FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended SEPTEMBER 30, 1998
-----------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-4473
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ARIZONA PUBLIC SERVICE COMPANY
------------------------------------------------------
(Exact name of registrant as specified in its charter)
ARIZONA 86-0011170
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 NORTH FIFTH STREET, P.O. BOX 53999, PHOENIX, ARIZONA 85072-3999
- -------------------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (602) 250-1000
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(Former name, former address and former fiscal year,
if changed since last report)
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 the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Number of shares of common stock, $2.50 par value,
outstanding as of November 13, 1998: 71,264,947
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GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
Company - Arizona Public Service Company
EITF - Emerging Issues Task Force
EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity ___ Issues Related to the Applications of FASB Statements
No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises ___ Accounting for the Discontinuation of Application of
FASB Statement No. 71"
FERC - Federal Energy Regulatory Commission
ITC - Investment tax credit
1997 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1997
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
Power Coordination Agreement - 1955 agreement between the Company and Salt River
Project that provides for certain electric system and power sales
SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
SFAS No. 131 - Statement of Financial Accounting Standards No. 131, "Disclosures
about Segments of an Enterprise and Related Information"
SFAS No. 133 - Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities"
Salt River Project - Salt River Project Agricultural Improvement and Power
District
TEP - Tucson Electric Power Company
Territorial Agreement - 1955 agreement between the Company and Salt River
Project that has provided exclusive retail service territories in Arizona as
against each other
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PART I - FINANCIAL INFORMATION
------------------------------
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
------------------------------
(Unaudited)
Three Months
Ended September 30,
-----------------------
1998 1997
--------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES .......................... $ 740,734 $ 632,821
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ....................... 74,112 48,379
Purchased power .................................... 178,587 110,151
--------- ---------
Total ........................................... 252,699 158,530
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES ................ 488,035 474,291
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding
fuel expenses .................................... 110,259 110,102
Depreciation and amortization ...................... 94,284 90,874
Income taxes ....................................... 98,411 92,195
Other taxes ........................................ 30,002 30,228
--------- ---------
Total ........................................... 332,956 323,399
--------- ---------
OPERATING INCOME ..................................... 155,079 150,892
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ........................................ (2,120) 445
Income taxes ....................................... 14,271 14,052
--------- ---------
Total ........................................... 12,151 14,497
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .................... 167,230 165,389
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ......................... 33,906 35,699
Interest on short-term borrowings .................. 2,359 2,163
Debt discount, premium and expense ................. 1,878 1,825
Capitalized interest ............................... (4,106) (3,997)
--------- ---------
Total ........................................... 34,037 35,690
--------- ---------
NET INCOME ........................................... 133,193 129,699
PREFERRED STOCK DIVIDEND REQUIREMENTS ................ 2,347 2,984
--------- ---------
EARNINGS FOR COMMON STOCK ............................ $ 130,846 $ 126,715
========= =========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
------------------------------
(Unaudited)
Nine Months
Ended September 30,
-------------------------
1998 1997
----------- ----------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ........................ $1,562,872 $1,470,593
---------- ----------
FUEL EXPENSES:
Fuel for electric generation ..................... 174,874 155,127
Purchased power .................................. 247,327 188,182
---------- ----------
Total ......................................... 422,201 343,309
---------- ----------
OPERATING REVENUES LESS FUEL EXPENSES .............. 1,140,671 1,127,284
---------- ----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding
fuel expenses................................... 309,388 287,280
Depreciation and amortization .................... 279,097 274,027
Income taxes ..................................... 162,808 164,066
Other taxes ...................................... 89,459 89,874
---------- ----------
Total ......................................... 840,752 815,247
---------- ----------
OPERATING INCOME ................................... 299,919 312,037
---------- ----------
OTHER INCOME (DEDUCTIONS):
Other - net ...................................... (7,035) (2,674)
Income taxes ..................................... 26,214 24,942
---------- ----------
Total ......................................... 19,179 22,268
---------- ----------
INCOME BEFORE INTEREST DEDUCTIONS .................. 319,098 334,305
---------- ----------
INTEREST DEDUCTIONS:
Interest on long-term debt ....................... 103,249 105,390
Interest on short-term borrowings ................ 5,419 7,586
Debt discount, premium and expense ............... 5,745 5,883
Capitalized interest ............................. (12,627) (12,391)
---------- ----------
Total ......................................... 101,786 106,468
---------- ----------
NET INCOME ......................................... 217,312 227,837
PREFERRED STOCK DIVIDEND REQUIREMENTS .............. 7,660 9,805
---------- ----------
EARNINGS FOR COMMON STOCK .......................... $ 209,652 $ 218,032
========== ==========
See Notes to Condensed Financial Statements
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
------------------------------
(Unaudited)
Twelve Months
Ended September 30,
-------------------------
1998 1997
---------- ----------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ........................ $1,970,832 $1,850,047
---------- ----------
FUEL EXPENSES:
Fuel for electric generation ..................... 221,089 217,654
Purchased power .................................. 294,430 207,115
---------- ----------
Total ......................................... 515,519 424,769
---------- ----------
OPERATING REVENUES LESS FUEL EXPENSES .............. 1,455,313 1,425,278
---------- ----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding
fuel expenses................................... 421,542 429,569
Depreciation and amortization .................... 370,741 363,625
Income taxes ..................................... 183,479 170,562
Other taxes ...................................... 119,844 117,084
---------- ----------
Total ......................................... 1,095,606 1,080,840
---------- ----------
OPERATING INCOME ................................... 359,707 344,438
