereunder."
<PAGE>
SECTION 2. Effectiveness.
This Amendment No. 2 shall become effective as of the date
hereof upon the execution and delivery of a counterpart of this Amendment No. 2
by each of the parties hereto.
SECTION 3. Miscellaneous.
(a) Full Force and Effect.
Except as expressly provided herein, the Decommissioning Trust
Agreement shall remain unchanged and in full force and effect. Each reference in
the Decommissioning Trust Agreement and in any exhibit or schedule thereto to
"this Agreement," "hereto," "hereof" and terms of similar import shall be deemed
to refer to the Decommissioning Trust Agreement as amended hereby.
(b) Counterparts.
This Amendment No. 2 may be executed in any number of
counterparts, all of which taken together shall constitute the same instrument,
and any of the parties hereto may execute this Amendment No. 2 by signing any
such counterpart.
(c) Arizona Law.
This Amendment No. 2 shall be construed in accordance with and
governed by the law of the State of Arizona.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment No. 2 to the Decommissioning Trust Agreement to be duly executed as
the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
By NANCY E. NEWQUIST
------------------------------
Title Treasurer
------------------------------
-2-
<PAGE>
MELLON BANK, N.A., as
Decommissioning Trustee
By EARL G. KLECKNER
------------------------------
Earl G. Kleckner
Title Vice President
------------------------------
STATE OF ARIZONA )
) ss.
County of Maricopa )
The foregoing instrument was acknowledged before me this 16th
day of December, 1996, by Nancy E. Newquist, the Treasurer of ARIZONA PUBLIC
SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
[Official Seal] MARIA R. MARRS
---------------------------------
Notary Public
My commission expires:
July 21, 1998
STATE OF PENNSYLVANIA )
) ss.
County of Allegheny )
The foregoing instrument was acknowledged before me this 16th
day of October, 1996, by Earl Kleckner, a Trust Officer of MELLON BANK, N.A., a
corporation having trust powers, as Decommissioning Trustee, on behalf of said
corporation.
[Official Seal] STEPHANIE RIEGER
---------------------------------
Notary Public
My commission expires:
May 12, 1997
-3-
Exhibit 10.5
This Amendment No. 4, dated as of December 16, 1996, to the
Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of
January 31, 1992, as amended by Amendment No. 1 thereto dated as of November 1,
1992, Amendment No. 2 thereto dated as of November 1, 1994, and Amendment No. 3
thereto dated as of June 20, 1996 (the "Decommissioning Trust Agreement"; terms
used herein as therein defined), is entered into between Arizona Public Service
Company ("APS"), State Street Bank and Trust Company, as successor to The First
National Bank of Boston, as Owner Trustee and as Lessor, and Mellon Bank, N.A.,
as Decommissioning Trustee ("Decommissioning Trustee").
R E C I T A L S:
- - - - - - - -
WHEREAS, the parties hereto wish to amend the limitations of
the parties' ability to modify the Decommissioning Trust Agreement under certain
circumstances;
NOW, THEREFORE, in consideration of the premises and of other
good and valuable consideration, receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:
A G R E E M E N T S:
- - - - - - - - - -
SECTION 1. Amendments.
The Decommissioning Trust Agreement is hereby amended by
adding the following as the last sentence of Section 15: "Notwithstanding the
foregoing, this Agreement may not be amended or modified in violation of Section
468A of the Code or the regulations thereunder."
SECTION 2. Effectiveness.
This Amendment No. 4 shall become effective as of the date
hereof upon the execution and delivery of a counterpart of this Amendment No. 4
by each of the parties hereto.
SECTION 3. Miscellaneous.
(a) Full Force and Effect.
Except as expressly provided herein, the Decommissioning Trust
Agreement shall remain unchanged and in full force and effect. Each reference in
the Decommissioning Trust Agreement and in any exhibit or schedule thereto to
"this Agreement," "hereto," "hereof" and terms of similar import shall be deemed
to refer to the Decommissioning Trust Agreement as amended hereby.
<PAGE>
(b) Counterparts.
This Amendment No. 4 may be executed in any number of
counterparts, all of which taken together shall constitute one and the same
instrument, and any of the parties hereto may execute this Amendment No. 4 by
signing any such counterpart.
(c) Arizona Law.
This Amendment No. 4 shall be construed in accordance with and
governed by the law of the State of Arizona.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment No. 4 to the Decommissioning Trust Agreement to be duly executed as of
the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
By NANCY E. NEWQUIST
-------------------------------------
Title Treasurer
-----------------------------------
MELLON BANK, N.A., as
Decommissioning Trustee
By EARL G. KLECKNER
-------------------------------------
Earl G. Kleckner
Title Vice President
-----------------------------------
STATE STREET BANK AND TRUST COMPANY,
as Owner Trustee under a Trust Agreement
with Security Pacific Capital Leasing
Corporation and as Lessor under a
Facility Lease with Arizona Public
Service Company
By ERIC DONAGHEY
-------------------------------------
Title Assistant Vice President
-----------------------------------
-2-
<PAGE>
STATE STREET BANK AND TRUST COMPANY,
as Owner Trustee under a Trust Agreement
with Emerson Finance Co. and as Lessor
under a Facility Lease with Arizona
Public Service Company
By ERIC DONAGHEY
-------------------------------------
Title Assistant Vice President
-----------------------------------
STATE OF ARIZONA )
) ss.
County of Maricopa )
The foregoing instrument was acknowledged before me this 16th
day of December, 1996, by Nancy E. Newquist, the Treasurer of ARIZONA PUBLIC
SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
[Official Seal] MARIA R. MARRS
-------------------------------
Notary Public
My commission expires:
July 21, 1998
STATE OF PENNSYLVANIA )
) ss.
County of Allegheny )
The foregoing instrument was acknowledged before me this 16th
day of October, 1996, by Earl Kleckner, a Trust Officer of MELLON BANK, N.A., a
corporation having trust powers, as Decommissioning Trustee, on behalf of said
corporation.
[Official Seal] STEPHANIE RIEGER
---------------------------------
Notary Public
My commission expires:
May 12, 1997
-3-
<PAGE>
Commonwealth of Massachusetts )
) ss.
County of Suffolk )
The foregoing instrument was acknowledged before me this 13th
day of December, 1996, by Eric Donaghey, the Assistant Vice President of STATE
STREET BANK AND TRUST COMPANY, a Massachusetts trust company, in its capacity as
Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing
Corporation, and as Lessor under a Facility Lease with Arizona Public Service
Company, on behalf of said association in such capacities.
[Official Seal] SCOTT KNOX
---------------------------------
Notary Public
My commission expires:
July 12, 2002
Commonwealth of Massachusetts )
) ss.
County of Suffolk )
The foregoing instrument was acknowledged before me this 13th
day of December, 1996, by Eric Donaghey, the Assistant Vice President of STATE
STREET BANK AND TRUST COMPANY, a Massachusetts trust company, in its capacity as
Owner Trustee under a Trust Agreement with Emerson Finance Co., and as Lessor
under a Facility Lease with Arizona Public Service Company, on behalf of said
association in such capacities.
[Official Seal] SCOTT KNOX
---------------------------------
Notary Public
My commission expires:
July 12, 2002
-4-
Exhibit 10.6
AMENDMENT NO. 2
Decommissioning Trust Agreement
(PVNGS Unit 3)
Dated as of July 1, 1991,
as Amended by Amendment No. 1
Dated as of December 1, 1994
between
Arizona Public Service Company
and
Mellon Bank, N.A.
as Decommissioning Trustee
This Amendment No. 2, dated as of December 16, 1996, to the
Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991 as
amended by Amendment No. 1 thereto dated as of December 1, 1994 (the
"Decommissioning Trust Agreement"; terms used herein as therein defined), is
entered into between Arizona Public Service Company ("APS") and Mellon Bank,
N.A., as Decommissioning Trustee ("Decommissioning Trustee").
R E C I T A L S
- - - - - - - -
WHEREAS, the parties hereto wish to amend the limitations of
the parties' ability to modify the Decommissioning Trust Agreement under certain
circumstances;
NOW THEREFORE, in consideration of the premises and of other
good and valuable consideration, receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:
A G R E E M E N T S:
- - - - - - - - - -
SECTION 1. Amendments.
The Decommissioning Trust Agreement is hereby amended by
adding the following as the last sentence of Section 13: "Notwithstanding the
foregoing, this Agreement may not be amended or modified in violation of Section
468A of the Code or the regulations thereunder."
<PAGE>
SECTION 2. Effectiveness.
This Amendment No. 2 shall become effective as of the date
hereof upon the execution and delivery of a counterpart of this Amendment No. 2
by each of the parties hereto.
SECTION 3. Miscellaneous.
(a) Full Force and Effect.
Except as expressly provided herein, the Decommissioning Trust
Agreement shall remain unchanged and in full force and effect. Each reference in
the Decommissioning Trust Agreement and in any exhibit or schedule thereto to
"this Agreement," "hereto," "hereof" and terms of similar import shall be deemed
to refer to the Decommissioning Trust Agreement as amended hereby.
(b) Counterparts.
This Amendment No. 2 may be executed in any number of
counterparts, all of which taken together shall constitute the same instrument,
and any of the parties hereto may execute this Amendment No. 2 by signing any
such counterpart.
(c) Arizona Law.
This Amendment No. 2 shall be construed in accordance with and
governed by the law of the State of Arizona.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment No. 2 to the Decommissioning Trust Agreement to be duly executed as
the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
By NANCY E. NEWQUIST
--------------------------------
Title Treasurer
----------------------------
-2-
<PAGE>
MELLON BANK, N.A., as
Decommissioning Trustee
By EARL G. KLECKNER
--------------------------------
Earl G. Kleckner
Title Vice President
----------------------------
STATE OF ARIZONA )
) ss.
County of Maricopa )
The foregoing instrument was acknowledged before me this 16th
day of December, 1996, by Nancy E. Newquist, the Treasurer of ARIZONA PUBLIC
SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
[Official Seal] MARIA R. MARRS
-------------------------
Notary Public
My commission expires:
July 21, 1998
STATE OF PENNSYLVANIA )
) ss.
County of Allegheny )
The foregoing instrument was acknowledged before me this 16th
day of October, 1996, by Earl Kleckner, a Trust Officer of MELLON BANK, N.A., a
corporation having trust powers, as Decommissioning Trustee, on behalf of said
corporation.
[Official Seal] STEPHANIE RIEGER
-------------------------
Notary Public
My commission expires:
May 12, 1997
-3-
Exhibit 10.7
October 9, 1996
Jaron Norberg
Tempe, Az 85282
Dear Jaron,
As a follow-up to our recent discussion in which you expressed your intent to
retire from APS effective December 31st of this year, I am providing you with a
written summary of those benefit enhancements that we have agreed upon.
Retirement
- ----------
A. The cash equivalent for stock options and restricted stock awarded
under the Pinnacle West Stock Option and Restricted Stock Program that
would have vested with one additional year credited.
B. In recognition for your service on the APS Board of Directors you will
receive an additional four years of credited service for the purpose of
calculating your pension benefit.
C. Your pension benefit will be calculated on base compensation paid in
1994, 1995 and 1996. Additionally, any incentive bonus earned in 1994,
1995 and 1996 will also be included in your pension calculation.
Severance
- ---------
A. You will receive severance pay equal to one year of base salary.
B. You will be credited with one additional year of age and service for
purposes of calculating your pension and SEBRP benefits.
C. You will receive continued dental coverage for a period of one year
beginning January 1, 1997 to December 31, 1997 provided that you
continue to pay your respective share of the premium. At the end of
this one year period, you will be eligible to elect continued coverage
in accordance with COBRA.
<PAGE>
Consulting Services
- -------------------
At the discretion of the Chief Executive Officer you will provide up to six
hundred hours of consulting services to APS in each of the two years following
your retirement at the rate of two hundred dollars per hour.
Miscellaneous
- -------------
We are awarding you the computers you have been using at APS, as well as the
Country Club membership at Phoenix Country Club.
Further, at the discretion of the CEO every effort will be made to accommodate
you with parking at the Corporate Headquarters building subject to availability.
If you have questions regarding any of the preceding information let me know,
otherwise indicate your acknowledgment and agreement by providing your signature
below.
Sincerely,
WILLIAM J. POST
- --------------------------------
William J. Post
Chief Operating Officer
Arizona Public Service
The foregoing is agreed to and accepted:
JARON B. NORBERG
- --------------------------------
Jaron Norberg
Exhibit 10.8
August 16, 1996
Mr. William L. Stewart
Paradise Valley, AZ 85253
Dear Bill,
As a result of our meeting on Tuesday, July 23, 1996, I am pleased to provide
you with a summary of the compensation and retirement benefit enhancements that
we agreed upon.
Base Salary:
- ------------
Your base salary will be increased by $100,000 effective July 23, 1996. Your new
base salary will be $410,026.
Incentive Pay Plan:
- -------------------
You will continue to be a participant in the Officers Incentive Plan as an
Executive Vice President, with an incentive opportunity ranging from 0% - 52% of
base pay.
Retirement:
- -----------
Your retirement benefit will be calculated by adding a base amount of 20% of
your average monthly wage (as determined by the highest 36 consecutive months)
and 10% of your average monthly wage for each year of service. You will become
vested in this benefit when you have accrued four years and 1000 hours of
service (November 1998). The maximum benefit you can accrue is 100% of your
average monthly wage. Under this schedule, you will qualify for the maximum
benefit in November 2001. Please note, this retirement benefit replaces our
previous agreement outlined in your offer letter dated December 21, 1993.
Restricted Stock:
- -----------------
You will receive two thousand shares of restricted stock for each calendar year
you are actively employed at APS retroactive to 1994. This results in an award
of four thousand shares to be issued as soon as possible. Each subsequent years
award will be made in the last quarter of each year and will be provided in
addition to any other stock award you receive under the Pinnacle West Stock
Option and Restricted Stock Program.
<PAGE>
Home Purchase:
- --------------
The Company will purchase your home at its market value and you may live there
for the remainder of your employment at APS. You will be responsible for any
personal income taxes due to this arrangement.
Should you have any questions regarding any of the above information, please
feel free to contact Armando Flores who will implement all of the above actions.
Sincerely,
WILLIAM J. POST
- -----------------------------------
William J. Post
Chief Operating Officer
Arizona Public Service Company
The foregoing is agreed to and accepted:
WILLIAM L. STEWART
- ----------------------------------
William L. Stewart
Exhibit 10.9
November 27, 1996
Mr. George Schreiber
New York, NY 10021
Dear George:
I am delighted to provide you with this offer of employment as Chief Financial
Officer of Arizona Public Service Company and Pinnacle West Capital Corporation.
This is an exciting and challenging time both in the Companies as well as the
industry. Your experience will have a direct impact on our efforts. The
information outlined below covers the major items regarding our offer of
employment. This offer of employment is for a three-year term and renewable by
mutual agreement after the completion of the second year.
As you know this offer is for the position of Executive Vice President and Chief
Financial Officer of Arizona Public Service Company (APS), and Executive Vice
President and Chief Financial Officer of Pinnacle West Capital Corporation
(PNW), with a 50/50 split of your time and efforts directed to each. You will
report directly to me in both Companies and your responsibilities will include
Corporate Finance, Accounting, Treasury, Investor Relations and Risk Management.
Changes in responsibility may occur during the contract term at the discretion
of the Company. The base salary of $375,000 is effective on your first day of
employment, February 3, 1997.
In addition to your base salary, you will participate in the APS Officer
Incentive Program which has a maximum target opportunity of 52% of annual base
salary in 1996. Incentive dollars are generally paid during the first quarter of
the subsequent year. The targets and payout thresholds are reviewed each year.
In 1997, your minimum incentive payment will be $125,000.
In addition to the base and incentive compensation referenced above, you will
also receive a semi-monthly auto allowance totaling $7,200 per year. You will
also be able to utilize a corporate club membership contingent upon your
acceptance. You will be responsible for all monthly dues.
As an additional incentive and contingent upon your acceptance of the position,
the Pinnacle West Board has granted you 1,200 shares of Restricted Stock as well
as 6,000 stock options. The description of these grants is attached. These
grants occur annually in November and are at the levels at which you would
normally participate in the Pinnacle West Capital Corporation Long-Term
Incentive Program. The 1996 grants were determined as if you had been an
employee of the Company at your proposed salary and responsibility levels.