---------- ----------
OTHER INCOME (DEDUCTIONS):
AFUDC - equity ................................... -- (411)
Other - net ...................................... (14,188) (13,188)
Income taxes ..................................... 32,685 40,383
---------- ----------
Total ......................................... 18,497 26,784
---------- ----------
INCOME BEFORE INTEREST DEDUCTIONS .................. 378,204 371,222
---------- ----------
INTEREST DEDUCTIONS:
Interest on long-term debt ....................... 138,790 142,196
Interest on short-term borrowings ................ 7,237 8,811
Debt discount, premium and expense ............... 7,653 7,915
Capitalized interest ............................. (16,444) (14,478)
---------- ----------
Total ......................................... 137,236 144,444
---------- ----------
NET INCOME ......................................... 240,968 226,778
PREFERRED STOCK DIVIDEND REQUIREMENTS .............. 10,658 13,941
---------- ----------
EARNINGS FOR COMMON STOCK .......................... $ 230,310 $ 212,837
========== ==========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
------------------------
ASSETS
(Unaudited)
September 30, December 31,
1998 1997
------------ -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for
future use.................................... $ 7,179,571 $ 7,009,059
Less accumulated depreciation and amortization ... 2,759,425 2,620,607
----------- -----------
Total ......................................... 4,420,146 4,388,452
Construction work in progress .................... 211,758 237,492
Nuclear fuel, net of amortization ................ 55,771 51,624
----------- -----------
Utility plant - net ........................... 4,687,675 4,677,568
----------- -----------
INVESTMENTS AND OTHER ASSETS ..................... 186,342 164,906
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ........................ 17,687 12,552
Accounts receivable:
Service customers ............................. 238,905 141,022
Other ......................................... 52,349 31,313
Allowance for doubtful accounts ............... (1,414) (1,338)
Accrued utility revenues ......................... 86,153 58,559
Materials and supplies, at average cost .......... 71,896 70,634
Fossil fuel, at average cost ..................... 17,303 9,621
Deferred income taxes ............................ 3,496 3,496
Other ............................................ 27,632 24,529
----------- -----------
Total current assets .......................... 514,007 350,388
----------- -----------
DEFERRED DEBITS:
Regulatory asset for income taxes ................ 414,491 458,369
Rate synchronization cost deferral ............... 317,463 358,871
Unamortized costs of reacquired debt ............. 56,409 63,501
Unamortized debt issue costs ..................... 15,142 15,303
Other ............................................ 260,904 242,236
----------- -----------
Total deferred debits ......................... 1,064,409 1,138,280
----------- -----------
TOTAL ......................................... $ 6,452,433 $ 6,331,142
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
------------------------
LIABILITIES
(Unaudited)
September 30, December 31,
1998 1997
----------- -----------
(Thousands of Dollars)
CAPITALIZATION:
Common stock .................................... $ 178,162 $ 178,162
Additional paid-in capital ...................... 1,143,617 1,142,364
Retained earnings ............................... 610,535 528,798
----------- -----------
Common stock equity .......................... 1,932,314 1,849,324
Non-redeemable preferred stock .................. 123,795 142,051
Redeemable preferred stock ...................... 9,401 29,110
Long-term debt less current maturities .......... 1,871,949 1,953,162
----------- -----------
Total capitalization ......................... 3,937,459 3,973,647
----------- -----------
CURRENT LIABILITIES:
Commercial paper ................................ 115,350 130,750
Current maturities of long-term debt ............ 154,220 104,068
Accounts payable ................................ 170,202 107,423
Accrued taxes ................................... 208,595 85,886
Accrued interest ................................ 26,489 31,660
Customer deposits ............................... 28,841 29,116
Other ........................................... 36,394 19,588
----------- -----------
Total current liabilities .................... 740,091 508,491
----------- -----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ........................... 1,291,258 1,345,177
Deferred investment tax credit .................. 36,724 60,093
Unamortized gain - sale of utility plant ........ 78,931 82,363
Customer advances for construction .............. 29,489 29,294
Other ........................................... 338,481 332,077
----------- -----------
Total deferred credits and other ............. 1,774,883 1,849,004
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 5 and 8)
TOTAL ........................................ $ 6,452,433 $ 6,331,142
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
----------------------------------
(Unaudited)
Nine Months
Ended September 30,
----------------------
1998 1997
--------- ---------
(Thousands of Dollars)
Cash Flows from Operating Activities:
Net Income ......................................... $ 217,312 $ 227,837
Items not requiring cash:
Depreciation and amortization .................... 279,097 274,027
Nuclear fuel amortization ........................ 24,991 24,077
Deferred income taxes - net ...................... (47,749) (58,675)
Deferred investment tax credit - net ............. (23,369) (24,091)
Changes in certain current assets and liabilities:
Accounts receivable - net ........................ (118,843) (84,769)
Accrued utility revenues ......................... (27,594) (26,597)
Materials, supplies and fossil fuel .............. (8,944) 2,077
Other current assets ............................. (3,103) (4,541)
Accounts payable ................................. 61,611 23,270
Accrued taxes .................................... 122,709 93,215
Accrued interest ................................. (5,171) (13,279)
Other current liabilities ........................ 16,799 12,171
Other - net ........................................ (20,778) 32,244
--------- ---------
Net cash flow provided by operating activities ....... 466,968 476,966
--------- ---------
Cash Flows from Investing Activities:
Capital expenditures ............................... (221,904) (229,608)
Capitalized interest ............................... (12,627) (12,391)
Other .............................................. (5,872) (16,798)
--------- ---------
Net cash flow used for investing activities .......... (240,403) (258,797)
--------- ---------
Cash Flows from Financing Activities:
Long-term debt ..................................... 109,375 109,906
Short-term borrowings - net ........................ (15,400) 100,850
Dividends paid on common stock ..................... (127,500) (127,500)
Dividends paid on preferred stock .................. (8,070) (10,334)
Repayment of preferred stock ....................... (37,585) (46,511)
Repayment and reacquisition of long-term debt ...... (142,250) (222,725)
--------- ---------
Net cash flow used for financing activities .... (221,430) (196,314)
--------- ---------
Net increase in cash and cash equivalents ............ 5,135 21,855
Cash and cash equivalents at beginning of period ..... 12,552 12,521
--------- ---------
Cash and cash equivalents at end of period ........... $ 17,687 $ 34,376
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........ $ 100,929 $ 114,070
Income taxes ..................................... $ 115,585 $ 161,228
See Notes to Condensed Financial Statements.