Regarding pension, the Company will credit you with ten years of service which
will allow you to reach the maximum level of pension benefits at age 65.
During 1997, you will be provided with four weeks vacation. For purposes of
vacation, you will be eligible for five weeks vacation after five years of
service.
<PAGE>
Mr. George Schreiber
November 27, 1996
Page 2
I have enclosed copies of our Employee Benefits and a schedule outlining the
employee premiums. Also enclosed is a description of our Employee Savings Plan
in which you will be eligible to participate 31 days after employment. Please
note that the Employee Savings Plan is a pre-tax savings plan and takes
advantage of Section 401(k) of the Code. Also, please note that the premiums
that apply to our medical and dental plan are done on a pre-tax basis.
We will also provide you with a relocation service for the disposition of your
real estate. We have a contract with Western Relocation Management Company.
Briefly, the procedure is that Western will select two independent real estate
appraisers. The two appraisers will appraise the property based on the normal
resale period for your area. Provided that both appraisals are within five
percent of one another, the two will be averaged. That average will be
considered the fair market value of the property. You will be given a written
offer in the amount of the fair value. You have sixty days within which to
decide to accept or reject that offer. If you sell the property to another buyer
for a higher price during the sixty day period, you can then assign the property
over to Western. You will receive a check in the amount of your equity based on
the fair market value assigned by Western, and you will then receive a check
after the closing of the property with the buyer to whom you sold the property
for the difference.
APS will pay all of the relocation company fees, as well as any maintenance of
the property during the period of time it is held for resale. We will also pay
normal closing costs and provide the relocation of all household effects to
Phoenix.
I have also included a copy of the change of control agreement, the Pinnacle
West Capital Corporation Long-Term Incentive Program and the executive insurance
program.
On behalf of APS, I look forward to having you join our team. In the event you
have any questions, feel free to contact me or Armando Flores who will
ultimately coordinate the details of your employment and relocation.
Sincerely,
WILLIAM J. POST
William J. Post
Executive Vice President
Pinnacle West Capital Corporation
and
Senior Vice President and
Chief Operating Officer
Arizona Public Service Company
Enclosures
The foregoing is agreed to and accepted
GEORGE A. SCHREIBER, JR.
- ---------------------------------------------
George Schreiber
Date: 12/3/96
----------------------------------------
Exhibit 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-51085, 33-57822, 33-61228, 33-55473, 33-64455 and 333-15379 on Form S-3, of
our report dated February 28, 1997 appearing in this Annual Report on Form 10-K
of Arizona Public Service Company for the year ended December 31, 1996.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
March 27, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
PUBLIC UTILITY COMPANIES AND PUBLIC UTILITY HOLDING COMPANIES
(THOUSANDS OF DOLLARS)
FISCAL YEAR ENDED DECEMBER 31, 1996
FOR PERIOD JANUARY 1, 1996 THROUGH DECEMBER 31, 1996
TWELVE MONTHS ENDED
</LEGEND>
<MULTIPLIER> 1000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4655140
<OTHER-PROPERTY-AND-INVEST> 113666
<TOTAL-CURRENT-ASSETS> 347158
<TOTAL-DEFERRED-CHARGES> 1307258
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 6423222
<COMMON> 178162
<CAPITAL-SURPLUS-PAID-IN> 1091122
<RETAINED-EARNINGS> 460106
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1729390
53000
165673
<LONG-TERM-DEBT-NET> 2029482
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 16900
<LONG-TERM-DEBT-CURRENT-PORT> 153780
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2274997
<TOT-CAPITALIZATION-AND-LIAB> 6423222
<GROSS-OPERATING-REVENUE> 1718272
<INCOME-TAX-EXPENSE> 178513
<OTHER-OPERATING-EXPENSES> 1174551
<TOTAL-OPERATING-EXPENSES> 1353064
<OPERATING-INCOME-LOSS> 365208
<OTHER-INCOME-NET> 35217
<INCOME-BEFORE-INTEREST-EXPEN> 400425
<TOTAL-INTEREST-EXPENSE> 156954
<NET-INCOME> 243471
17092
<EARNINGS-AVAILABLE-FOR-COMM> 226379
<COMMON-STOCK-DIVIDENDS> 170000
<TOTAL-INTEREST-ON-BONDS> 139699
<CASH-FLOW-OPERATIONS> 587130
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
Arizona Corporation Commission
DOCKETED
DEC 26 1996
DOCKETED BY CM
BEFORE THE ARIZONA CORPORATION COMMISSION
RENZ D. JENNINGS
Chairman
MARCIA WEEKS
Commissioner
CARL J. KUNASEK
Commissioner
IN THE MATTER OF THE COMPETITION ) DOCKET NO. U-0000-94-165
IN THE PROVISION OF ELECTRIC )
SERVICES THROUGHOUT THE STATE )
OF ARIZONA. ) DECISION NO. 59943
)
)
____________________________________) OPINION AND ORDER
-----------------
DATES OF HEARING: December 2, 3 and 4, 1996
PLACES OF PUBLIC Phoenix, Tucson, Yuma, Flagstaff, and
COMMENT: Kingman, Arizona
PRESIDING OFFICERS: Jerry L. Rudibaugh, Jane Rodda, Scott
Wakefield
IN ATTENDANCE: Renz D. Jennings, Chairman
Marcia Weeks, Commissioner
Carl J. Kunasek, Commissioner
APPEARANCES: Mr. Bradford A. Borman, and Mr. Peter
Breen, Staff Attorneys, Legal Division, on
behalf of the Utilities Division of the Arizona
Corporation Commission.
BY THE COMMISSION:
On October 1, 1996, the Utilities Division Staff ("Staff") of the
Arizona Corporation Commission ("Commission") forwarded to the Commission
proposed new rules A.A.C. R14-2-1601 through A.A.C. R14-2-1616 ("Rules" or
"Electric Competition Rules") regarding competitive electric services. By
Decision No. 59870 (October 10, 1996), the Commission directed the Hearing
Division to schedule Public Comment regarding the proposed Rules in Phoenix,
Tucson, Yuma, Flagstaff, and Kingman, Arizona. Our October 11, 1996 Procedural
Order scheduled public comment proceedings on the above-captioned matter on
December 2 in Phoenix, December 3 in Tucson and Yuma, and December
<PAGE>
4 in Flagstaff and Kingman. Decision No. 59870 also ordered Staff to forward a
Notice of Proposed Rulemaking ("Notice") to the Office of the Secretary of State
for publication. The Notice was published in the Arizona Administrative Register
on November 1, 1996.
DISCUSSION
----------
The proposed Competitive Electric Rules set forth a framework for the
inevitable transition from a non-competitive to a competitive environment. It
has been a process that has evolved since May 1994 as Staff has held numerous
workshops prior to bringing forth the proposed Rules. Based on the amount of
comments filed and the attendance at each of the public comment proceedings
held, the interest in the proposed Rules is as great as it has been for as any
rules the Commission has promulgated.
Based on the overall comments, we must conclude that all of the parties
have expressed a desire for a more competitive electric market in Arizona. Some
parties, including Arizona Public Service ("APS"), Tucson Electric Power
("TEP"), Citizens Utilities Company ("Citizens"), Salt River Project ("SRP") and
the cooperatives were not as receptive to the proposed Rules as other parties.
That is certainly understandable since, under the proposed Rules, their status
as monopoly providers of electric service will change.
The parties were generally in agreement that competition will provide
the benefit of reduced costs, at least for some consumers. However, there were
concerns raised regarding the quality of service, as well as concerns that not
all customers, particularly residential customers, will receive the benefits of
competition as quickly as some large industrial customers. And of course, the
incumbent utilities were greatly concerned regarding the recoverability of
stranded costs.
While there was general agreement as to the need and inevitability of
competition in the electric field, there were major disagreements over the
implementation of these Rules. The parties identified complex problems such as
the recoverability of stranded investment, intra-state and inter-state
reciprocity, the status of the new Certificates of Convenience and Necessity
("CC&Ns"), and other issues, for which the parties assert the Rules provide
insufficient guidance. Several parties have suggested holding evidentiary
hearings on these issues in order to resolve them before going forward with
these Rules. Other parties, including Staff, have warned against delay in
promulgating
<PAGE>
these rules, indicating that the competitive electric market is rapidly
approaching whether these Rules are promulgated or not. We conclude that these
gaps, to the extent that they exist, can be filled in later with workshops,
working groups, subsequent evidentiary hearings, and perhaps subsequent
rulemaking proceedings; while competition is approaching rapidly, the transition
to competition will allow time to address these issues and resolve them in a
timely fashion.
* * * * * * * * * *
Having considered the entire record herein and being fully advised in
the premises, the Commission finds, concludes, and orders that:
FINDINGS OF FACT
----------------
1. On October 1, 1996, Staff filed the proposed Rules regarding
competitive electric services.
2. On October 10, 1996, the Commission issued Decision No. 59870 which
directed the Hearing Division to schedule hearings on the proposed Rules in
Phoenix, Tucson, Yuma, Flagstaff, and Kingman, Arizona.
3. The purpose of the proposed Rules is to provide the Commission with
a framework to open the retail electric market to competition, and to streamline
the regulatory process for setting rates for competitive electric services.
4. The proposed amendments to the Rules are set forth in Appendix A,
attached hereto and incorporated by reference.
5. In accordance with A.R.S. Section 41-1027, a Concise Explanatory
Statement for the proposed Rules is set forth in Appendix B, attached hereto and
incorporated by reference.
6. The economic impact of the proposed Rules is set forth in Appendix
C, attached hereto and incorporated by reference.
7. The Notice of Rulemaking was filed with the Secretary of State and
was published in the Arizona Administrative Register on November 1, 1996.
8. Public Comment sessions were held on December 2, 1996, in Phoenix,
December 3, 1996 in Tucson and Yuma, and December 4, 1996 in Flagstaff and
Kingman, Arizona.
<PAGE>
CONCLUSIONS OF LAW
------------------
1. The Commission has authority for the proposed Rules pursuant to the
Arizona Constitution, Article XV, under A.R.S. Sections 40-202, -203, -250,
- -321, -322, -331, -332, -336, 361, -365, -367, and under the Arizona Revised
Statutes, Title 40, generally.
2. Notice of the proceeding has been given in the manner prescribed by
law.
3. Adoption of the proposed Rules is in the public interest.
4. The Concise Explanatory Statement set forth in Appendix B should be
adopted.
ORDER
IT IS THEREFORE ORDERED that the proposed Rules A.A.C. R14-2-1601,
R14-2-1602, R14-2-1603, R14-2-1604, R14-2-1605, R14-2-1606, R14-2-1607,
R14-2-1608, R14-2-1609, R14-2-1610, R14-2-1611, R14-2-1612, R14-2-1613,
R14-2-1614, R14-2-1615, and R14-2-1616, as set forth in Appendix A, and the
Concise Explanatory Statement, as set forth in Appendix B, are hereby adopted.
IT IS FURTHER ORDERED that the Commission=s Utilities Division shall
immediately forward the new Rules A.A.C. R14-2-1601, R14-2-1602, R14-2-1603,
R14-2-1604, R14-2-1605, R14-2-1606, R14-2-1607, R14-2-1608, R14-2-1609,
R14-2-1610, R14-2-1611, R14-2-1612, R14-2-1613, R14-2-1614, R14-2-1615, and
R14-2-1616, to the Secretary of State.
IT IS FURTHER ORDERED that this Decision shall become effective
immediately.
<PAGE>
BY ORDER OF THE ARIZONA CORPORATION COMMISSION
Renz D. Jennings Marcia Weeks Carl J. Kunasek
- --------------------------------------------------------------------------------
CHAIRMAN COMMISSIONER COMMISSIONER
IN WITNESS WHEREOF, I, JAMES MATTHEWS,
Executive Secretary of the Arizona Corporation
Commission, have hereunto, set my hand and
caused the official seal of this Commission to
be affixed at the Capitol, in the City of
Phoenix, this 26th day of December , 1996.
Phillip R. Moulton, Deputy
---------------------------------------
for JAMES MATTHEWS
Executive Secretary
DISSENT __________________
GY:DB:KEC: RTW:BAB:mmc
<PAGE>
TITLE 14. PUBLIC SERVICE CORPORATIONS; CORPORATIONS AND
ASSOCIATIONS; SECURITIES REGULATIONS
CHAPTER 2. CORPORATION COMMISSION - FIXED UTILITIES
ARTICLE 16. RETAIL ELECTRIC COMPETITION
Section
R14-2-1601. Definitions
R14-2-1602. Filing of Tariffs by Affected Utilities
R14-2-1603. Certificates of Convenience and Necessity
R14-2-1604. Competitive Phases
R14-2-1605. Competitive Services
R14-2-1606. Services Required To Be Made Available by Affected
Utilities
R14-2-1607. Recovery of Stranded Cost of Affected Utilities
R14-2-1608. System Benefits Charges
R14-2-1609. Solar Portfolio Standard
R14-2-1610. Spot Markets and Independent System Operation
R14-2-1611. In-State Reciprocity
R14-2-1612. Rates
R14-2-1613. Service Quality, Consumer Protection, Safety, and
Billing Requirements
R14-2-1614. Reporting Requirements
R14-2-1615. Administrative Requirements
R14-2-1616. Legal Issues
<PAGE>
ARTICLE 16. RETAIL ELECTRIC COMPETITION
R14-2-1601. Definitions
In this Article, unless the context otherwise requires:
1. "Affected Utilities" means the following public service corporations
providing electric service:
Tucson Electric Power Company, Arizona Public Service Company, Citizens
Utilities Company, Arizona Electric Power Cooperative, Trico Electric
Cooperative, Duncan Valley Electric Cooperative, Graham County Electric
Cooperative, Mohave Electric Cooperative, Sulphur Springs Valley
Electric Cooperative, Navopache Electric Cooperative, Ajo Improvement
Company, and Morenci Water and Electric Company.
#In the event that modifications are made to existing law that would allow
the application of this Article to the Salt River Project Agricultural
Improvement and Power District ("SRP") then Affected Utilities shall also
include SRP.#
2. "Bundled Service" means electric service provided as a package to the
consumer including all generation, transmission, distribution, ancillary
and other services necessary to deliver and measure useful electric energy
and power to consumers.
3. "Buy-through" refers to a purchase of electricity by an Affected Utility at
wholesale for a particular retail consumer or aggregate of consumers or at
the direction of a particular retail consumer or aggregate of consumers.
4. "Distribution Service" means the delivery of electricity to a retail
consumer through wires, transformers, and other devices that are not
classified as transmission services subject to the jurisdiction of the
Federal Energy Regulatory Commission; Distribution Service excludes meters
and meter reading.
5. "Electric Service Provider" means a company supplying, marketing, or
brokering at retail any of the services described in R14-2-1605 or
R14-2-1606.
6. "Eligible Demand" means the total consumer kilowatts of demand which an
Affected Utility must make available to competitive generation under the
terms of this Article or the consumer kilowatts of demand provided
competitively in an Affected Utility's distribution territory, whichever is
greater.
7. "Standard Offer" means Bundled Service offered to all consumers in a
designated area at regulated rates.
8. "Stranded Cost" means the verifiable net difference between:
a. The value of all the prudent jurisdictional assets and obligations
necessary to furnish electricity (such as generating plants, purchased
power contracts, fuel contracts, and regulatory assets), acquired or
entered into prior to the adoption of this Article, under traditional
regulation of Affected Utilities; and
b. The market value of those assets and obligations directly
attributable to the introduction of competition under this Article.
9. "System Benefits" means Commission-approved utility low income, demand side
management, environmental, renewables, and nuclear power plant
decommissioning programs.
10. "Unbundled Service" means electric service elements provided and priced
separately, including, but not limited to, such service elements as
generation, transmission, distribution, and ancillary services. Unbundled
Service may be sold to consumers or to other Electric Service Providers.
Text between # indicates strikethrough
<PAGE>
R14-2-1602. Filing of Tariffs by Affected Utilities
Each Affected Utility shall file tariffs consistent with this Article by
December 31, 1997.