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-8-
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. In the opinion of the Company, the accompanying unaudited condensed financial
statements contain all adjustments (consisting of normal recurring accruals)
necessary to present fairly the financial position of the Company as of
September 30, 1998, the results of operations for the three months, nine months
and twelve months ended September 30, 1998 and 1997, and the cash flows for the
nine months ended September 30, 1998 and 1997. It is suggested that these
condensed financial statements and notes to condensed financial statements be
read in conjunction with the financial statements and notes to financial
statements included in the 1997 10-K. Certain prior year balances have been
restated to conform to the current year presentation.
2. The Company's operations are subject to seasonal fluctuations, with
variations in energy usage by customers occurring from season to season and from
month to month within a season, primarily as a result of changing weather
conditions. For this and other reasons, the results of operations for interim
periods are not necessarily indicative of the results to be expected for the
full year.
3. All the outstanding shares of common stock of the Company are owned by
Pinnacle West.
4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
changes in capitalization for the nine months ended September 30, 1998.
5. Regulatory Matters ___ Electric Industry Restructuring
STATE
The following is a description of regulatory and legislative developments
related to implementation of retail electric competition beginning with the ACC
rules adopted in December 1996 through the proposed settlement agreement in
November 1998.
ACC RULES. In December 1996, the ACC adopted rules that provide a framework for
the introduction of retail electric competition in Arizona. On August 5, 1998,
the ACC adopted amendments to the rules. The ACC rules, as amended, include the
following major provisions:
o The rules apply to virtually all of the Arizona electric utilities
regulated by the ACC, including the Company.
o The rules require each affected utility, including the Company, to make
available at least 20% of its 1995 system retail peak demand for
competitive generation supply to all customer classes beginning January
1, 1999, and 100% beginning January 1, 2001.
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o All affected utility customers with single premise loads of one
megawatt or greater will be eligible for competitive electric services
beginning January 1, 1999, until the 20% level described in the
preceding paragraph is met. Until the 20% level is met, affected
utility customers with single premise loads of forty kilowatts or
greater will be able to aggregate into a combined load of one megawatt
or greater to be eligible for competitive electric services beginning
January 1, 1999.
o Prior to January 1, 2001, residential customers will have access to
competitive services through a quarterly phase-in of one-half percent
of residential customers per quarter beginning January 1, 1999.
o Electric service providers that obtain Certificates of Convenience and
Necessity (CC&Ns) from the ACC will be allowed to supply, market,
and/or broker specified electric services at retail. These services
include electric generation, but exclude electric transmission and
distribution.
o As required by the rules, in February 1998 the Company filed with the
ACC proposed tariffs for unbundled service (electric service elements
provided and priced separately). The ACC has not issued a decision in
this matter.
o The rules establish that the ACC shall allow a reasonable opportunity
for the recovery of unmitigated stranded costs. See "Stranded Costs"
below. Affected utilities are expected to take reasonable,
cost-effective steps to mitigate stranded costs.
o Absent a waiver from the ACC, each affected utility must separate
itself from all competitive generation assets and services prior to
January 1, 2001. The separation must be either to an unaffiliated party
or to a separate corporate affiliate or affiliates.
o Beginning January 1, 1999, each affected utility will be prohibited
from providing certain competitive electric services, except through a
separate affiliate.
o The rules contain affiliate transaction rules generally prohibiting an
affected utility and its competitive electric affiliates from sharing
personnel, office space, equipment, services, and systems, except to
the extent appropriate to perform certain permissible shared corporate
support functions. No later than December 31, 1998, each affected
utility must file a compliance plan with the ACC demonstrating its
compliance with the affiliate transaction rules.
In accordance with the rules, on September 15, 1998, the Company filed a report
detailing possible mechanisms to provide certain non-rate benefits and a
possible extension of the 1996 regulatory agreement to all standard offer
customers and a proposed plan for phase-in implementation of 3,500 residential
customers per quarter
<PAGE>
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on a first come, first served basis.
The amended rules became effective on an emergency basis upon their filing with
the Secretary of State on August 10, 1998. The ACC held hearings on the amended
rules in October 1998 and must complete the process of adopting the amended
rules on a permanent basis within 180 days of the Secretary of State filing. The
Company anticipates the completion of this process by year-end 1998 or early
1999.
The Company believes that certain provisions of the 1996 ACC rules and the
amended rules are deficient. In February 1997, a lawsuit was filed by the
Company to protect its legal rights regarding the 1996 rules. That lawsuit is
pending but two related cases filed by other utilities have been partially
decided in a manner adverse to those utilities' positions. In October 1998, the
Company also filed a lawsuit to protect its legal rights regarding the amended
rules.
STRANDED COSTS. In February 1998, the ACC completed a formal, generic hearing on
stranded cost determination and recovery. On June 22, 1998, the ACC issued an
order in this matter. The order allows an affected utility, such as the Company,
to choose between two options for the recovery of its stranded costs. Under the
first option, an affected utility that chooses to divest its generating assets
must file a divestiture plan for ACC approval no later than October 1, 1998, and
such divestiture must be completed by January 1, 2001, after which the affected
utility would be permitted to collect 100 percent of its stranded costs,
including a return on the unamortized balance, over a ten-year period. Under the
second option (referred to by the ACC as the "Transition Revenues Methodology"),
an affected utility would be provided sufficient revenues necessary to maintain
financial integrity for a period of ten years or the ACC would "otherwise
provide an allocation of stranded cost responsibilities and risks between
ratepayers and shareholders as is determined to be in the public interest." The
order also states an intent that the various recovery options "will provide the
affected utilities sufficient revenues to enable them to recover appropriate
regulatory assets." In accordance with the order, on August 21, 1998 the Company
filed with the ACC the Transition Revenues Methodology as its choice of options
for stranded cost recovery and a related implementation plan relating to its
chosen option. The Company does not intend to divest its generating assets
except to an affiliated party. The Company believes that certain provisions of
the stranded cost order are deficient and in August 1998 the Company filed two
lawsuits to protect its legal rights relating to the order. Based on various
assumptions, estimates and methodologies, the Company estimates its recoverable
stranded costs (excluding regulatory assets which have already been addressed in
the 1996 regulatory agreement with the ACC) to be $533 million, assuming a
measurement period 1999 through 2004. The Company cannot accurately predict the
outcome of this matter.
PROPOSED SETTLEMENT AGREEMENT. On November 4, 1998, the Company and the ACC
Staff entered into a proposed settlement agreement related to the implementation
of retail electric competition. In connection with the settlement agreement, the
Company and TEP entered into a memorandum of understanding for the exchange of
certain
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assets. The following are the major provisions of each agreement, both of which
are attached as exhibits to this Form 10-Q and incorporated herein by reference:
PROPOSED SETTLEMENT AGREEMENT WITH ACC STAFF
o The Company will reduce its prices by a total of at least 4% in the
years 1999 through 2002. Price reductions in 2001 and 2002 will apply
only to the Company's residential customers who purchase all their
electric services from the Company.
o There will be a moratorium on filing for retail rate changes before
January 1, 2003, except for the price reductions described above and
certain other limited circumstances.
o In addition to the cost-saving incentive mechanism, the rate filing
moratorium and full recovery of regulatory assets, certain other
aspects of the 1996 regulatory settlement are extended through 2002.
See Note 6 below for additional information on the 1996 regulatory
agreement.
o The Company will be permitted to defer for later recovery prudent and
reasonable costs of complying with the amended ACC rules, systems
benefits costs and solar power costs in excess of the levels included
in current rates.
o The Company will have the ability to recover stranded costs in exchange
for the divestiture of its 345 kV and 500 kV transmission assets to
TEP.
o The Company and TEP entered into a memorandum of understanding for the
exchange of certain assets.
o Upon final adoption and approval of the settlement agreement by the
ACC, the Company will move to dismiss all of its litigation currently
pending against the ACC.
o The Company will establish a separate corporate affiliate for marketing
generation and other competitive electric services before year-end
1998.
o The Company will form a separate corporate affiliate and transfer to it
generating assets by year-end 2002.
MEMORANDUM OF UNDERSTANDING WITH TEP
o The Company and TEP have entered into a memorandum of understanding to
negotiate in good faith to reach a definitive agreement on the exchange
of certain transmission and generation assets.
o The Company would acquire from TEP up to 273 MW of generating capacity
in exchange for the Company's 500 kV and 345 kV transmission lines. The
assets
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will be exchanged at the transmission current book value, which is
approximately $162 million as of July, 1998. If TEP is unable to
transfer 273 MW of generating capacity, the deficiency is to be made up
by a cash payment from TEP to the Company.
o The transaction is expected to close by December 31, 2000.
o The generating assets are TEP's interest in the Navajo Generating
Station and Four Corners Generating Plant.
A hearing date for the ACC's consideration or approval of the settlement
agreement has not yet been set. The memorandum of understanding provides that a
definitive agreement must be entered into within sixty days of a final order on
the settlement agreement by the ACC.
LEGISLATIVE INITIATIVES. An Arizona joint legislative committee studied electric
utility industry restructuring issues in 1996 and 1997. In conjunction with that
study, Arizona legislative counsel prepared memoranda in late 1997 related to
the legal authority of the ACC to deregulate the Arizona electric utility
industry. The memoranda raise a question as to the degree to which the ACC may,
under the Arizona Constitution, deregulate any portion of the electric utility
industry and allow rates to be determined by market forces. This latter issue
(the ability of the ACC to set rates based on the competitive market) has been
subsequently decided by lower courts in favor of the ACC in two unrelated and
two related lawsuits.
In May 1998, a bill was enacted to facilitate implementation of retail electric
competition in the state. The bill includes the following major provisions: (a)
requirements that Arizona's largest government-operated electric utility (Salt
River Project) and, at their option, smaller city electric systems (i) open
their service territories to electric service providers to implement retail
electric generation competition for 20% of each utility's 1995 retail peak
demand by December 31, 1998 and for all retail customers by December 31, 2000;
(ii) decrease rates by at least 10% over a ten-year period beginning as early as
January 1, 1991; (iii) implement procedures and public processes, including
judicial review at the request of either an interested party or the Arizona
Attorney General, for establishing the terms, conditions and pricing of electric
services as well as certain other decisions affecting retail electric
competition, which procedures and processes are comparable to those already
applicable to public service corporations; (b) a description of the factors
which form the basis of consideration by Salt River Project in determining
stranded costs; and (c) a requirement that metering and meter reading services
be provided on a competitive basis during the first two years of competition
only for customers having demands in excess of one megawatt (and that are
eligible for competitive generation services), and thereafter for all customers
receiving competitive electric generation. In addition, the Arizona legislature
will review and make recommendations for the 1999 legislature on certain
competitive issues.
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FEDERAL
The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted
increased competition in the wholesale electric power markets. The Company does
not expect these rules to have a material impact on its financial statements.
Several electric utility reform bills have been introduced during recent
congressional sessions, which as currently written, would allow consumers to
choose their electricity suppliers by 2000 or 2003. These bills, other bills
that are expected to be introduced, and ongoing discussions at the federal level
suggest a wide range of opinion that will need to be narrowed before any
substantial restructuring of the electric utility industry can occur.
REGULATORY ACCOUNTING
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 $0.9 billion at September 30, 1998. In
accordance with the 1996 regulatory agreement, the ACC accelerated the
amortization of substantially all of the Company's regulatory assets to an
eight-year period that began July 1, 1996.