R14-2-1603. Certificates of Convenience and Necessity
A. Any Electric Service Provider intending to supply services described in
R14- 2-1605 or R-14-2-1606, other than services subject to federal
jurisdiction, shall obtain a Certificate of Convenience and Necessity from
the Commission pursuant to this Article; however, a Certificate is not
required to offer information services or billing and collection services.
An Affected Utility does not need to apply for a Certificate of Convenience
and Necessity for any service provided as of the date of adoption of this
Article within its distribution service territory.
B. Any company desiring such a Certificate of Convenience and Necessity shall
file with the Docket Control Center the required number of copies of an
application. Such Certificates shall be restricted to geographical areas
served by the Affected Utilities as of the date this Article is adopted and
to service areas added under the provisions of R14-2-1611. In support of
the request for a Certificate of Convenience and Necessity, the following
information must be provided:
1. A description of the electric services which the applicant intends to
offer;
2. The proper name and correct address of the applicant, and
a. The full name of the owner if a sole proprietorship,
b. The full name of each partner if a partnership,
c. A full list of officers and directors if a corporation, or
d. A full list of the members if a limited liability corporation;
3. A tariff for each service to be provided that states the maximum rate
and terms and conditions that will apply to the provision of the
service;
4. A description of the applicant's technical ability to obtain and
deliver electricity and provide any other proposed services;
5. Documentation of the financial capability of the applicant to provide
the proposed services, including the most recent income statement and
balance sheet, the most recent projected income statement, and other
pertinent financial information. Audited information shall be provided
if available;
6. A description of the form of ownership (e.g., partnership,
corporation);
7. Such other information as the Commission or the Staff may request.
C. At the time of filing for a Certificate of Convenience and Necessity, each
applicant shall notify the Affected Utilities in whose service territories
it wishes to offer service of the application by serving a complete copy of
the application on the Affected Utilities.
D. The Commission may deny certification to any applicant who:
1. Does not provide the information required by this Article;
2. Does not possess adequate technical or financial capabilities to
provide the proposed services;
3. Fails to provide a performance bond, if required.
E. Every Electric Service Provider obtaining a Certificate of Convenience and
Necessity under this Article shall obtain certification subject to the
following conditions:
1. The Electric Service Provider shall comply with all Commission rules,
orders,
<PAGE>
and other requirements relevant to the provision of electric service
and relevant to resource planning;
2. The Electric Service Provider shall maintain accounts and records as
required by the Commission;
3. The Electric Service Provider shall file with the Director of the
Utilities Division all financial and other reports that the Commission
may require and in a form and at such times as the Commission may
designate;
4. The Electric Service Provider shall maintain on file with the
Commission all current tariffs and any service standards that the
Commission shall require;
5. The Electric Service Provider shall cooperate with any Commission
investigation of customer complaints;
6. The Electric Service Provider shall obtain all necessary permits and
licenses;
7. Failure to comply with any of the above conditions may result in
recision of the Electric Service Provider's Certificate of Convenience
and Necessity.
F. In appropriate circumstances, the Commission may require, as a precondition
to certification, the procurement of a performance bond sufficient to cover
any advances or deposits the applicant may collect from its customers, or
order that such advances or deposits be held in escrow or trust.
R14-2-1604. Competitive Phases
A. Each Affected Utility shall make available at least 20 percent of its 1995
system retail peak demand for competitive generation supply to all customer
classes (including residential and small commercial consumers) not later
than January 1, 1999. If data permit, coincident annual peak demand shall
be used; otherwise noncoincident peak data may be used.
1. No more than 1/2 of the Eligible Demand may be procured by consumers,
each of whose total competitive contract demand is greater than 3 MW.
2. At least 15% of the Eligible Demand shall be reserved for residential
consumers.
3. Aggregation of loads of multiple consumers shall be permitted.
B. Each Affected Utility shall make available at least 50% of its 1995
system retail peak demand for competitive generation supply to all customer
classes (including residential and small commercial consumers) not later
than January 1, 2001. If data permit, coincident peak annual demand shall
be used; otherwise noncoincident peak data may be used.
1. No more than 1/2 of the Eligible Demand may be procured by consumers,
each of whose total competitive contract demand is greater than 3 MW.
2. At least 30 % of the Eligible Demand shall be reserved for residential
consumers.
3. Aggregation of loads of multiple consumers shall be permitted.
C. Prior to 2001, no single consumer shall receive more than 20% of the
Eligible Demand in a given year in an Affected Utility's service territory.
D. Each Affected Utility shall make available all of its retail demand for
competitive generation supply not later than January 1, 2003.
<PAGE>
E. By the date indicated in R14-2-1602, Affected Utilities shall propose for
Commission review and approval how customers will be selected for
participation in the competitive market prior to 2003.
1. Possible selection methods are first-come, first-served; random
selection via a lottery among volunteering consumers; or designation of
geographic areas.
2. The method for selecting customers to participate in the competitive
market must fairly allow participation by a wide variety of customers
of all sizes of loads.
3. All customers who produce or purchase at least 10% of their annual
electricity consumption from photovoltaic or solar thermal resources
installed in Arizona after January 1, 1997 shall be selected for
participation in the competitive market if those customers apply for
participation in the competitive market. Such participants count toward
the minimum requirements in R14-2- 1604(A) and R14-2-1604(B).
4. The Commission Staff shall commence a series of workshops on selection
issues within 45 days of the adoption of this Article and Staff shall
submit a report to the Commission discussing the activities and
recommendations of participants in the workshops. The report shall be
due not later than 90 days prior to the date indicated in R14-2-1602.
F. Retail consumers served under existing contracts are eligible to
participate in the competitive market prior to expiration of the existing
contract only if the Affected Utility and the consumer agree that the
retail consumer may participate in the competitive market.
G. An Affected Utility may engage in Buy-throughs with individual or
aggregated consumers. Any contract for a Buy-through effective prior to the
date indicated in R14-2-1604(A) must be approved by the Commission.
H. Schedule Modifications for Cooperatives
1. An electric cooperative may request that the Commission modify the
schedule described in R14-2-1604(A) through R14-2-1604(D) so as to
preserve the tax exempt status of the cooperative or to allow time to
modify contractual arrangements pertaining to delivery of power
supplies and associated loans.
2. As part of the request, the cooperative shall propose methods to
enhance consumer choice among generation resources.
3. The Commission shall consider whether the benefits of modifying the
schedule exceed the costs of modifying the schedule.
R14-2-1605. Competitive Services
A properly certificated Electric Service Provider may offer any of the following
services under bilateral or multilateral contracts with retail consumers:
A. Generation of electricity from generators at any location whether owned by
the Electric Service Provider or purchased from another generator or
wholesaler of electric generation.
B. Any service described in R14-2-1606, except Distribution Service and except
services required by the Federal Energy Regulatory Commission to be
monopoly services. Billing and collection services and information services
do not require a
<PAGE>
Certificate of Convenience and Necessity.
R14-2-1606. Services Required To Be Made Available by Affected Utilities
A. Until the Commission determines that competition has been substantially
implemented for a particular class of consumers (residential, commercial,
industrial) so that all consumers in that class have an opportunity to
participate in the competitive market, and until all Stranded Costs
pertaining to that class of customers have been recovered, each Affected
Utility shall make available to all consumers in that class in its service
area, as defined on the date indicated in R14-2-1602, Standard Offer
bundled generation, transmission, ancillary, distribution, and other
necessary services at regulated rates.
1. An Affected Utility may request that the Commission determine that
competition has been substantially implemented to allow discontinuation
of Standard Offer service and shall provide sufficient documentation to
support its request.
2. The Commission may, on its own motion, investigate whether competition
has been substantially implemented and whether Standard Offer service
may be discontinued.
B. Standard Offer Tariffs
1. By the date indicated in R14-2-1602, each Affected Utility may file
proposed tariffs to provide Standard Offer Bundled Service and such
rates shall not become effective until approved by the Commission. If
no such tariffs are filed, rates and services in existence as of the
date in R14-2-1602 shall constitute the Standard Offer.
2. Affected Utilities may file proposed revisions to such rates. It is the
expectation of the Commission that the rates for Standard Offer
service will not increase, relative to existing rates, as a result of
allowing competition. Any rate increase proposed by an Affected Utility
for Standard Offer service must be fully justified through a rate case
proceeding.
3. Such rates shall reflect the costs of providing the service.
4. Consumers receiving Standard Offer service are eligible for future rate
reductions authorized by the Commission, such as reductions authorized
in Decision No. 59601.
C. By the date indicated in R14-2-1602, each Affected Utility shall file
Unbundled Service tariffs to provide the services listed below to all
eligible purchasers on a nondiscriminatory basis:
1. Distribution Service;
2. Metering and meter reading services;
3. Billing and collection services;
4. Open access transmission service (as approved by the Federal Energy
Regulatory Commission, if applicable);
5. Ancillary services in accordance with Federal Energy Regulatory
Commission Order 888 (III FERC Stats. & Regs. P. 31,036, 1996)
incorporated herein by reference;
6. Information services such as provision of customer information to other
Electric Service Providers;
7. Other ancillary services necessary for safe and reliable system
operation.
D. To manage its risks, an Affected Utility may include in its tariffs deposit
requirements and advance payment requirements for Unbundled Services.
E. The Affected Utilities must provide transmission and ancillary services
according to the following guidelines:
1. Services must be provided consistent with applicable tariffs filed with
the Federal Energy Regulatory Commission.
2. Unless otherwise required by federal regulation, Affected Utilities
must accept power and energy delivered to their transmission systems by
others and offer transmission and related services comparable to
services they provide to
<PAGE>
themselves.
F. Customer Data
1. Upon authorization by the customer, an Electric Service Provider shall
release in a timely and useful manner that customer's demand and energy
data for the most recent 12 month period to a customer-specified
Electric Service Provider.
2. The Electric Service Provider requesting such customer data shall
provide an accurate account number for the customer.
3. The form of data shall be mutually agreed upon by the parties and such
data shall not be unreasonably withheld.
G. Rates for Unbundled Services
1. The Commission shall review and approve rates for services listed in
R14-2-1606(C) and requirements listed in R14-2-1606(D), where it has
jurisdiction, before such services can be offered.
2. Such rates shall reflect the costs of providing the services.
3. Such rates may be downwardly flexible if approved by the Commission.
H. Electric Service Providers offering services under this R14-2-1606 shall
provide adequate supporting documentation for their proposed rates. Where
rates are approved by another jurisdiction, such as the Federal Energy
Regulatory Commission, those rates shall be provided to this Commission.
I. Within 90 days of the adoption of this Article, the Commission Staff shall
commence a series of workshops to explore issues in the provision of
Unbundled Service and Standard Offer service.
1. Parties to be invited to participate in the workshops shall include
utilities, consumers, organizations promoting energy efficiency, and
other Electric Service Providers.
2. Among the issues to be reviewed in the workshops are: metering
requirements; metering protocols; designation of appropriate test
years; the nature of adjustments to test year data; de-averaging of
rates; service characteristics such as voltage levels; revenue
uncertainty; line extension policies; and the need for performance
bonds.
3. A report shall be submitted to the Commission by the Staff on the
activities and recommendations of the participants in the workshops not
later than 60 days prior to the date indicated in R14-2-1602. The
Commission shall consider any recommendations regarding Unbundled
Service and Standard Offer service tariffs.
R14-2-1607. Recovery of Stranded Cost of Affected Utilities
A. The Affected Utilities shall take every feasible, cost-effective measure to
mitigate or offset Stranded Cost by means such as expanding wholesale or
retail markets, or offering a wider scope of services for profit, among
others.
B. The Commission shall allow recovery of unmitigated Stranded Cost by
Affected Utilities.
C. A working group to develop reccomendations for the analysis and recovery of
Stranded Cost shall be established.
1. The working group shall commence activities within 15 days of the date
of adoption of this Article.
2. Members of the working group shall include representatives of Staff,
the Residential Utility Consumer Office, consumers, utilities, and
other Electric Service Providers. In addition, the Executive and
Legislative Branches shall be invited to send representatives to be
members of the working group.
3. The working group shall be coordinated by the Director of the Utilities
Division of the Commission or by his or her designee.
D. In developing its recommendations, the working group shall consider at
least the following factors:
1. The impact of Stranded Cost recovery on the effectiveness of
competition;
2. The impact of Stranded Cost recovery on customers of the Affected
Utility who do not participate in the competitive market;
3. The impact, if any, on the Affected Utility's ability to meet debt
obligations;
4. The impact of Stranded Cost recovery on prices paid by consumers who
participate in the competitive market;
5. The degree to which the Affected Utility has mitigated or offset
Stranded Cost;
6. The degree to which some assets have values in excess of their book
values;
7. Appropriate treatment of negative Stranded Cost;
8. The time period over which such Stranded Cost charges may be recovered.
The Commission shall limit the application of such changes to a
specified time period;
9. The ease of determining the amount of Stranded Cost;
10. The applicability of Stranded Cost to interruptible customers;
11. The amount of electricity generated by renewable generating resources
owned by the Affected Utility.
E. The working group shall submit to the Commission a report on the activities
and recommendations of the working group no later than 90 days prior to the
date indicated in R14-2-1602.
F. The Commision shall consider the recommendations and decide what actions,
if any, to take based on the recommendations.
G. The Affected Utilities shall file estimates of unmitigated Stranded Cost.
Such estimates shall be fully supported by analyses and by records of
market transactions undertaken by willing buyers and willing sellers.
<PAGE>
H. An Affected Utility shall request Commission approval of distribution
charges or other means of recovering unmitigated Stranded Cost from
customers who reduce or terminate service from the Affected Utility as a
direct result of competition governed by this Article, or who obtain lower
rates from the Affected Utility as a direct result of the competition
governed by this Article.
I. The Commission shall, after hearing and consideration of analyses and
recommendations presented by the Affected Utilities, Staff, and
intervenors, determine for each Affected Utility the magnitude of Stranded
Cost, and appropriate Stranded Cost recovery mechanisms and charges. In
making its determination of mechanisms and charges, the Commission shall
consider at least the following factors:
1. The impact of Stranded Cost recovery on the effectiveness of
competition;
2. The impact of Stranded Cost recovery on customers of the Affected
Utility who do not participate in the competitive market;
3. The impact, if any, on the Affected Utility's ability to meet debt
obligations;
4. The impact of Stranded Cost recovery on prices paid by consumers who
participate in the competitive market;
5. The degree to which the Affected Utility has mitigated or offset
Stranded Cost;
6. The degree to which some assets have values in excess of their book
values;
7. Appropriate treatment of negative Stranded Cost;
8. The time period over which such Stranded Cost charges may be recovered.
The Commission shall limit the application of such charges to a
specified time period;
9. The ease of determining the amount of Stranded Cost;
10. The applicability of Stranded Cost to interruptible customers;
11. The amount of electricity generated by renewable generating resources
owned by the Affected Utility.
J. Stranded Cost may only be recovered from customer purchases made in the
competitive market using the provisions of this Article. Any reduction in
electricity purchases from an Affected Utility resulting from
self-generation, demand side management, or other demand reduction
attributable to any cause other than the retail access provisions of this
Article shall not be used to calculate or recover any Stranded Cost from a
consumer.
K. The Commission may order an Affected Utility to file estimates of Stranded
Cost and mechanisms to recover or, if negative, to refund Stranded Cost.
L. The Commission may order regular revisions to estimates of the magnitude of
Stranded Cost.
R14-2-1608. System Benefits Charges
A. By the date indicated in R14-2-1602, each Affected Utility shall file for
<PAGE>
Commission review non-bypassable rates or related mechanisms to recover the
applicable pro-rata costs of System Benefits from all consumers located in
the Affected Utility's service area who participate in the competitive
market. In addition, the Affected Utility may file for a change in the
System Benefits charge at any time. The amount collected annually through
the System Benefits charge shall be sufficient to fund the Affected
Utilities' present Commission-approved low income, demand side management,
environmental, renewables, and nuclear power plant decommissioning
programs.
B. Each Affected Utility shall provide adequate supporting documentation for
its proposed rates for System Benefits.
C. An Affected Utility shall recover the costs of System Benefits only upon
hearing and approval by the Commission of the recovery charge and
mechanism. The Commission may combine its review of System Benefits charges
with its review of filings pursuant to R14-2-1606.
D. Methods of calculating System Benefits charges shall be included in the
workshops described in R14-2-1606(I).