During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) issued EITF 97-4, which requires that SFAS No. 71 be
discontinued no later than when legislation is passed or a rate order is issued
that contains sufficient detail to determine its effect on the portion of the
business being deregulated, which could result in write-downs or write-offs of
physical and/or regulatory assets. Additionally, the EITF determined that
regulatory assets should not be written off if they are to be recovered from a
portion of the entity which continues to apply SFAS No. 71.
Although the ACC has issued rules for transitioning generation services to
competition, there are many unresolved issues. The Company continues to apply
SFAS No. 71 to all of its operations. If rate recovery of regulatory assets is
no longer probable, whether due to competition or regulatory action, the Company
would be required to write off the remaining balance as an extraordinary charge
to expense.
<PAGE>
-14-
GENERAL
Changes in ACC decisions, Arizona and federal legislation, and possible
amendments to the Arizona Constitution may impact the implementation of retail
electric competition in Arizona. Until the details of implementation of
competition, including addressing stranded costs, are determined, the Company
cannot accurately predict the impact of full retail competition on its financial
position, cash flows or results of operation. As competition in the electric
industry continues to evolve, the Company will continue to evaluate strategies
and alternatives that will position the Company to compete in the new regulatory
environment.
6. Regulatory Matters ___ 1996 Regulatory Agreement
In April 1996, the ACC approved a regulatory agreement between the Company and
the ACC Staff. The major provisions of this agreement are:
o An annual rate reduction of approximately $48.5 million ($29 million
after income taxes), or 3.4% on average for all customers except
certain contract customers, effective July 1, 1996.
o Recovery of substantially all of the Company's present regulatory
assets through accelerated amortization over an eight-year period that
began July 1, 1996, increasing annual amortization by approximately
$120 million ($72 million after income taxes).
o A formula for sharing future cost savings between customers and
shareholders (price reduction formula) referencing a return on equity
(as defined) of 11.25%.
o A moratorium on filing for permanent rate changes prior to July 2,
1999, except under the price reduction formula and under certain other
limited circumstances.
o Infusion of $200 million of common equity into the Company by Pinnacle
West, in annual payments of $50 million starting in 1996.
Pursuant to the price reduction formula, in 1997 and in 1998, the ACC approved
retail price decreases of approximately $17.6 million ($10.5 million after
income taxes), or 1.2%, effective July 1, 1997, and approximately $17 million
($10 million after income taxes), or 1.1%, effective July 1, 1998, respectively.
7. Agreement with Salt River Project
On April 25, 1998, the Company and Salt River Project entered into a Memorandum
of Agreement in anticipation of, and to facilitate, the opening of the Arizona
electric industry. The Agreement contains the following major components:
<PAGE>
-15-
o The Company and Salt River Project would amend the Territorial
Agreement to remove any barriers to the provision of competitive
electricity supply and non-distribution services.
o The Company and Salt River Project would amend the Power Coordination
Agreement to lower the price that the Company will pay Salt River
Project for purchased power by approximately $17 million (pretax) in
1999 and by lesser annual amounts through 2006.
o The Company and Salt River Project agreed on certain legislative
positions regarding electric utility restructuring at the state and
federal level.
An ACC docket had previously been established and the ACC held a hearing on
August 6, 1998 so that the ACC could review certain provisions of the Memorandum
of Agreement, as amended, including, whether: (a) the Territorial Agreement
remains in the public interest, (b) the Agreement is a contract in restraint of
trade, and (c) the Agreement will materially lessen the potential for retail
electric competition in Arizona.
The Antitrust Unit of the Arizona Attorney General's Office, which has been
involved in the ongoing regulatory and legislative proceedings regarding the
restructuring of the Arizona electric industry, requested clarification of the
operation of certain of the Agreement's provisions. Pursuant to an Addendum to
Memorandum of Agreement, dated as of May 19, 1998 (the "Addendum"), the Company
and Salt River Project amended and clarified certain provisions of the
Memorandum of Agreement in response to certain issues raised by the Antitrust
Unit. By letter dated May 19, 1998, the Antitrust Unit advised the Company and
Salt River Project that, upon their execution of the Addendum, it would take no
action regarding the language of the Memorandum of Agreement, although it
reserved the right to take action in the future if new information justified
doing so.
8. The Palo Verde participants have insurance for public liability payments
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 $88 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 is approximately $77
million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to
<PAGE>
-16-
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.
9. The Financial Accounting Standards Board issued SFAS No. 131 on "Disclosures
about Segments of an Enterprise and Related Information" which is effective for
fiscal years beginning after December 15, 1997. SFAS No. 131 requires that
public companies report certain information about operating segments in their
financial statements. It also establishes related disclosures about products and
services, geographic areas, and major customers. The Company is currently
evaluating what impact this standard will have on its disclosures.
In June 1998 the Financial Accounting Standards Board issued SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities," which is
effective for the Company in 2000. SFAS No. 133 requires that an entity
recognize all derivatives as either assets or liabilities in the balance sheet
and measure those instruments at fair value. The standard also provides specific
guidance for accounting for derivatives designated as hedging instruments. The
Company is currently evaluating what impact this standard will have on its
financial statements.
<PAGE>
-17-
ARIZONA PUBLIC SERVICE COMPANY
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
OPERATING RESULTS
The following table summarizes the Company's revenues and earnings for
the three-month, nine-month and twelve-month periods ended September 30, 1998
and 1997:
<TABLE>
<CAPTION>
Periods ended September 30
(Unaudited)
(Thousands of Dollars)
Three Months Nine Months Twelve Months
----------------------- ----------------------- -----------------------
1998 1997 1998 1997 1998 1997
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Operating
Revenues $ 740,734 $ 632,821 $1,562,872 $1,470,593 $1,970,832 $1,850,047
Earnings for
Common
Stock $ 130,846 $ 126,715 $ 209,652 $ 218,032 $ 230,310 $ 212,837
</TABLE>
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1998
COMPARED WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1997
Earnings increased $4 million in the three-month comparison primarily
because of customer growth, weather effects, and higher profitability from power
marketing activities, partially offset by higher fuel expenses and a retail
price reduction. See Note 6 of Notes to Condensed Financial Statements for
information on the price reduction.
Operating revenues increased $108 million because of increased power
marketing revenues ($71 million), customer growth ($28 million), and weather
effects ($18 million), partially offset by the price reduction ($6 million) and
other ($3 million). The increase in power marketing revenues was a result of
higher market prices and increased activity. The increase in power marketing
revenues was accompanied by related increases in purchased power.
Fuel expenses increased $94 million primarily because of higher
purchased power prices, increased wholesale and retail sales volumes, and the
effects of two fuel-related settlements in the third quarter of 1997. The
settlements contributed approximately $21 million to 1997 pretax earnings and
are reflected on the income statement as reductions in fuel expense and as other
income.
<PAGE>
-18-
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1998 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1997
Earnings decreased $8 million in the nine-month comparison primarily
because of two fuel-related settlements recorded in 1997, increased operations
and maintenance expenses, the effects of weather, and two retail price
reductions, partially offset by customer growth and higher profitability from
power marketing activities. See Note 6 of Notes to Condensed Financial
Statements for additional information about the price reduction.
The two fuel-related settlements increased the Company's 1997 pretax
earnings by approximately $21 million. The Company's income statement reflects
these settlements as reductions in fuel expense and as other income.
Operations and maintenance expenses increased $22 million related to
impending competition and growth, outages at power plants and other
miscellaneous factors.
Operating revenues increased $92 million because of increased power
marketing revenues ($69 million) and customer growth ($58 million). These
factors were partially offset by the effects of weather ($20 million) and the
price reductions ($15 million). The increase in power marketing revenues was a
result of higher prices and increased activity. The increase in power marketing
revenues was accompanied by related increases in purchased power.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1998
COMPARED WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1997
Earnings increased $17 million in the twelve-month comparison primarily
because of customer growth and higher profitability from power marketing
activities. These positive factors more than offset two retail price reductions
and the effects of weather. See Note 6 of Notes to Condensed Financial
Statements for additional information about the price reductions. The period
ended September 30, 1997 also benefited from two fuel-related settlements and
the recognition of $8 million of income tax benefits associated with capital
loss carryforwards.
Operating revenues increased $121 million because of increased power
marketing revenues ($85 million) and customer growth ($69 million), partially
offset by the price reductions ($18 million), the effects of weather ($10
million), and other ($5 million). The increase in power marketing revenues was a
result of higher prices and increased activity. The increase in power marketing
revenues was accompanied by related increases in purchased power.
<PAGE>
-19-
The two fuel-related settlements increased the Company's 1997 pretax
earnings by approximately $21 million. The Company's income statement reflects
these settlements as reductions in fuel expense and as other income.
Operations and maintenance expenses decreased $8 million because of a
$32 million pretax charge for a voluntary severance program recorded in 1996 and
related savings in 1997, partially offset by higher expenses related to
impending competition and growth, outages at power plants and other
miscellaneous factors.
OTHER INCOME
As part of a 1994 rate settlement with the ACC, the Company accelerated
amortization of substantially all deferred ITCs over a five-year period that
ends on December 31, 1999. The amortization of ITCs is shown on the Company's
income statement as Other Income ___ Income Taxes and decreases annual income
tax expense by approximately $28 million.
LIQUIDITY AND CAPITAL RESOURCES
For the nine months ended September 30, 1998, the Company incurred
approximately $221 million in capital expenditures, which is approximately 68%
of the most recently estimated 1998 capital expenditures. The Company's
projected capital expenditures for the next three years are: 1998, $323 million;
1999, $322 million; and 2000, $317 million, respectively. These amounts include
about $30 - $35 million each year for nuclear fuel expenditures. In addition,
the Company is considering expanding certain of its businesses over the next
several years, which may result in increased expenditures.
The Company's long-term debt and preferred stock redemption
requirements and payment obligations on a capitalized lease for the next three
years are: 1998, $221 million; 1999, $174 million; and 2000, $104 million.
During the nine months ended September 30, 1998, the Company redeemed
approximately $142 million of its long-term debt and approximately $38 million
of its preferred stock with cash from operations and long-term and short-term
debt. On December 1, 1998 the Company will redeem all $37.5 million of its
$1.8125 Cumulative Preferred Stock, Series W. As a result of the 1996 regulatory
agreement (see Note 6 of Notes to Condensed Financial Statements), Pinnacle West
invested $50 million in the Company in 1996 and 1997 and will invest similar
amounts annually in 1998 and 1999.
Although provisions in the Company's bond indenture, articles of
incorporation, and financing orders from the ACC establish maximum amounts of
additional first mortgage bonds and preferred stock that the Company may issue,
management does
<PAGE>
-20-
not expect any of these restrictions to limit the Company's ability to meet its
capital requirements.
YEAR 2000 READINESS DISCLOSURE
As the year 2000 approaches many companies face problems because most
software application and operational programs will not properly recognize
calendar dates beginning with the year 2000. The Company initiated a
comprehensive Company-wide Year 2000 program over a year ago to review and
resolve all Year 2000 issues in critical systems and equipment in a timely
manner to avoid impacting the reliability of electric service to its customers.
This included a Company-wide awareness program of the Year 2000 issue.
The Company has been actively implementing and replacing new systems
and technology since 1995 for reasons unrelated to the year 2000, and these
actions have resulted in substantially all of its major information technology
(IT) systems becoming Year 2000 compliant. The Company has made, and will
continue to make, certain modifications to its computer hardware and software
systems and applications to ensure they are capable of handling changing
business needs, including dates in the year 2000 and thereafter. In addition,
other IT systems and non-IT systems, including embedded technology and real-time
process control systems, are being analyzed for potential modifications. To
date, the Company has inventoried and assessed all IT and non-IT systems and any
renovation, validation and implementation of these systems will be completed by
mid-1999, except for those items that can only be completed during maintenance
outages at Palo Verde, which will be completed for the last unit during the last
half of 1999. The Company has also designated an internal audit/quality review
team that is periodically reviewing the individual Year 2000 projects and their
Year 2000 readiness.