R14-2-1609. Solar Portfolio Standard
A. Starting on January 1, 1999, any Electric Service Provider selling
electricity under the provisions of this Article must derive at least 1/2
of 1% of the total retail energy sold competitively from new solar
resources, whether that solar energy is purchased or generated by the
seller. Solar resources include photovoltaic resources and solar thermal
resources that generate electricity. New solar resources are those
installed on or after January 1, 1997.
B. Solar portfolio standard after December 31, 2001:
1. Starting on January 1, 2002, any Electric Service Provider selling
electricity under the provisions of this Article must derive at least
1% of the total retail energy sold competitively from new solar
resources, whether that solar energy is purchased or generated by the
seller. Solar resources include photovoltaic resources and solar
thermal resources that generate electricity. New solar resources are
those installed on or after January 1, 1997.
2. The Commission may change the solar portfolio percentage applicable
after December 31, 2001, taking into account, among other factors, the
costs of producing solar electricity and the costs of fossil fuel for
conventional power plants.
C. Any Electric Service Provider certificated under the provisions of this
Article shall be able to credit 2 times the electric energy it generated,
or caused to be generated under contract, before January 1, 1999 using
photovoltaics or solar thermal resources installed on or after January 1,
1997 in Arizona to the electric energy requirements of R14-2-1609(A) or
R14-2-1609(B).
D. Electric Service Providers selling electricity under the provisions of this
Article shall provide reports on sales and solar power as required in this
Article, clearly demonstrating the output of solar resources, the
installation date of solar resources, and the transmission of energy from
those solar resources to Arizona consumers. The Commission may conduct
necessary monitoring to ensure the accuracy of these data.
E. If an Electric Service Provider selling electricity under the provisions of
this Article fails to meet the requirement in R14-2-1609(A) or
R14-2-1609(B) in any year, the Commission may impose a penalty on that
Electric Service Provider up to
<PAGE>
$0.30 per kWh for deficiencies in the provision of solar energy. In
addition, if the provision of solar energy is consistently deficient, the
Commission may void an Electric Service Provider's contracts negotiated
under this Article.
F. Photovoltaic or solar thermal resources that are located on the consumer's
premises shall count toward the solar portfolio standard applicable to the
current Electric Service Provider serving that consumer.
G. The solar portfolio standard described in this section is in addition to
renewable resource goals for Affected Utilities established in Decision No.
58643.
R14-2-1610. Spot Markets and Independent System Operation
A. The Commission shall conduct an inquiry into spot market development and
independent system operation for the transmission system.
B. The Commission may support development of a spot market or independent
system operator(s) for the transmission system.
C. The Commission may work with other entities to help establish spot markets
and independent system operators.
R14-2-1611. In-State Reciprocity
A. The service territories of Arizona electric utilities which are not
Affected Utilities shall not be open to competition under the provisions of
this Article, nor shall Arizona electric utilities which are not Affected
Utilities be able to compete for sales in the service territories of the
Affected Utilities.
B. An Arizona electric utility, subject to the jurisdiction of the Commission,
which is not an Affected Utility may voluntarily participate under the
provisions of this Article if it makes its service territory available for
competing sellers, if it agrees to all of the requirements of this Article,
and if it obtains an appropriate Certificate of Convenience and Necessity.
#C. The Commission shall pursue, on its own or in cooperation whith the Joint
Legislative Study Committe on Electric Industry Competition established by
House Bill 2504 (1996), legislation to address the role of electric
utilities of Arizona political subdivisions or municipal corporations in a
competitive market. The Commission shall further make available, as
appropriate, Staff assistance to the Legislature if the Legislature
requests such assistance for the purpose of determining the proper role of
electric utilities of Arizona political subdivisions or municipal
corporations in a competitive market.
D. An Arizona electic utility, not subject to the jurisdiction of the
Commission, which is not an Affected Utility, may voluntarily participate
under the provisions of this Article if it makes its service territory
available for competing sellers, if it agrees to all of the requirements of
this Article other than any requirement to obtain a Certificate of
Convenience and Necessity, if adequate enforcement mechanisms can be
established, and if all other Affected Utilities consent in writing.#
C. An Arizona electric utility, not subject to the jurisdiction of the
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Commission, may submit a statement to the Commission that it voluntarily
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opens its service territory for competing sellers in a manner similar to
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the provisions of this Article. Such statement shall be accompanied by the
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electric utility's nondiscriminatory Standard Offer Tariff, electric supply
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tariffs, Unbundled Services rates, Stranded Cost charges, System Benefits
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charges, Distribution Services charges and any other applicable tariffs and
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policies for services the electric utility offers for which these Rules
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otherwise require compliance by Affected Utilities or Electric Service
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Providers. Such filings shall serve as authorization for such electric
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utility to utilize the Commission's Rules of Practice and Procedure and
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other applicable Rules concerning any complaint that an Affected Utility or
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#Text between # indicates strikethrough
Electric Service Provider is violating any provision of this Article or is
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otherwise discriminating against the filing electric utility or failing to
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provide just and reasonable rates in tariffs filed under this Article.
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D. If an electric utility is an Arizona political subdivision or municipal
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corporation, then the existing service territory of such electric utility
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shall be deemed open to competition if the political subdivision or
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municipality has entered into an intergovernmental agreement with the
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Commission that establishes nondiscriminatory terms and conditions for
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Distribution Services and other Unbundled Services, provides a procedure
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for complaints arising therefrom, and provides for reciprocity with
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Affected Utilities. The Commission shall conduct a hearing to consider any
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such intergovernmental agreement.
R14-2-1612. Rates
A. Market determined rates for competitively provided services as defined in
R14-2-1605 shall be deemed to be just and reasonable.
B. Each Electric Service Provider selling services under this Article shall
have on file with the Commission tariffs describing such services and
maximum rates for those services, but the services may not be provided
until the Commission has approved the tariffs.
C. Prior to the date indicated in R14-2-1604(D), competitively negotiated
contracts governed by this Article customized to individual customers which
comply with approved tariffs do not require further Commission approval.
However, all such
<PAGE>
contracts whose term is one year or more and for service of 1 MW or more
must be filed with the Director of the Utilities Division as soon as
practicable. If a contract does not comply with the provisions of this
Article it shall not become effective without a Commission order.
D. Contracts entered into on or after the date indicated in R14-2-1604(D)
which comply with approved tariffs need not be filed with the Director of
the Utilities Division. If a contract does not comply with the provisions
of this Article it shall not become effective without a Commission order.
E. An Electric Service Provider holding a Certificate pursuant to this Article
may price its competitive services, as defined in R14-2-1605, at or below
the maximum rates specified in its filed tariff, provided that the price is
not less than the marginal cost of providing the service.
F. Requests for changes in maximum rates or changes in terms and conditions of
previously approved tariffs may be filed. Such changes become effective
only upon Commission approval.
R14-2-1613. Service Quality, Consumer Protection, Safety, and Billing
Requirements
A. Except as indicated elsewhere in this Article, R14-2-201 through R14-2-212,
inclusive, are adopted in this Article by reference. However, where the
term "utility" is used in R14-2-201 through R14-2-212, the term "utility"
shall pertain to Electric Service Providers providing the services
described in each paragraph of R14-2-201 through R14-2-212. R14-2-212(G)(2)
shall pertain only to Affected Utilities. R14-2-212(G)(4) shall apply only
to Affected Utilities. R14-2-212(H) shall pertain only to Electric Service
Providers who provide distribution service.
B. The following shall not apply to this Article:
1. R14-2-202 in its entirety,
2. R14-2-212(F)(1),
3. R14-2-213.
C. No consumer shall be deemed to have changed suppliers of any service
authorized in this Article (including changes from supply by the Affected
Utility to another supplier) without written authorization by the consumer
for service from the new supplier. If a consumer is switched to a different
("new") supplier without such written authorization, the new supplier shall
cause service by the previous supplier to be resumed and the new supplier
shall bear all costs associated with switching the consumer back to the
previous supplier.
D. Each Electric Service Provider providing service governed by this Article
shall be responsible for meeting applicable reliability standards and shall
work cooperatively with other companies with whom it has interconnections,
directly or indirectly, to ensure safe, reliable electric service.
E. Each Electric Service Provider shall provide at least 30 days notice to all
of its affected consumers if it is no longer obtaining generation,
transmission, distribution, or ancillary services necessitating that the
consumer obtain service from another supplier of generation, transmission,
distribution, or ancillary services.
<PAGE>
F. All Electric Service Providers rendering service under this Article shall
submit accident reports as required in R14-2-101.
G. An Electric Service Provider providing firm electric service governed by
this Article shall make reasonable efforts to reestablish service within
the shortest possible time when service interruptions occur and shall work
cooperatively with other companies to ensure timely restoration of service
where facilities are not under the control of the Electric Service Provider
H. Each Electric Service Provider shall ensure that bills rendered on its
behalf include the toll free telephone numbers for billing, service, and
safety inquiries and the telephone number of the Consumer Services Section
of the Arizona Corporation Commission Utilities Division. Each Electric
Service Provider shall ensure that billing and collection services rendered
on its behalf comply with R14-2-1613(A) and R14-2- 1613(B).
I. Additional Provisions for Metering and Meter Reading Services
1. An Electric Service Provider who provides metering or meter reading
services pertaining to a particular consumer shall provide access to
meter readings to other Electric Service Providers serving that same
consumer.
2. A consumer or an Electric Service Provider relying on metering
information provided by another Electric Service Provider may request a
meter test according to the tariff on file and approved by the
Commission. However, if the meter is found to be in error by more than
3%, no meter testing fee will be charged.
3. Protocols for metering shall be developed subsequent to the workshops
described in R14-2-1606(I).
J. Working Group on System Reliability and Safety:
1. If it has not already done so, the Commission shall establish, by
separate order, a working group to monitor and review system
reliability and safety.
a. The working group may establish technical advisory panels to
assist it.
b. The working group shall commence activities within 15 days of the
date of adoption of this Article.
c. Members of the working group shall include representatives of
Staff, consumers, the Residential Utility Comsumer Office,
utilities, other Electric Service Providers and organizations
promoting energy efficiency. In addition, the Executive and
Legislative Branches shall be invited to send representatives to
be members of the working group.
d. The working group shall be coordinated by the Director of the
Utilities Division of the Commission or by his or her designee.
2. All Electric Service Providers governed by this Article shall cooperate
and participate in any investigation conducted by the working group,
including provision of data reasonably related to system reliability or
safety.
3. The working group shall report to the Commission on system reliability
and safety regularly, and shall make recommendations to the Commission
regarding improvements to reliability or safety.
K. Electric Service Providers shall comply with applicable reliability
standards and practices established by the Western Systems Coordinating
Council and the North American Electric Reliability Council or successor
organizations.
L. Electric Service Providers shall provide notification and informational
materials to
<PAGE>
consumers about competition and consumer choices, such as a standardized
description of services, as ordered by the Commission.
R14-2-1614. Reporting Requirements
A. Reports covering the following items shall be submitted to the Director of
the Utilities Division by Affected Utilities and all Electric Service
Providers granted a Certificate of Convenience and Necessity pursuant to
this Article. These reports shall include the following information
pertaining to competitive service offerings, Unbundled Services, and
Standard Offer services in Arizona:
1. Type of services offered;
2. kW and kWh sales to consumers, disaggregated by customer class (e.g.,
residential, commercial, industrial);
3. Solar energy sales (kWh) and sources for grid connected solar
resources; kW capacity for off-grid solar resources;
4. Revenues from sales by customer class (e.g., residential, commercial,
industrial);
5. Number of retail customers disaggregated as follows: aggregators,
residential, commercial under 100 kW, commercial 100 kW to 2999 kW,
commercial 3000 kW or more, industrial less than 3000 kW, industrial
3000 kW or more, agricultural (if not included in commercial), and
other;
6. Retail kWh sales and revenues disaggregated by term of the contract
(less than 1 year, 1 to 4 years, longer than 4 years), and by type of
service (for example, firm, interruptible, other);
7. Amount of and revenues from each service provided under R14-2- 1605,
and, if applicable, R14-2-1606;
8. Value of all Arizona specific assets and accumulated depreciation;
9. Tabulation of Arizona electric generation plants owned by the Electric
Service Provider broken down by generation technology, fuel type, and
generation capacity;
10. Other data requested by Staff or the Commission;
11. In addition, prior to the date indicated in R14-2-1604(D), Affected
Utilities shall provide data demonstrating compliance with the
requirements of R14-2-1604;
B. Reporting Schedule
1. For the period through December 31, 2003, semi-annual reports shall be
due on April 15 (covering the previous period of July through December)
and October 15 (covering the previous period of January through June).
The first such report shall cover the period January 1 through June 30,
1999.
2. For the period after December 31, 2003, annual reports shall be due on
April 15 (covering the previous period of January through December).
The first such report shall cover the period January 1 through December
31, 2004.
C. The information listed above may be provided on a confidential basis.
However, Staff or the Commission may issue reports with aggregate
statistics based on confidential information that do not disclose data
pertaining to a particular seller or purchases by a particular buyer.
<PAGE>
D. Any Electric Service Provider governed by this Article which fails to file
the above data in a timely manner may be subject to a penalty imposed by
the Commission or may have its Certificate rescinded by the Commission.
E. Any Electric Service Provider holding a Certificate pursuant to this
Article shall report to the Director of the Utilities Division the
discontinuation of any competitive tariff as soon as practicable after the
decision to discontinue offering service is made.
F. In addition to the above reporting requirements, Electric Service Providers
governed by this Article shall participate in Commission workshops or other
forums whose purpose is to evaluate competition or assess market issues.
G. Reports filed under the provisions of this section shall be submitted in
written format and in electronic format. Electric Service Providers shall
coordinate with the Commission Staff on formats.
R14-2-1615. Administrative Requirements
A. Any Electric Service Provider certificated under this Article may propose
additional electric services at any time by filing a proposed tariff with
the Commission describing the service, maximum rates, terms and conditions.
The proposed new electrical service may not be provided until the
Commission has approved the tariff.
B. Contracts filed pursuant to this Article shall not be open to public
inspection or made public except on order of the Commission, or by the
Commission or a Commissioner in the course of a hearing or proceeding.
C. The Commission may consider variations or exemptions from the terms or
requirements of any of the rules in this Article upon the application of an
affected party. The application must set forth the reasons why the public
interest will be served by the variation or exemption from the Commission
rules and regulations. Any variation or exemption granted shall require an
order of the Commission. Where a conflict exists between these rules and an
approved tariff or order of the Commission, the provisions of the approved
tariff or order of the Commission shall apply.
D. The Commission may develop procedures for resolving disputes regarding
implementation of retail electric competition.
R14-2-1616. Legal Issues
A. A working group to identify, analyze and provide recommendations to the
Commission on legal issues relevant to this Article shall be established.
1. The working group shall commence activities within 15 days of the date
of adoption of this Article.
2. Members of the working group shall include representatives of Staff,
the Residential Utility Consumer Office, consumers, utilities, and
other Electric Service Providers. In addition, the Executive and
Legislative Branches and the Attorney General shall be invited to send
representatives to be members of the working group.
3. The working group shall be coordinated by the Director of the Legal
Division of the Commission or by his or her designee.
B. The working group shall submit to the Commission a report on the activities
and recommendations of the working group no later than 90 days prior to the
date indicated in R14-2-1602.
C. The Commission shall consider the recommendations and decide what actions,
if any, to take based on the recommendations.
<PAGE>
APPENDIX B
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CONCISE EXPLANATORY STATEMENT
-----------------------------
This explanatory statement is provided to comply with A.R.S. Section
41-1036.
I. REASONS FOR ADOPTING THE PROPOSED AMENDMENTS.
The Arizona Corporation Commission has promulgated proposed Rules to
govern the provision of competitive electric services in the State of Arizona.
R14-2-1601. Definitions.
This section contains all the definitions necessary to interpret and
follow the provisions set forth in the proposed Rules.
R14-2-1602. Filing of Tariffs by Affected Utilities.
This section requires all Affected Utilities (defined in R14-2-1601) to
file tariffs required by this Article by December 31, 1997.
R14-2-1603. Certificates of Convenience and Necessity.
This section requires all Electric Services Providers (defined in
R14-2-1601) intending to supply electric services under this Article to obtain a
Certificate of Convenience and Necessity from the Commission. Affected Utilities
already have Certificates for their existing service area, and thus need not
obtain a Certificate in order to continue to provide service therein. This
section sets up the process for obtaining such Certificates, as well as grounds
for denial and conditions under which they may be granted.
R14-2-1604. Competitive Phases.
This section outlines the time frames for the introduction of
competition in Arizona. In the first phase, to begin in 1999, Affected Utilities
are required to open up 20 percent of their base year (1995) markets (as
measured by kW demand) to competition. In the second phase, to begin in 2001,
this is enlarged to at least 50 percent of the incumbent utilities' base year
markets. Full competition for generation, the third phase, begins in 2003. At
least 15 percent of the eligible demand must be reserved for residential
consumers in the competitive marketplace in the first phase, and at least 30
percent of the eligible demand must be reserved for residential consumers in the
competitive marketplace in the second phase. In addition, prior to 2001, no
single consumer may receive more
<PAGE>
than 20 percent of the total service available in the competitive market in an
Affected Utility's service territory.
The Affected Utilities must propose how customers will be selected for
participation in the competitive market. Consumers who use photovoltaics or
solar thermal resources (built after January 1, 1997 and installed in Arizona)
for at least 10 percent of their annual electricity consumption are
automatically included in the list of eligible customers for participation in
the competitive market if they wish to participate in the competitive market. To
assist the Affected Utilities and the Commission in understanding selection
issues, a workshop will be conducted on selection issues prior to the date when
selection filings are due.
Customers served under existing contracts are eligible to participate
in the competitive market prior to expiration of the existing contract only if
the affected utility and customer agree to early revision of the contract.
Buy-throughs are permitted on a voluntary basis. These mechanisms, which enable
the incumbent utility to purchase specific sources of energy at wholesale for
the use of a specific consumer, may enable some consumers to obtain some of the
benefits of competition prior to the start of the first competitive phase, if
the Commission approves.
Electric cooperatives may request a modification to the schedule. Any
such requests must include proposals on enhancing consumer choice among
generation resources. The Commission will have to consider the costs and
benefits of modifying the schedule in making a determination on the proposed
modifications.
R14-2-1605. Competitive Services.
This section describes services which can be provided competitively.
These include generation at any location (including distributed generation) plus
other services except distribution service and except services required by the
federal government to be provided on a monopoly basis.
R14-2-1606. Services Required To Be Made Available by Affected Utilities.
This section deals with utilities' obligations to provide unbundled
services and standard offer services. Incumbent utilities must offer "Standard
Offer" service in their service territories until the Commission determines that
competition has been substantially implemented. Standard offer service consists
of bundled service at regulated rates for consumers who do not or cannot
participate in the
<PAGE>
competitive market. In addition, by December 31, 1997, Affected Utilities will
have to file unbundled tariffs to provide to all eligible purchasers on a
nondiscriminatory basis the following services: Distribution service, metering
and meter reading, billing and collection, open access transmission service, and
ancillary services. Such transmission and ancillary service tariffs must be
consistent with applicable tariffs filed with the Federal Energy Regulatory
Commission ("FERC").
This section also sets up guidelines and practices for the
authorization and release of customer demand and energy data, sets up a process
for the review of rates for unbundled services, and sets up a series of
workshops to explore various issues involved in the provision of unbundled
services and Standard Offer services.
R14-2-1607. Recovery of Stranded Cost of Affected Utilities.
This section discusses the process by which Affected Utilities may seek
to recover their unmitigated Stranded Costs (defined in R14-2-1601). The section
sets up a working group to develop recommendations for the analysis and recovery
of such Stranded Costs, and sets forth several factors to be considered in
allowing this recovery. Stranded Costs can only be recovered from customers in
the competitive marketplace, and estimates of Stranded Costs must be updated
periodically to allow the Commission to monitor the magnitude of such costs, and
to grant refunds where such estimates may be overstated.
R14-2-1608. System Benefits Charges.
This section recognizes the availability of the recovery of costs of
Commission-approved utility low income, demand side management, environmental,
renewables, and nuclear power plant decommissioning programs. Affected Utilities
are to propose the necessary charges on competitive consumers (to continue
existing programs) for Commission review and approval.
R14-2-1609. Solar Portfolio Standard.
This section requires any Electric Service Provider selling electricity
under the provisions of the Rules to derive at least 1/2 of 1% of the total
retail energy sold competitively from new solar resources. As of January 1,
2001, this standard becomes 1%, unless the Commission decides otherwise. New
solar resources are those installed on or after January 1, 1997. Electric
Service Providers selling electricity derived from new solar resources prior to
January 1, 1999 are allowed
<PAGE>
to claim credit toward the Solar Portfolio Standard for twice the electric
energy generated by such solar resources prior to 1999. Periodic reports of such
sales of solar energy are required; Electric Services Providers who fail to meet
the standard in the Rules may be subject to penalties imposed by the Commission.
R14-2-1610. Spot Markets and Independent System Operators.
This section requires the Commission to conduct an inquiry into spot
market development and independent system operation for the transmission system;
the Commission is authorized to support the development of either, and may work
with other entities to help establish them.
R14-2-1611. In-State Reciprocity.
This section recognizes that electric utilities which are not subject
to the Commission's jurisdiction are not allowed to participate in the
competitive electric market unless certain legislative changes are made, or
these electric utilities either voluntarily submit to the Commission=s
jurisdiction for purposes of such participation, or they enter into some form of
agreement with the Commission to allow for their participation under mutually
agreeable terms.
R14-2-1612. Rates.
This section sets forth the Commission's determination that rates
determined by the competitive market are just and reasonable. Electric Service
Providers selling services under these Rules are required to file with the
Commission tariffs describing such services along with the maximum rates of
those services, subject to Commission approval. Pricing for competitive services
may be at or below the maximum rates specified in the tariff, provided the price
is not less than the marginal cost of the service. Changes in maximum rates or
in terms and conditions of previously approved tariffs may be filed, and are
effective upon Commission approval.
R14-2-1613. Service Quality, Consumer Protection, Safety, and Billing
Requirements.
This section explicitly recognizes that the Commission's existing rules
for electric service apply in the competitive arena, except in specific
instances. "Slamming" by suppliers of electric service is explicitly prohibited.
Electric Service Providers supplying service under these Rules are responsible
for meeting applicable reliability standards, are required to provide customer
notice if it is unable to continue providing customers with any service, shall
submit accident reports, shall
<PAGE>
make reasonable efforts to reestablish service in the shortest possible time in
the event of service interruptions, and shall ensure that bills rendered on
their behalf include toll free telephone numbers for customer inquiries. In
addition, Electric Service Providers supplying metering or meter reading
services shall provide access to meter readings to other Electric Service
Providers serving the same customer. Meter tests may be requested by a consumer
or an Electric Service Provider relying on meter information provided by another
Electric Service Provider; such test shall be without charge if an error of more
than 3% is found. A working group on System Reliability and Safety is set up to
monitor and review such issues and make regular reports to the Commission on
these issues. All Electric Service Providers are required to comply with
applicable reliability standards and practices set forth by the Western Systems
Coordinating Council and the North American Electric Reliability Council or
successor organizations.
R14-2-1614. Reporting Requirements.
This section requires regular reporting of market information so the
Commission is able to monitor developments in competitive markets.
R14-2-1615. Administrative Requirements.
This section indicates that Electric Service Providers may file to
offer new services and that contracts are not public documents. It further
states the Commission may grant variation s or exemptions from portions of the
Rules. The Commission may also adopt procedures to resolve disputes.
R14-2-1616. Legal Issues.
This section sets up a working group to identify, analyze and provide
recommendations to the Commission on legal issues relative to these Rules. The
Commission shall consider the recommendations and decide the appropriate actions
to take thereon.
II. CHANGES IN THE TEXT OF THE PROPOSED AMENDMENT FROM THAT CONTAINED IN
THE NOTICE OF RULEMAKING FILED WITH THE SECRETARY OF STATE.
A.A.C. R14-2-1601 Definitions
The last sentence has been deleted from R14-2-1601.1. The deleted
language stated that "In the event that modifications are made to exisiting law
that would allow the application of this Article to the Salt River Project
Agricultural Improvement and Power District ("SRP"), then Affected Utilities
shall also include SRP."
A.A.C. R14-2-1603 Certificates of Convenience and Necessity
The second sentence of R14-2-1603(B) has been amended to read: "Such
Certificates shall be restricted to geographical areas served by the Affected
Utilities as of the date this Article is adopted and to service areas added
under the provisions of R14-2-1611."
A.A.C. R14-2-1611 In-State Reciprocity
R14-2-1611(C) has been deleted. The remaining subsections have been
renumbered and relettered accordingly.
R14-2-1611D (now C) has been amended to read:
C. An Arizona electric utility, not subject to the jurisdiction
of the Commission, may submit a statement to the Commission
that it voluntarily opens its service territory for competing
sellers in a manner similar to the provisions of this Article.
Such statement shall be accompanied by the electric utility's
nondiscriminatory Standard Offer tariff, electric supply
tariffs, Unbundled Services rates, Stranded Cost charges,
System Benefits charges, Distribution Services charges and any
other applicable tariffs and policies for services the
electric utility offers, for which these Rules otherwise
require compliance by Affected Utilities or Electric Service
Providers. Such filings shall serve as authorization for such
electric utility to utilize the Commission's Rules of Practice
and Procedure and other applicable Rules concerning any
complaint that an Affected Utility or Electric Service
Provider is violating any provision of this Article or is
otherwise discriminating against the filing electric utility
or failing to provide just and reasonable rates in tariffs
filed under this Article.
R14-2-1611D has been added to read:
D. If an electric utility is an Arizona political subdivision or
municipal corporation, then the existing service territory of
such electric utility shall be deemed open to competition if
the political subdivision or municipality has entered into an
intergovernmental agreement with the Commission that
establishes
<PAGE>
nondiscriminatory terms and conditions for Distribution
Services and other Unbundled Services, provides a procedure
for complaints arising therefrom, and provides for reciprocity
with Affected Utilities. The Commission shall conduct a
hearing to consider any such intergovernmental agreement.
III. EVALUATION OF THE ARGUMENTS FOR AND AGAINST THE PROPOSED AMENDMENTS.
A. General Legal Arguments Against The Rules.
1. The Commission Has the Legal Right to Promulgate These Rules.
One primary overriding comment made by the parties is that the
Commission has no legal right to adopt these Rules. This argument follows
several lines of reasoning, the three primary ones being that the rules modify
or abrogate the regulatory compact; the rules are in violation of the Arizona
Administrative Procedures Act; and that the Commission does not have the
authority to issue, modify or delete a Certificate of Convenience and Necessity
without some legislative change.
Issue: The Rules Are an Unlawful Modification or Abrogation of
the Regulatory Compact.
The basic argument made by the parties regarding the regulatory compact
is that there is some sort of "contract" between the state and the incumbent
monopoly electric utility, wherein the utility is obligated to supply
electricity to all customers who require it at a reasonable cost, and in return,
the state agrees to provide the utility with the exclusive right to serve all
customers within a defined territory. The argument goes on to assert that since
the Proposed Rules would change the exclusive nature of electric service, the
rules unilaterally abrogate or at least modify this contract, and thus the
Proposed Rules cannot be passed.
Staff argues that no such contract has been formed. Generally, a party
asserting the formation of a contract by statute must overcome a presumption
against such formation, and courts will be cautious both in identifying a
contract within the language of a regulatory statute, and in defining the
outlines of any contractual obligation. Nat'l R.R. Passenger Corp. v. Atchison,
Topeka, and Santa Fe Ry. Co., 470 U.S. 451, 466, 105 S.Ct. 1441, 1452 (1985).
"[A]bsent some clear indication that the legislature intends to bind itself
contractually, the presumption is that 'a law is not intended
<PAGE>
to create private contractual or vested rights but merely declares a policy to
be pursued until the legislature shall ordain otherwise.'" Id. at 465-66, 105
S.Ct. at 1451 (quoting Dodge v. Bd. Educ. of City of Chicago, 302 U.S. 74, 79,
58 S.Ct. 98, 100 (1937)). In promulgating these Proposed Rules, the Commission
is exercising the legislative discretion flowing from its plenary ratemaking
authority. See Simms v. Round Valley Light & Power, 80 Ariz. 145, 294 P.2d 378
(1956). The question as to whether particular legislation creates a contractual
right begins with an examination of the statute itself. Nat'l R.R. Corp., 470
U.S. at 465-66, 105 S.Ct. at 1451. However, a search of the Arizona Constitution
reveals no such intent on the part of the State to bind itself. Indeed, the
Constitution expressly disfavors monopolies: "[m]onopolies and trusts shall
never be allowed in this State . . . ." Ariz. Const. Art. XIV, section 15.
Staff further notes that, while the parties cite Application of Trico
Electric Co-operative, Inc., 92 Ariz. 373, 377 P.2d 309 (1962) for the
proposition that "the state in effect contracts" with a monopoly utility, that
language in Trico is clearly dicta. Additionally, other cases refer to regulated
monopoly as public policy rather than a contractual relationship. See Ariz.
Corp. Comm'n v. Super. Ct., 105 Ariz. 56, 59, 459 P.2d 489 (1969) (regulated
monopoly held to be public policy of Arizona); Winslow Gas Co. v. Southern Union
Gas Co., 76 Ariz. 373, 385, 265 P.2d 442, 443 (1954)(referring to Arizona=s
public policy of controlled monopoly); James P. Paul Water Co. v. Ariz. Corp.
Comm'n, 137 Ariz 426, 429, 671 P.2d 404, 407 (1983)("It is well established that
Arizona's public policy respecting public service corporations . . . is one of
regulated monopoly over freewheeling competition.").
In addition, Staff points out that it is well established that any
alleged contract is subject to modifications in the law. The parties seem to
find the source of the regulatory compact in both the Arizona Constitution and
the statutes concerning public service corporations. The Constitution clearly
provides for changes in the law concerning public service corporations; see
Ariz. Const Art. XV, section 3. Further, any statutes concerning public service
corporations may be changed at any time as well. If indeed the Constitution and
the statutes have created a contract such as the parties claim, then this
possibility for changes in the law must also be a part of that contract.
Analysis: We are not convinced that the regulatory policy of the state
has formed any
<PAGE>
sort of contract with the Affected Utilities. It appears that the former
"policy" of regulated monopoly was just that- a policy, made with no intent to
bind the state or the Commission. Finally, we recognize, as should the
utilities, that such regulatory policies are always subject to change as the
economics and technologies of the time also change.
Resolution: There is no reason to delay the promulgation of these
Rules.
Issue: The Rules Violate the Administrative Procedures Act.
The next argument made by the parties is that the Commission in
adopting the Proposed Rules in this manner is violating the Arizona
Administrative Procedures Act ("APA"), A.R.S. section 41-1001 et seq. There are
two prongs to this argument, one being that the rules will clearly not be
certified by the Attorney General's office, and the other being that because the
Economic Impact Statement ("EIS") accompanying the Proposed Rules are somehow
inadequate, interested persons are not given an adequate opportunity for notice
and comment as required in the APA. Both prongs are without merit.
Staff believes that the rules are not subject to Attorney General
certification, as they are quite plainly a manifestation of the Commission's
ratemaking authority. Clearly, the adoption of the Proposed Rules will have an
impact on rates, something even all the commentators seem to recognize. Such an
impact on rates has been recognized as grounds for the Commission's authority to
exercise its plenary ratemaking authority through the adoption of rules. Ariz.
Corp. Comm'n v. State ex rel. Woods, 171 Ariz. 286, 295, 830 P.2d 807, 816
(1992). Where rules, such as these, are an exercise of that ratemaking
authority, the Attorney General does not have the authority to review and reject
them. State ex rel. Corbin v. Ariz. Corp. Comm'n, 174 Ariz. 216, 219, 848 P.2d
301 (Ct.App. 1992).
Further, Staff notes that the Commission is expressly exempted pursuant
to A.R.S. section 41-1057 from the requirement of submitting an EIS as set forth
in section 41-1055. Under section 41-1057, the Commission is merely required to
adopt substantially similar review procedures for its rules. This is what Staff
has done in this case in preparing the EIS forwarded to the Secretary of State
as part of the rulemaking package. Staff thus believes its EIS thus meets the
requirements of the APA.