The Company is communicating with its significant suppliers, business
partners, other utilities and large customers to determine the extent to which
it may be affected by these third parties' plans to remediate their own Year
2000 issues in a timely manner. The Company has been interfacing with suppliers
of systems, services and materials in order to assess whether their schedules
for analysis and remediation of Year 2000 issues are timely and to assess their
ability to continue to supply required services and materials. The Company is
also working with the North American Electric Reliability Council (NERC) through
the Western Systems Coordinating Council (WSCC) to develop operational plans for
stable grid operation that will be utilized by the Company and other utilities
in the western United States. However, the Company cannot currently predict the
effect on the Company if the systems of these other companies are not Year 2000
compliant.
The Company currently estimates that it will spend approximately $5
million relating to Year 2000 issues, about half of which has been spent to
date. This does not include expenditures incurred since 1995 to implement and
replace systems for
<PAGE>
-21-
reasons unrelated to the Year 2000, as discussed above. Costs incurred to
address the Year 2000 issue are charged to operating expenses as incurred and
are expected to be funded by available cash balances and cash provided by
operations.
The Company currently expects that its most reasonably likely worst
case Year 2000 scenario would be intermittent loss of power, similar to an
outage during a severe weather disturbance. In this situation the Company would
restore power as soon as possible by, among other things, re-routing power
flows. The Company does not currently expect that this scenario would have a
material effect on its financial position, cash flows or results of operations.
The Company is working to develop its own contingency plans to handle
Year 2000 issues, and expects these plans to be completed by mid-1999. As
discussed above, the Company is also working with NERC and WSCC to develop
contingency plans related to grid operation.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1
of this report for discussions of competitive developments and regulatory
accounting. See Note 7 of Notes to Condensed Financial Statements in Part I,
Item 1 of this report for a discussion of a proposed amendment to a Power
Coordination Agreement with Salt River Project that the Company estimates would
reduce its pretax costs for purchased power by approximately $17 million in 1999
and by lesser annual amounts through 2006.
RATE MATTERS
See Note 6 of Notes to Condensed Financial Statements in Part I, Item 1
of this report for a discussion of a price reduction, which became effective on
July 1, 1998.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve
risks and uncertainties. Words such as "estimates," "expects," "anticipates,"
"plans," "believes," "projects," and similar expressions identify
forward-looking statements. These risks and uncertainties include, but are not
limited to, the ongoing restructuring of the electric industry; the outcome of
the regulatory proceedings relating to the restructuring; regulatory, tax and
environmental legislation; the ability of the Company to successfully compete
outside its traditional regulated markets; regional economic conditions, which
could affect customer growth; the cost of debt and equity capital; weather
variations affecting customer usage; technological developments in the electric
industry; and Year 2000 issues.
<PAGE>
-22-
These factors and the other matters discussed above may cause future
results to differ materially from historical results, or from results or
outcomes currently expected or sought by the Company.
<PAGE>
-23-
PART II - OTHER INFORMATION
---------------------------
ITEM 5. OTHER INFORMATION
CONSTRUCTION AND FINANCING PROGRAMS
See "Liquidity and Capital Resources" in Part I, Item 2 of this report
for a discussion of the Company's construction and financing programs.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1
of this report for a discussion of competition and the rules regarding the
introduction of retail electric competition in Arizona. On February 28, 1997 and
October 16, 1998, lawsuits were filed by the Company to protect its legal rights
regarding the rules and the amended rules, respectively, and in each complaint
the Company asked the Court for (i) a judgment vacating the retail electric
competition rules, (ii) a declaratory judgment that the rules are unlawful
because, among other things, they were entered into without proper legal
authorization, and (iii) a permanent injunction barring the ACC from enforcing
or implementing the rules and from promulgating any other regulations without
lawful authority. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION
COMMISSION, CV 97-03753 (consolidated under CV 97-03748.) ARIZONA PUBLIC SERVICE
COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-18896. On August 28, 1998, the
Company filed two lawsuits to protect its legal rights under the stranded cost
order and in its complaints the Company asked the Court to vacate and set aside
the order. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV
98-15728. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION,
1-CA-CC-98-0008. See "State-Proposed Settlement Agreement" in Note 5 of Notes to
Condensed Financial Statements in this Report regarding the possible dismissal
of the lawsuits described in this paragraph.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
EXHIBIT NO. DESCRIPTION
- ----------- -----------
27.1 Financial Data Schedule
99.1 Settlement Agreement with the ACC dated November 4, 1998, which
includes a Memorandum of Understanding with TEP
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:
<PAGE>
-24-
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE
- ----------- ----------- ---------------------------- --------- --------------
<S> <C> <C> <C> <C>
3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96
February 20, 1996 Report
3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95
Directors temporarily Report
suspending Bylaws in part
3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, 1988 Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report
3.4 Certificates pursuant to 4.3 to Form S-3 1-4473 9-29-93
Sections 10-152.01 and Registration Nos.
10-016, Arizona Revised 33-33910 and 33-55248 by
Statutes, establishing Series A means of September 24,
through V of the Company's 1993 Form 8-K Report
Serial Preferred Stock
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
</TABLE>
(b) Reports on Form 8-K
During the quarter ended September 30, 1998, and the period from
October 1 through November 13, 1998, the Company filed the following reports on
Form 8-K:
Report dated August 5, 1998 regarding the ACC rules related to retail
competition.
- --------
(a) Reports filed under File No. 1-4473 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
<PAGE>
-25-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Dated: November 13, 1998 By: George A. Schreiber, Jr.
--------------------------------------
George A. Schreiber, Jr.