Analysis: We have previously litigated the issue of whether Commission
rules
<PAGE>
involving ratemaking are subject to review and certification by the Attorney
general=s office. The Courts have been clear in deciding that they are not.
Further, we are satisfied that the EIS prepared by Staff meets the statutory
requirements set forth in A.R.S. section 41-1057.
Resolution: There is no reason to delay the promulgation of these
Rules.
Issue: The Adoption of These Rules Modifies Existing CC&Ns.
Another argument raised by various parties in this proceeding is that
the Commission has no authority to enact the Rules because the legislature has
not afforded the Commission the authority to issue competitive CC&Ns as is
contemplated by the Rules. According to this argument, the Commission has no
authority to promulgate the Rules until the legislature grants to the Commission
the authority to grant competitive CC&Ns.
Staff urges that the adoption of these Rules does not grant to any
potential competitor the right to provide electric service. Pursuant to the
Rules, CC&Ns may be granted to applicants after going through an application
process which includes public notice of the application and an opportunity for a
hearing. See A.A.C. R14-2-1603. No CC&N is granted merely by the adoption of the
Rules, and any CC&N granted under these Rules is expressly conditional upon
numerous factors set forth in the rules. Therefore no additional legislative
authority is required for the Commission to promulgate the Rules.
Furthermore, Staff points out that courts have recognized that the
Commission does have the authority to determine when competition is in the
public interest and to issue competitive CC&Ns. Arizona v. People's Freight
Line, 41 Ariz. 158, 166-67, 16 P.2d 420, 423 (1932); Winslow Gas Co. v. Southern
Union Gas Co., 76 Ariz. 383, 385, 265 P.2d 442, 443 (1954). Thus, while Staff
welcomes a role for the legislature in clarifying this authority, Staff believes
such authority already exists.
Analysis: The Rules as drafted set forth a framework for the
introduction of competition into the electric services market in Arizona. As
they are merely a framework, the Rules do not grant, modify, or delete any new
or existing CC&N. The Rules do set up a process that must be followed before any
such event occurs. All of the objecting parties are anticipated and expected to
participate in such process. We are also persuaded by Staff's argument that we
already have the authority to
<PAGE>
grant competitive CC&Ns, when the public interest demands it. However, that is
an issue that we expect to address again before any competitive CC&Ns are
issued.
Resolution: There is no reason to delay the promulgation of these
Rules.
2. The Adoption of the Proposed Rules Does Not Violate Due Process.
Issue: Several parties in their comments have observed that the
Proposed Rules as written violate due process because they are impermissibly
vague. They argue that the Proposed Rules defer resolution of too many issues,
such as stranded cost and the nature of CC&Ns under the rules, and do not give
the affected parties fair warning as to how these and other aspects of the rules
will be determined by the Commission.
Staff acknowledges that a statute or rule is impermissibly vague in
violation of due process if a) it fails to give a person of ordinary
intelligence a reasonable opportunity to know what the law is in order to plan
accordingly, or b) it allows arbitrary or discriminatory enforcement by failing
to provide an objective standard. Bird v. State, 184 Ariz. 198, 908 P.2d 12
(Ct.App. 1995). However, Staff believes the Rules as written do not violate this
standard. First, in regard to stranded cost recovery, the Rules set up a process
for utilities claiming to have incurred stranded costs to seek recovery of those
costs. The Rules set forth several factors for the Commission to consider in
determining a utility's stranded cost, and allow the requesting utility to
recover the appropriate amount. The Rules thus give the utility an opportunity
to know what the law is so it can plan ahead, and sets forth an objective
standard which the Commission must follow in doing so. As for CC&Ns, once again
it is clear to a person of ordinary intelligence that under the Rules, all new
CC&Ns will be competitive CC&Ns, and that under the rules there is a clear
standard for granting such CC&Ns.
Analysis: The Rules as written give the parties a great deal of
guidance in terms of what is expected in the new competitive environment.
Precise specificity is of course impossible; neither we nor anyone else has the
prescience to know exactly what will happen in the future. However, the Rules do
set adequate standards and processes for dealing with these future
uncertainties. We thus do not agree that the Rules are impermissibly vague in
violation of due process.
Resolution: There is no reason to delay the promulgation of these
Rules.
3. The Proposed Rules Do Not Violate Equal Protection.
<PAGE>
Issue: Some parties argue that the rules as proposed do not allow for
equal treatment of all members of a recognized class, that class being all
entities that provide electric services. The claim is made that the Proposed
Rules treat incumbent monopoly public service corporations differently than they
treat such potential competitors as the Salt River Project, municipal
corporations, tribal authorities and non-utility generators. According to these
comments, these other entities are not subject to any of the obligations of the
Proposed Rules, but are still allowed to reap the benefits of the rules. Such
unequal treatment, it is claimed, violates equal protection.
Staff notes that there are serious differences between the incumbent
monopoly providers and other potential entrants. Equal protection is satisfied
if all persons in a class are treated alike. Baseball Liquors v. Circle K Corp.,
129 Ariz. 215, 630 P.2d 38 (Ct.App. 1981), cert den. 454 U.S. 969, 102 S.Ct.
515. Legislation which applies to members of a class, but not to nonmembers of
that class, will be upheld under equal protection if the classification is not
arbitrary and there is a substantial difference between those within the class
and those without. Farmer v. Killingsworth, 102 Ariz. 44, 424 P.2d 172 (1967).
In this instance, there is one clear difference between the incumbent monopoly
providers, and all others: the incumbents' monopoly status. To treat all parties
identically under the rules would fail to recognize the incumbents' ability to
use their current monopoly status to inhibit the competition these rules are
designed to encourage. These Proposed Rules recognize that electric competition
is not a race that begins with all entrants beginning at the starting gate;
rather, the incumbents have a significant head start and a full head of steam.
The Proposed Rules treat the incumbents differently because they ARE different.
This does not violate equal protection.
Analysis: As pointed out by Staff, there are clear reasons why Affected
Utilities are treated differently than other entities under these Rules. Indeed,
it would make no sense to make their treatment identical, because of their
differing circumstances. The Rules identify those differences and treat the
classes fairly based on those differences.
Resolution: There is no reason to delay the promulgation of these
Rules.
4. Passage of the Proposed Rules Does Not Constitute an
Unconstitutional Taking.
Issue: Another argument put forth by several parties is that the
property rights of regulated
<PAGE>
utilities enjoy constitutional protection, and therefore the Rules constitute an
unconstitutional taking of this property. The primary focus of these comments s
that because under the Rules the Commission possibly may not allow recovery of a
utility's entire stranded cost claim, this constitutes a regulatory taking of
the utility's property without compensation. Another argument is that the rules
confiscate the exclusive rights inherent in existing CC&Ns without compensation
Staff believes such claims are premature at this time. The Rules as
written do not take anything; they do not deny any utility recovery of any
stranded cost, nor do they grant any new CC&N. What the rules do is set forth a
framework wherein a regulated entity claiming to have stranded costs may come
before the Commission and seek recovery of those costs. The rules also establish
a process wherein potential new entrants may apply for and receive a CC&N. Mere
adoption of the Rules will not result in any property being taken.
Furthermore, Staff argues that in order for a taking to be
unconstitutional, it must be done without compensation. The law is well-settled
that takings claims are not ripe until the plaintiff has been denied
compensation. Pub. Serv. Comm'n of New Mexico v. City of Albuquerque, 755
F.Supp. 1494, 1498 (D.N.M. 1991). If a state provides an adequate procedure for
seeking just compensation, the property owner cannot claim a violation until it
has used the procedure and been denied just compensation. Williamson Co.
Regional Planning Comm'n v. Hamilton Bank, 473 U.S. 172, 195, 105 S.Ct. 3108,
3121 (1985).
Any property that a utility believes has been taken once competition
has been implemented under the Rules is essentially a stranded cost. The Rules
allow for stranded cost recovery, and set forth a process wherein utilities can
seek recovery of these costs.
Analysis: Mere adoption of these Rules does not constitute a taking.
Thus claims by parties that the Rules constitute an unlawful taking are clearly
premature. Losses in value of utility assets as a result of competition would
appear to be stranded costs; as the Rules set forth a process to allow for the
recovery of stranded costs, it seems clear that the Rules do not constitute an
unconstitutional taking of any utility property.
Resolution: There is no reason to delay the promulgation of these
Rules.
B. A.A.C. R14-2-1601: Definitions
<PAGE>
Issue: Trico proposes that cooperatives be deleted from the definition
of affected utilities (R14-2-1601(1)).
Staff disagrees. The consumers located in the service areas of the
cooperatives should be able to benefit from competition.
Analysis: The Commission agrees that all customers should be able to
benefit from competition, including those located in the service areas of
cooperatives.
Resolution: No amendment to R14-2-1601(1) is necessary.
Issue: APS wants to delete the word "net" and to delete the term
"value" and substitute "recorded costs of the assets and obligations" from the
definition of stranded costs in R14-2-1601(8). Further, APS wants to substitute
"used and useful" for "necessary," pertaining to furnishing electricity. APS is
also concerned that stranded costs refers only to assets and obligations created
prior to the adoption of the article.
TEP is concerned that the proposed definition of stranded cost would
result in reconsideration of the prudence of past investment decisions. TEP
states that it is unclear what specific assets and obligations are included in
stranded cost and whether the definition is limited to balance sheet accounts.
TEP states that stranded cost is not limited to generation assets and may
include regulatory assets and operating expenses.
In response to Arizona Public Service Company's concerns, Staff
believes that the word "net" is essential -- it reflects the fact that some
assets will have market values greater than regulated values and that some
assets will have market values less than regulated value. Further, Staff
believes the rule should be general so as to permit stranded cost calculations
reflecting the individual circumstances of a given utility.
Staff expects that, in general, reconsideration such as concerns TEP
would not be undertaken, but cannot rule out reconsideration of the prudence of
past investments in every circumstance. Further, Staff believes that the
definition is clear on these points: the calculation of stranded cost will not
consider only generation assets, and can include purchased power contracts,
regulatory assets, fuel contracts, etc.
Evaluation: The Commission should not just allow a utility to recover
stranded costs only
<PAGE>
for those assets whose value has decreased without offsetting that gross
stranded cost with increases in the value of other assets. Substituting
"recorded costs of the assets and obligations" for "value" is not necessary.
APS' point can be dealt with in the stranded cost working group to obtain input
from other parties; this may be an issue on which consensus can be reached.
Resolution: No amendment to R14-2-1601(8) is necessary.
C. R14-2-1604: Competitive Phases
Issue: Several cooperatives (Arizona Electric Power Cooperative, Duncan
Valley Electric Cooperative, Inc., Graham County Electric Cooperative, Inc., and
Sulphur Springs Valley Electric Cooperative), would substitute for
R14-2-1604(H), which allows for modifications of the implementation schedule for
cooperatives, a requirement that the cooperatives file a report describing the
status of the efforts to address and resolve tax exemption and contractual and
federal financing issues. Phelps Dodge Morenci, Inc. (Phelps Dodge) disagrees
with the contention that cooperatives should be exempted from competition. To do
so, Phelps Dodge says, would mean that rural customers will be prevented from
receiving the lowest possible price of electricity.
Staff disagrees with the cooperatives, and agrees with Phelps Dodge,
because this proposal will exclude consumers served by cooperatives from the
benefits of competition and dilute incentives for the cooperatives to introduce
competition.
The cooperatives propose that a new definition be added for available
transmission capability ("the meaning accorded it by Federal Energy Regulatory
Commission Order 888 ...). The phrase "subject to Available Transmission
Capability" would then be added to the beginning of R14-2-1604(A), (B), and (D).
FERC Order 888 requires transmission providers to describe their method for
determining available transmission capability posted on the transmission
provider's OASIS (Open Access Same time Information Systems). If sufficient
transmission capability may not exist to accommodate a service request, the
transmission provider will respond by performing a system impact study (Section
15.2 of the pro-forma tariff). System impact studies are described in Section 32
of the pro-forma tariff. If transmission upgrades are needed to supply a service
request, the customer must reimburse the transmission provider for the
facilities study and, if the customer wants the facilities, he or she will have
to pay for them. Staff believes that the cooperative's proposal
<PAGE>
incorrectly gives the impression that the transmission provider is not obligated
to conduct system impact studies or facilities studies as required by the FERC.
Therefore, Staff recommends that the wording of the proposed rule not be changed
as suggested by the cooperatives.
The cooperatives also propose to add language to R14-2-1604 that states
that "Any consumer which elects to participate in the competitive market shall
pay all costs attributable to such election including but not limited to special
metering costs and any costs required to relieve transmission or distribution
constraints." Staff argues that these costs should be covered by rates charged
for unbundled services; no change in the rule is needed.
Analysis: As with Trico's objection to R14-2-1601(1), the Commission
agrees that all customers should be able to benefit from competition, including
those located in the service areas of cooperatives. Further, it appears to the
Commission that the cooperatives' proposed language regarding transmission
service gives the misleading impression that transmission providers have no
obligation regarding the stated studies. Finally, the proposed language
regarding competitive customers paying special metering costs and other costs is
not necessary.
Resolution: No amendment to R14-2-1604 is necessary.
Issue: Timing of the introduction to competition.
TEP proposes that unbundling of distribution services be postponed
until 2002 to allow operational issues with generation competition to be sorted
out first and to allow time to prepare for "complete competitive product and
service unbundling."
Nordic Power of Southpoint I, Limited Partnership (Nordic Power)
"supports market-based rates with customer choice in the most expeditious manner
reasonably feasible." Nordic Power proposes that the phase-in begin no later
than January 1, 1998. Enron Capital & Trade Resources (ECT) agrees that
competition should begin in 1998, rather than in 1999.
Staff believes that two years offers a practical, but aggressive
schedule, in which to address all of the unanswered questions that need to be
resolved. Two years will allow for evidentiary hearings, working group
deliberations, and time to review successful programs as well as problems in
other state restructuring efforts.
<PAGE>
Analysis: The time line in the Rule as written for the introduction of
competition in these services is both reasonable and feasible. It allows time
for the Commission, Staff and other parties to come up to speed on competition
quickly, yet is not so hasty as to ignore lessons that can be learned through
the procedures in the rules and the experiences of other states.
Resolution: No amendment to R14-2-1604 is necessary.
D. R14-2-1606: Services Required To Be Made Available by Affected
Utilities
Issue: Obligation to provide service.
APS wants clarification that an Affected Utility has an obligation to
provide service and plan for generation resources during the phase-in period for
those customers not eligible for access. Staff notes that R14-2-1606(A)
indicates that Affected Utilities have an obligation to provide standard offer
service until the Commission determines otherwise.
Analysis: R14-2-1606(A) is clear on this subject: an Affected Utility
has an obligation to provide Standard Offer service until otherwise ordered by
this Commission.
Resolution: No amendment to R14-2-1606 is necessary.
E. R14-2-1607: Recovery of Stranded Cost of Affected Utilities
Issue: R14-2-1607(A) requires Affected Utilities to take every
feasible, cost-effective measure to mitigate Stranded Costs.
APS wants to replace in R14-2-1607(A),"every feasible, cost effective
[mitigation] measure" with "reasonable [mitigation] measures..." Staff believes
this proposed change may be more workable than the initial wording and would not
object to such a change if it were clear that the Commission is serious about
having utilities actively work to offset stranded costs through mitigation
measures. APS further proposes deletion of the examples of types of mitigation.
Staff believes that the examples provide additional clarity to the intent.
TEP states that it is unclear whether mitigation of stranded costs
includes only energy related activities or is all-encompassing, covering any
business activity the utility and its affiliates may pursue. TEP believes that
profits from activities that are unrelated to the provision of electricity in
Arizona and that do not require use of assets acquired to serve electric
customers in Arizona, and that are potentially strandable, should not be
considered as a source of funds to offset stranded cost.
<PAGE>
Further, TEP fears that costs of mitigation activities could become stranded.
Staff interprets the rule as including all activities, including
non-energy-related activities, as part of mitigation. An Affected Utility's
losses due to stranded cost are to be offset by that company's gains in other
activities. Further, there cannot be any recoverable stranded costs associated
with mitigation since those costs would not be necessary to furnish electricity
to consumers in the utility's service territory and be incurred prior to the
adoption of the Article.
RUCO wants greater emphasis on mitigation of stranded costs.
Analysis: This Commission is serious about having utilities actively
pursue mitigation measure to offset stranded costs. Because of that, we believe
it is important to retain the current language requiring Affected Utilities to
take "every feasible, cost-effective measure to mitigate or offset Stranded
Cost." We further agree with Staff that the inclusion of examples of mitigation
or offset are helpful to parties in understanding what we are expecting.
We interpret the rule in a manner similar to Staff, in that it
envisions Affected Utilities utilizing a wide variety of methods to mitigate or
offset Stranded Cost, including methods unrelated to energy activities. We also
agree with Staff that there are no recoverable Stranded Costs associated with
mitigation, since those costs cannot be both necessary to furnish electricity to
consumers in its service territory, and be incurred prior to the adoption of
these Rules.
So far as RUCO's comments are concerned, we believe the Rule as written
adequately emphasizes the importance of mitigation. Further, RUCO never
indicates how this additional emphasis is to be provided.
Resolution: No amendment to R14-2-1607(A) is necessary.
Issue: Guarantee of recovery of Stranded Costs.
RUCO wants the rule to indicate that there is no guarantee of recovery
of stranded costs and that the Commission should make a determination regarding
the amount of stranded costs that should be recoverable by each utility. The
rule allows recovery of unmitigated stranded cost (R14-2-1607(B)) and for the
determination of the magnitude of stranded cost (R14-2-1607(I)).
Destec is concerned that the Commission has determined the efficacy of
stranded cost recovery before considering the issue.
<PAGE>
Staff expects that the Commission will ultimately consider a wide range
of estimates of the magnitude of stranded cost offered by Affected Utilities,
Staff, RUCO, consumer groups, and other intervenors. The Commission must also
consider several factors regarding mechanisms and charges for recovery of
stranded costs (R14-2-1607(I)). Staff believes that no change in the rule is
needed on this matter.
Analysis: The Rule does guarantee recovery of unmitigated Stranded
Cost, but also provides a process for determining the magnitude of Stranded
Cost, and recovery mechanisms and charges. Input from various parties as to that
magnitude is provided and encouraged.
Resolution: No amendment to the Rule is necessary.
Issue: R14-2-1607(I) lists various factors to be considered by the
Commission in determining the mechanisms for the recovery of Stranded Cost.
APS wants the rule to indicate that the factors listed in R14-2-1607(I)
pertain only to recovery mechanisms and not to the recoverability of stranded
costs. APS wants to remove R14-2-1607(I)(8) pertaining to the period over which
stranded cost charges may be recovered. Further, APS desires prompt review of
Stranded Cost recovery proposals.
TEP states that a specific time period over which stranded costs are
computed should not be ordered. The proposed rule does not specify a standard
time period, but leaves this to be determined on a case by base basis.
AEPCO and other cooperatives propose deleting some of the factors in
R14-2-1607(I) because they believe that stranded cost recovery is required by
law. Trico also indicates that some of these should not be considered because,
in Trico's view, all stranded costs are recoverable.
Staff believes that changes proposed by APS to R14-2-1607(I) are
unnecessary. As written, R14-2-1607(I) states that the list of factors is to be
considered by the Commission in determining mechanisms and charges for recovery
of stranded cost, but not the magnitude of stranded cost. The Commission cannot
consider stranded cost recovery mechanisms and charges in a vacuum as proposed
by APS. Staff further believes that the Commission will give prompt attention to
requests for stranded cost recovery. However, not knowing the nature of the
utilities' filings or the nature of other parties' analyses, no specific time
limit should be imposed now. The inclusion of R14-2-
<PAGE>
1607(I)(8) is necessary to indicate that a stranded cost recovery charge is for
a fixed time period to be determined by the Commission after having reviewed
data provided by utilities and other parties. Stranded cost recovery for an
indefinite time period is precluded.
Staff disagrees with the cooperatives and Trico; the effects of
stranded cost recovery on competition and on consumers are important factors in
stranded cost recovery mechanisms and should not be ignored by the Commission.
Staff believes that the Commission must consider all the factors listed so as to
take into account impacts of stranded cost recovery mechanisms on consumers and
on the market in general.
Analysis: We believe that the Rule is clear in that R14-2-1607(I)
identifies factors to be considered in setting the mechanisms and charges for
Stranded Cost recovery, not for the issue of the magnitude of Stranded Cost.
Further, as regards R14-2-1607(I)(8), utilities will be free to propose specific
methods for stranded cost recovery that are compatible with their circumstances.
Further, the factors identified in the Rule are necessary in order for the
Commission to determine the appropriate mechanisms for Stranded Cost recovery.
Resolution: No amendment to R14-2-1607(I) is necessary.
Issue: R14-2-1607(J) allows Stranded Cost recovery only from those
customers participating in the competitive market.
RUCO indicates that stranded costs should be recovered from all
customers. TEP argues that consumers who self generate should pay for stranded
costs.
Staff notes that costs are only stranded when competitive market prices
are below traditionally regulated rates. Consumers served in non-competitive
markets will pay for all prudently incurred costs in their regulated rates and
so, in that case, there is no stranded cost. Thus, RUCO's proposed objectives
are already incorporated in the rule. As for TEP's recommendation, self
generation has been available to consumers for years and no stranded cost
recovery has been imposed on such customers.
Analysis: The Commission agrees that consumers who will not be
participating in the competitive market will be paying for Stranded Costs
through the regulated Standard Offer rates. We also agree that there is no
compelling reason to impose Stranded Cost responsibility on self
<PAGE>
generators under these Rules, when none has been imposed in the past.
Resolution: No amendment to R14-2-1607(J) is necessary.
F. R14-2-1609: Solar Portfolio Standard
Issue: The Solar Portfolio Standard may not result in increased solar
capacity in Arizona.
APS suggests that the solar portfolio standard might not result in any
increased solar capacity in Arizona. Staff agrees that there is a possibility
that no new solar capacity will be built in Arizona, but notes that the purpose
of the standard is to promote solar power regardless of the location of
generation facilities. Staff believes that economics favor Arizona locations for
new solar facilities serving Arizona consumers. Because out-of-state solar
resources would need to acquire transmission rights to transmit solar
electricity into Arizona for use by the competitive customers in the phased-in
competition program, out-of-state resources would probably be more expensive. In
addition, since Arizona has the most plentiful supply of sunshine resources in
the nation, it is unlikely that an Electricity Service Provider would want to
build a solar plant elsewhere. The double credit provision for early solar
electricity generation is designed to encourage the installation of the solar
facilities in Arizona.
Analysis: While the Rule does not specifically require the building of
solar resource in Arizona, we believe that the prevailing environmental and
economic conditions will result in much of the solar requirement being met by
Arizona resources.
Resolution: No amendment to R14-2-1609 is necessary.
Issue: The Rules may not require that solar resources be used to serve
Arizona customers.
APS suggests that the proposed rules do not require that the solar
resources "even be used to serve Arizona consumers." Staff notes that
R14-2-1609(A) defines the solar portfolio standard as a percentage "of the total
retail energy sold competitively..." The obvious reference is for electricity
sold competitively in Arizona to Arizona consumers as part of the phased-in
competition program. However, if there is a need for clarification, Staff would
not object to the addition of the phrase "to Arizona consumers" after the phrase
"sold competitively."
Analysis: These rules pertain to the provision of electric services in
the State of Arizona.
<PAGE>
While Staff's proposed language may be useful, it is not necessary, in that all
electricity sold competitively under these Rules is sold in Arizona.
Resolution: No amendment to R14-2-1609(A) is necessary.
Issue: APS' alternative solar proposal.
APS made an alternative proposal in its September 12, 1996 comments
that it claims would be far less costly, guarantee between 25 and 50 MW of new
solar generation, and not serve as a market barrier. The proposal would have the
Commission levy a fixed fee on all kWh delivered to customers in Arizona
starting in June 1997. The money would be placed in an interest bearing account
and, starting in 1998, the money would be used to "buy down" the uneconomic
portion of the cost of newly installed solar systems in Arizona. The money would
be disbursed on a competitive-bid basis.
Staff does not believe that APS' proposal will accomplish what APS
claims it will. The proposal appears to contemplate the need for the
establishment of a new bureaucracy to collect fees, determine winning bidders,
oversee solar plant construction and start-up. At a time where competition
should be encouraging the reduction of bureaucracies in the regulation of
electric service and the provision of those services, this proposal would seem
to offer just the opposite.
Analysis: The APS proposal, contrary to APS' assertions, would not
guarantee that any solar facilities are built. It would offer an opportunity,
certain incentives, and a favorable environment for solar projects, but
certainly no guarantees. The Staff proposal, in contrast, offers a good chance
that solar projects will be built because of the potentially high penalties for
not meeting the standard. Further, we are not convinced that APS' proposal will
be less costly. The costs of buying and installing solar should be about the
same. In fact, there is a distinct possibility, under the solar portfolio
standard, that utilities or other large electricity suppliers, by buying solar
equipment in large volume purchases, will be able to obtain significant price
reductions from solar manufacturers anxious for increased market share.
Resolution: No amendment to R14-2-1609 is necessary.
Issue: The Solar Portfolio Standard is too expensive compared to wind
power.
RUCO is concerned about the cost of the solar portfolio standard. RUCO
states that wind
<PAGE>
power would be cheaper than solar power.
Staff notes that the purpose of the solar portfolio standard, however,
is to promote a specific type of renewable resource and not renewables in
general, some of which are already cost effective in a wide range of
applications. Further, Arizona has mostly Class 3 wind regions, which are not
currently cost effective resources, and Arizona wind resources are best in the
winter when their value is less than it would be during peak summer demand.
Analysis: The Solar Portfolio Standard as written serves properly
serves its intended purpose of encouraging the development of solar resources.
Solar resources more accurately match the electric demand needs of Arizona
consumers than do wind resources, improving their cost effectiveness.
Resolution: No amendment to R14-2-1609 is necessary.
Issue: R14-2-1609 should be deleted to make the Rules fuel and resource
neutral.
The Center for Energy and Economic Development (CEED) believes that
restructuring should be fuel and resource neutral. Staff disagrees that
restructuring should be resource and fuel neutral. The Commission, over the last
few years has encouraged the utilities it regulates to diversify their energy
portfolios to include renewable energy resources
Analysis: Diversification of resource portfolios benefits Arizona. We
believe it particularly appropriate to encourage solar because of its natural
advantages in the state.
Resolution: No amendment to R14-2-1609 is necessary.
Issue: The Solar Portfolio Standard is too modest.
The Environmental Group is concerned that the solar portfolio
standard's percentage rate is too low. The group quotes two National Renewable
Energy Laboratory ("NREL") reports that claim that solar thermal technologies
produce electricity today at 10.5 cents/kWh and that the current cost of
photovoltaic generated electricity is 21.8 cents/kWh. This is in contrast to
Staff's estimates of 30 cents/kWh. The group therefore suggests that section
R14-2-1609(B)(2) be modified to show that only an increase in the solar
portfolio be allowed when the standard is re-evaluated in 2001.
Staff disagrees with the proposal to change the solar portfolio
standard. There is insufficient information at this time to set future policy,
and R14-2-1609(B) should not be altered in the absence
<PAGE>
of this information. Staff agrees that NREL's estimated solar electricity cost
numbers are probably appropriate for large solar installations. However, since
the early solar portfolio projects will be modest in size, Staff feels that it
is important to be conservative in estimates. This has resulted in the modest
and conservative 1/2 of 1 percent initial solar portfolio standard. Staff agrees
with the Environmental Group and NREL that solar costs in the 1999-2003 time
frame will be significantly lower than current costs. If this cost reduction
occurs as projected, there will be a natural tendency to increase the solar
standard in 2001. If not, it may be appropriate to freeze the standard at 1/2 of
1 percent for a few years.
Analysis: While the Environmental Group may be right in regard to the
information it has provided from NREL, we believe it is too premature to
increase the standard beyond the levels set forth in the Rule.
Resolution: No amendment to R14-2-1609(B) is necessary.
Issue: Several commentators at the Public Comment session encouraged
the Commission to expand the Solar Portfolio Standard to include solar water
heaters and other solar demand reduction technologies. It was argued that many
of these technologies are cost effective and reliable methods to reduce the
demand for electricity from the grid.
Analysis: While the suggestions of these commentators has some merit,
we do not believe it appropriate to modify the Solar Portfolio Standard at this
time. As noted earlier, the purpose of the Solar Portfolio Standard is to
promote a specific type of renewable resource.
Resolution: No amendment to R14-2-1609 is necessary.
G. R14-2-1611: In-State Reciprocity
Issue: R14-2-1611 precludes Salt River Project and other
quasi-governmental entities and municipalities from participating in the
competitive marketplace.
SRP states that the Rules do not give all Arizona customers the right
to choose their Electric Service Provider. SRP further states that the Rules=
proposed regulation of political subdivisions and municipal corporations is
unconstitutional. SRP expressed concern about having to obtain consent from the
Affected Utilities. A concern is that some utilities will bar SRP's entrance by
refusing to agree to allow SRP to participate. Consequently, SRP proposed the
use of
<PAGE>
intergovernmental agreements to allow it to participate in competition under
this Article.
The Irrigation and Electrical Districts' Association of Arizona (IEDA)
suggests current wording in the Rules may embroil jurisdictional fights and
proposed rewording R14-2-1611 subsection D. The rewording would allow
non-jurisdictional utilities to voluntarily file unbundled and standard offer
service tariffs and to voluntarily open its service territory to competing
sellers. These filings would serve as authorization for such service providers
to utilize the Commission's rules concerning complaints related to their
participation in the competitive market.
Staff believes that the rules as proposed do not make provisions for
competition in the service territories of utilities not regulated by the
Commission. The rules do provide a framework for implementing competition in the
service territories of utilities regulated by the Commission and several means
by which nonjurisdictional utilities may participate. Staff further notes that
the Rules do not propose regulation of nonjurisdictional utilities in their
service territories. They apply to affected utilities and energy service
providers authorized to do business in currently regulated service areas. The
rules also explicitly state that SRP would not be considered an Affected Utility
unless existing law changes (R14-2-1601(1)).
Nordic Power is concerned that the intergovernmental agreement
recommended by SRP may allow major utilities to carve out service territories if
customers and competitive power service providers are left out of the process.
Staff believes SRP's proposed use of intergovernmental agreements has
merit and may be a means of establishing adequate enforcement of
nondiscriminatory rates. The concerns of other utilities over level playing
field issues must be considered in any resolution of SRP's status. Further,
there must be an objective party who can resolve disputes over whether electric
service providers have fair, nondiscriminatory access to SRP's distribution
system. If the Commission does not have this authority, some other party must
take on this responsibility; other electric service providers may also want to
be involved in the creation of this independent party.
Staff agrees with Nordic Power that other parties should have the
opportunity to provide input into intergovernmental agreements and expects that
if such an agreement is being entertained, the Commission will seek that input.
<PAGE>
Analysis: SRP's status as the second largest electric provider in the
state, coupled with its status as a political subdivision of Arizona, has vexed
the Commission in the formation of Rules designed to allow competition to
benefit all electric consumers in the state. SRP's and IEDA's proposals have
merit.
Resolution: R14-2-1611 should be amended as follows:
Initially, based on SRP's arguments and the analysis set forth above,
it is clear that R14-2-1611(C) is simply unnecessary. Therefore, R14-2-1611(C)
as previously proposed is deleted. The remaining subsections have been
relettered to conform.
Therefore. R14-2-1611D has been relettered as (C) and amended to read:
C. An Arizona electric utility, not subject to the jurisdiction
of the Commission, may submit a statement to the Commission
that it voluntarily opens its service territory for competing
sellers in a manner similar to the provisions of this Article.
Such statement shall be accompanied by the electric utility's
nondiscriminatory Standard Offer tariff, electric supply
tariffs, Unbundled Services rates, Stranded Cost charges,
System Benefits charges, Distribution Services charges and any
other applicable tariffs and policies for services the
electric utility offers, for which these Rules otherwise
require compliance by Affected Utilities or Electric Service
Providers. Such filings shall serve as authorization for such
electric utility to utilize the Commission's Rules of Practice
and Procedure and other applicable Rules concerning any
complaint that an Affected Utility or Electric Service
Provider is violating any provision of this Article or is
otherwise discriminating against the filing electric utility
or failing to provide just and reasonable rates in tariffs
filed under this Article.
R14-2-1611D has been added to read:
E. If an electric utility is an Arizona political subdivision or
municipal corporation, then the existing service territory of
such electric utility shall be deemed open to competition if
the political subdivision or municipality has entered into an
intergovernmental agreement with the Commission that
establishes nondiscriminatory terms and conditions for
Distribution Services and other Unbundled Services, provides a
procedure for complaints arising therefrom, and provides for
reciprocity with Affected Utilities. The Commission shall
conduct a hearing to consider any such intergovernmental
agreement.
In addition, several other conforming changes are necessary. First,
because the adopted changes to the rules make it redundant, the last sentence of
R14-2-1601.1 should be deleted. The deleted sentence stated that "In the event
that modifications are made to existing law that would allow the application of
this Article to the Salt River Project Agricultural Improvement and Power
District ("SRP"), then Affected Utilities shall also include SRP." Also, the
second sentence of R14-2-1603(B) should be amended to read: "Such Certificates
shall be restricted to geographical areas served by the Affected Utilities as of
the date this Article is adopted and to service areas added under the provisions
of R14-2-1611."
<PAGE>
APPENDIX C
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ECONOMIC IMPACT STATEMENT
PROPOSED RULE --RETAIL ELECTRIC COMPETITION
R14-2-1601 et seq.
A. Summary of economic, small business and consumer impacts.
1. Identification of the proposed rulemaking.
The proposed rule (Article 16) provides procedures and schedules for
introducing competition into the provision of electric service.
2. Brief summary of the economic, small business and consumer impact
statement.
Increased competition in the electric industry is expected to produce
several benefits:
(1) Consumer choice among energy suppliers.
(2) Greater customization of energy services, especially for
larger consumers, regarding time of use rates, interruptible
service, contract duration, pricing arrangements, risk
management, and so on.
(3) Greater innovation in technology and greater applications
of technological innovations, especially in distributed
generation, as a result of incentives in the competitive
marketplace.
(4) Greater application of energy efficiency measures as
energy service companies offer packages of electric energy,
demand side management measures, and possibly other services
such as building maintenance services.
(5) Lower prices for electricity due to competitive pressures
and to technological, marketing, and organizational
innovations that would not occur as rapidly, if at all, in a
regulated monopoly environment.
The costs of participating in a competitive market generally involve
risk management and information. Examples of possible costs include: the costs
of searching out and evaluating alternatives; additional record keeping and
billing costs associated with deliveries of electricity from
<PAGE>
suppliers; additional costs of executing, monitoring, and enforcing contracts;
and additional costs of maintaining power quality and transmission and
generation system reliability.
A competitive market in electricity will benefit small businesses
because it increases their choices and tends to lower prices of electric
service. However, small businesses must be informed about their choices. The
rule indicates that the Commission may undertake educational activities to lower
the costs of participating in the competitive market.
Probable costs to the Commission include costs associated with new
tasks, such as reviewing applications for competitive Certificates of
Convenience and Necessity, and engaging in evidentiary hearings for stranded
investment and unbundled tariff filings. However, Commission review of tariff
filings should be reduced eventually and costly rate cases will be avoided for
competitive services.
Employment opportunities could be enhanced as new energy related
companies move into the area or as a result of new business start-ups. However,
employees at public utilities could lose their positions through cost cutting
measures as the utilities strive to become more cost competitive.
Implementation of the proposed rule should result in no increased costs
to political subdivisions. As an end user of competitive electricity services, a
political subdivision may benefit from greater choices of service options and
affordable rates. Those political subdivisions which have their own municipal
electric utilities may feel pressure to allow competitive electric service.
The restructuring policy proposed is preferred to alternatives
considered because it: minimizes administrative complexity; requires minimal
information and planning needs a priori; is relatively flexible so that policy
could be adjusted in mid-course; uses existing institutions; minimizes utility
organizational disruption; allows buyers and sellers to enter the market freely;
limits market power of incumbent utilities; and minimizes public confusion.
3. The name and address of agency employees to contact regarding this
statement.
Gary Yaquinto or Bradford Borman at the Arizona Corporation Commission,
1200 West Washington Street, Phoenix, Arizona 85007.
<PAGE>
B. Economic, small business and consumer impact statement.
1. Identification of the proposed rulemaking.
The proposed rule (Article 16) provides procedures and schedules for
introducing competition into the provision of electric service.
2. Persons who will be directly affected by, bear the costs of, or
directly benefit from the proposed rulemaking.
a. The public at large who are consumers of electricity
throughout the State of Arizona.
b. Furnishers of electricity (serving Arizona and elsewhere),
including Investor Owned Utilities, consumer owned
utilities/power authorities, self generators, and Independent
Power Producers.
c. Power aggregators/marketers.
d. Industry organizations (e.g., Regional Transmission Groups).
e. Transmission utilities.
f. Employees of furnishers of electricity.
g. Suppliers to furnishers of electricity.
h. Investors in Investor Owned Utilities and Independent Power
Producers and holders of bonds of consumer owned utilities and
cooperatives.
i. Financial Organizations.
j. Government agencies such as the Arizona Corporation
Commission, siting authorities, Federal agencies (including
the Federal Energy Regulatory Commission), and consumer
advocates such as the Residential Utility Consumers
Organization.
3. Cost-benefit analysis.
a. Probable costs and benefits to the implementing agency and
other agencies directly affected by the implementation and
enforcement of the proposed rulemaking.
Probable costs to the Commission include costs associated with new
tasks, such as reviewing applications for competitive Certificates of
Convenience and Necessity, and engaging in evidentiary hearings for stranded
costs, standard offer service, and unbundled tariff filings.
<PAGE>
The proposed rule allows competitive power and energy suppliers to
change rates by applying for streamlined rate treatment. Filing requirements for
rate increases may be reduced. Thus, Commission review of tariff filings should
be reduced eventually and costly rate cases will be avoided for competitive
services.
b. Probable costs and benefits to a political subdivision of this state
directly affected by the implementation and enforcement of the proposed
rulemaking.
Implementation of the proposed rules should result in no increased
costs to political subdivisions relative to cost changes that may otherwise
occur. As an end user of competitive electricity services, a political
subdivision may benefit from greater choices of service options and affordable
rates. Those political subdivisions which have their own municipal electric
utilities may feel pressure to allow competitive electric service.
c. Probable costs and benefits to businesses directly affected by
the proposed rulemaking, including any anticipated effect on
the revenues or payroll expenditure of employers who are
subject to the proposed rulemaking.
Greater efficiency under competition should arise from lower cost
electricity generation, efficient operation and maintenance, development of low
cost new resources, and greater stimuli to innovation in electric generation
technology. These benefits are achievable while limiting adverse financial
impacts of competition on incumbent utilities; maintaining transmission and
generation system reliability; countering the market power of vertically
integrated utilities; and promoting solar resources.
Possible costs include: additional record keeping and billing costs
associated with deliveries of electricity; transmission access costs; costs of
interconnection arrangements such as disconnection switches to ensure that
interruptible consumers are properly interrupted; additional costs of
maintaining power quality and transmission and generation system reliability;
additional costs of scheduling power deliveries to meet contract requirements;
additional costs of executing, monitoring, and enforcing contracts; and costs of
complying with legal requirements.
<PAGE>
4. Probable impacts on private and public employment in business,
agencies and political subdivisions of this state directly
affected by the proposed rulemaking.
Employment opportunities could be enhanced as new energy related
companies move into the area or as a result of new business start-ups. However,
employees at public utilities could lose their positions through cost cutting
measures as the utilities strive to become more cost competitive.
5. Probable impact of the proposed rulemaking on small business.
a. Identification of the small businesses subject to the proposed
rulemaking. Businesses subject to the proposed rulemaking are
furnishers of electricity (serving Arizona and elsewhere),
including Investor Owned Utilities, consumer owned
utilities/power authorities, self generators, Independent
Power Producers, and power aggregators/marketers. Some of
these businesses are small, but some are also large regional,
national, or international firms.
b. Administrative and other costs required for compliance with
the proposed rulemaking.
Administrative costs to providers of competitive retail electric
service would include costs associated with filing requests with the Commission
for approval of Competitive Certificates of Convenience and Necessity; filing
unbundled tariffs for approval; filing semi-annual reports to inform the
Commission about the progress of competition during the phase-in period and
annual reports when competition is fully established; and requests for stranded
cost recovery. Sellers may be required to provide notification and informational
materials to consumers about competition and their choices.
c. A description of the methods that the agency may use to reduce
the impact on small businesses.
A competitive market in electricity will benefit small businesses
because it increases their choices and tends to lower prices of electric
service. However, small businesses must be informed about their choices. The
rule indicates that the Commission may undertake educational activities to lower
the costs of participating in the competitive market.
<PAGE>
A possible alternative to reduce the impact on small businesses is to
reduce the frequency of filings during the phase-in period. As a consequence,
however, the Commission may not become aware of implementation problems quickly
enough to offer timely solutions.
Another alternative would be to allow competitive service providers to
engage in market competition by simply registering the company with the
Commission rather than requiring the company to apply for a Certificate of
Convenience and Necessity. However, the outcome of this alternative may be
undesirable if an electric service provider does not have the technical or
financial capability of providing reliable energy services, and if the industry
becomes more prone to companies that engage in fraudulent activities.
A third alternative is to dispense with tariff filings. However, the
Commission could not fulfill its Constitutional responsibilities and consumers
would have less information about businesses who supply electric service.
d. The probable cost and benefit to private persons and consumers
who are directly affected by the proposed rulemaking.
Costs of participating in the market generally involve information and
risk management. Possible costs include: the costs of searching out and
evaluating alternatives; the cost of interruptions, whether the power was
intended to be interruptible or firm; costs of backup and maintenance service
provided by a utility or another party to deal with forced or scheduled outages
at the supplier's generation plant or transmission lines; and additional costs
of executing, monitoring, and enforcing contracts. Also, consumers of
competitive energy services may be assessed a stranded investment charge for
sunk costs incurred by the utility from which they previously received service.
The proposed rule will benefit Arizona consumers by creating consumer
choice among energy suppliers; customizing energy services to consumer needs;
stimulating innovation in technology; encouraging energy efficiency; and
lowering prices relative to regulated rates. Important public programs, such as
low income programs, will be protected and consumers who do not participate in
competition will be shielded from adverse effects during the early phases via
Commission-approved standard offer service from incumbent utilities.
<PAGE>
6. A statement of the probable effect on state revenues.
The proposed rule could reduce state revenues received from public
utilities as rates and, therefore, utility revenues are reduced. However, to the
degree that consumers respond to lower prices by increasing their demand for
electricity, the reduction in utility revenues would be offset by additional
revenues from increased electricity demand.
7. A description of any less intrusive or less costly alternative
methods of achieving the purpose of the proposed rulemaking.
A Working Group on Retail Electric Competition met in 1995 to discuss
restructuring options, including retail wheeling and maintaining the status quo.
The Working Group was comprised of individuals from utilities, alternative power
providers, consumer groups, and other interested parties. Several restructuring
options were considered: (1) maintaining the status quo, (2) introducing retail
competition and requiring divestiture of utility assets, (3) introducing retail
competition and requiring an exclusive poolco, and (4) introducing retail
competition and allowing bilateral contracts for power supplies (similar to the
proposed rule).
The first alternative is to maintain the status quo, utilizing
traditional cost-plus rate-making, incentive rate-making (e.g., bench-marking
prices, quality and reliability standards), and flexible pricing. No new
institutions would be required and disruptions in utility operations would be
minimized. However, the effectiveness of incentives (if any) and flexible
pricing are unknown. Also, the circumstances which once warranted classifying
utilities as "natural monopolies" are no longer applicable. The economies of
scale of large central station generation plants are not nearly as large as they
once were. Further, regulated monopolies cannot produce prices that are as low
as would occur in a competitive market and regulated monopolies cannot stimulate
technological, marketing, and organizational innovations as would occur in a
competitive market.
A second alternative is to establish retail competition with an
"exclusive poolco," which is an independent system operator that controls all
power transactions. All generators would sell to the neutral system operator and
all purchasers would buy from the system operator. With an exclusive poolco, all
consumers or their agents would know the market price at each hour. In addition,
power would be dispatched in a least cost order, subject to restrictions on
transmission.
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A major disadvantage of an exclusive poolco is that it forces all
transactions to be spot market transactions, thereby increasing the risk to
investors of investing in new power plant capacity without long term contracts
to purchase the output from new plants. Further, with only spot market
transactions, it becomes more difficult to customize contracts to suit the
circumstances of a wide variety of buyers and sellers.
Another disadvantage of retail competition with an exclusive poolco is
the unknown cost to implement the poolco. Also bidders in the poolco may game
their bids, especially if some have an advantage because of their location or
large size relative to the market.
A third option is to introduce retail competition and require utilities
to divest their generation and possibly transmission facilities. The market
would become segmented by function and generation companies would be expected to
operate in a competitive environment. A principal reason for divestiture is that
any incentive for utilities to impede access to their transmission systems to
inhibit competition in generation could be eliminated. In addition, incentives
for efficiency gains could be created by unbundling services into profit
centers. However, the Commission's regulatory authority to require divesture of
utility assets may be questioned and result in a protracted legal dispute.
Further, utilities, utility shareholders, and utility debt holders may strongly
resist divesture. Divestiture could be costly due to expensive debt
re-financing. In addition, inefficiencies could result from the loss of
traditional coordination of generation, transmission, and distribution services.
The restructuring policy proposed is preferred to the alternatives
described above because it: minimizes administrative complexity; requires
minimal information and planning needs a priori; is relatively flexible so that
policy could be adjusted in mid-course; uses existing institutions; minimizes
utility organizational disruption; allows buyers and sellers to enter the market
freely; limits market power of incumbent utilities; and minimizes public
confusion.
The proposed rule was synthesized from comments received from
interested parties on electric industry restructuring and it represents a middle
ground of proposals submitted by utilities, potential energy service
competitors, consumer groups, and others.
C. If for any reason adequate data are not reasonably available to comply with
the requirements of subsection B of this section, the agency shall explain the
limitations of the data
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and the methods that were employed in the attempt to obtain the data and shall
characterize the probable impacts in qualitative terms.
The Commission conducted a series of workshops and task forces to
obtain useful information to assess the costs and benefits of electric industry
competition. It is not possible to quantify future market prices, technological
innovations, organization changes, and the like. Therefore, we have described
impacts in qualitative terms.
Among the information gathering activities were:
* An introductory workshop held on September 7, 1994. One
hundred eighteen representatives from utilities, consumer
organizations, other power suppliers, and others attended the
workshop. The workshop was summarized in a Staff Report dated
October 1994.
* A series of nine working group and task force meetings held
in 1995 which addressed restructuring options, implementation
of the options, and advantages and disadvantages of the
options. Fifty-one groups were represented on task forces
which focused on systems and markets, regulatory issues, and
energy efficiency and environmental issues. Members of the
task forces included representatives from utilities, consumer
organizations, other power suppliers, and others. This work
was summarized in a "Report of the Working Group on Retail
Electric Competition," dated October 5, 1995. The report
contains an extensive bibliography on electric industry
restructuring.
* A request for comments on electric industry restructuring
issued in February 1996. Comments were filed by 31 parties on
June 28, 1996. Commenters included consumer groups, Arizona
utilities, other suppliers, and other parties. Staff prepared
a summary of the comments in July 1996.
* A workshop held on August 12, 1996 to explore and obtain
feedback on a small number of options for introducing retail
electric competition. One hundred thirty workshop participants
included representatives from utilities, consumer
organizations, other power suppliers, and others. Staff
summarized the workshop in
<PAGE>
a report dated August 19, 1996.
* Requests for comments on a draft rule to phase-in retail
electric competition. The requests were sent out on August 28,
1996 and comments were due September 12, 1996. Comments were
provided by a total of 30 utilities, consumer organizations,
other power suppliers, and others.
* A workshop to discuss a revised draft rule held on September
18, 1996. Ninety individuals attended the workshop, including
representatives from utilities, consumer organizations, other
power suppliers, and others.
In addition, to better understand possible impacts of restructuring,
the Commission Staff reviewed activities in other jurisdictions, including: New
Hampshire, Massachusetts, Illinois, Rhode Island, Texas, Alberta, and New York.