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer
and Officer Duly Authorized
to sign this Report)
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,687,675
<OTHER-PROPERTY-AND-INVEST> 186,342
<TOTAL-CURRENT-ASSETS> 514,007
<TOTAL-DEFERRED-CHARGES> 1,064,409
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 6,452,433
<COMMON> 178,162
<CAPITAL-SURPLUS-PAID-IN> 1,143,617
<RETAINED-EARNINGS> 610,535
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,932,314
9,401
123,795
<LONG-TERM-DEBT-NET> 1,871,949
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 115,350
<LONG-TERM-DEBT-CURRENT-PORT> 154,220
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,245,404
<TOT-CAPITALIZATION-AND-LIAB> 6,452,433
<GROSS-OPERATING-REVENUE> 1,562,872
<INCOME-TAX-EXPENSE> 162,808
<OTHER-OPERATING-EXPENSES> 1,100,145
<TOTAL-OPERATING-EXPENSES> 1,262,953
<OPERATING-INCOME-LOSS> 299,919
<OTHER-INCOME-NET> 19,179
<INCOME-BEFORE-INTEREST-EXPEN> 319,098
<TOTAL-INTEREST-EXPENSE> 101,786
<NET-INCOME> 217,312
7,660
<EARNINGS-AVAILABLE-FOR-COMM> 209,652
<COMMON-STOCK-DIVIDENDS> 127,500
<TOTAL-INTEREST-ON-BONDS> 87,558
<CASH-FLOW-OPERATIONS> 466,968
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
ARIZONA PUBLIC SERVICE COMPANY, INC.
DOCKET NO. E-01345A-98-0473
DOCKET NO. E-01345A-97-773
DOCKET NO. RE-00000C-94-0165
SETTLEMENT AGREEMENT
--------------------
The undersigned parties stipulate and agree to the following settlement
provisions in connection with the following applications submitted to the
Arizona Corporation Commission ("Commission") by Arizona Public Service Company,
Inc. ("APS" or "Company"): Docket No. E-01345A-98-0473 and Docket No.
E-01345-97-773.
In addition, this Settlement Agreement ("Agreement") settles all issues
arising from or related to the Commission's Electric Competition Rules as set
forth in Decision Nos. 59943, 60977 and 61071.
STATEMENT OF INTENTION.
The purpose of this Agreement is to resolve contested matters in a
manner consistent with the public interest. The contested matters were
generated, in large measure, as a result of the Commission's Retail Electric
Competition Rules and APS' regulatory filings made in response thereto. The
parties recognize that the electric utility industry is undergoing a transition
to competition, which is scheduled to begin on January 1, 1999.
It is the intention of the parties, APS and Commission Staff ("Staff"),
through this Agreement, to provide resolution of the contested matters regarding
APS' unbundled tariffs, APS' requested stranded cost recovery, and certain
outstanding matters related to the Commission's Retail Electric Competition
Rules. This settlement is intended to be comprehensive, fair to APS, its
shareholders and customers and will serve to make an efficient and cost
effective transition to a new era of customer choice in a competitive market
structure. Therefore, the parties believe that this settlement is in the public
interest.
The parties also agree that in exchange for APS divesting its
Transmission Assets, as defined below, APS shall fully recover its stranded
costs, as described herein. Under this Agreement, the basis for APS' opportunity
to recover its stranded cost is the divestiture of APS' Transmission Assets
including 345 kV and above. The failure of APS to divest of its Transmission
Assets as provided herein will eliminate APS' opportunity to recover its
stranded costs in the manner provided by this Agreement. Instead, the Commission
may award transition revenues to APS in order to maintain its financial
viability. For purposes of this Agreement, the term "divestiture" under the
Commission's rules includes APS' divestiture of Transmission Assets as agreed to
herein. Staff believes that APS' divestiture of these Transmission Assets limits
the potential for APS to exercise vertical market power and as such constitutes
a change in market structure in the transition to competition.
<PAGE>
I. CONTINGENCY OF AGREEMENT.
This Agreement is contingent upon Commission approval of the Agreement
in its entirety and without modification pursuant to a final and non-appealable
order.
II. UNBUNDLED RATES.
The Company's unbundled rates and charges will reflect (1) the embedded
cost of service for all functions as approved by the Commission, (2) the 1.1
percent rate reduction approved by the Commission in Decision No. 61103 (August
28, 1998) and (3) separately identify distribution, transmission, metering,
billing and system benefits and the remaining generation service, which shall
consist of a Competition Transition Charge, ("CTC") a nonbypassable charge for
Regulatory Assets, and a Market Generation Credit ("MGC"). Current recovery
levels of Regulatory Assets will continue until all Regulatory Assets are
recovered, at which point APS will, without further Commission action, adjust
its prices to remove any charges for Regulatory Asset recovery, unless APS
demonstrates and the Commission finds that APS has experienced offsetting
increased revenue requirements attributable to Commission-regulated APS electric
services.
The quarterly Market Generation CreditS (MGC) shall be calculated for
peak and off-peak hours for the next twelve months based on the Palo Verde Nymex
futures price, plus 3 mills, and brought to the retail delivery level by
multiplying by 1 plus the appropriate line loss. The peak and off peak prices
shall be determined by shaping the Palo Verde Nymex futures price by actual
hourly prices from the California spot price index. The adder will be adjusted
for each class for differences between the class load factor and the system
average load factor before being included in the MGC. The basic 3 mill adder
shall remain in effect unchanged unless 25% of the load eligible for competition
has not selected an alternative supplier by December 31, 2000, in which case the
adder will be increased to 3.5 mills. By September 1, 2002, Staff and APS shall
present to the Commission their recommendations regarding the appropriate Market
Generation Credit for the period from January 1, 2003 until the CTC collection
ends. At this same time, Staff and APS shall also present recommendations
regarding the longer-term provision of Provider of Last Resort service. The
monthly competitive transition charges shall be the residual after subtracting
distribution, transmission, metering, billing, system benefits, the regulatory
asset charge and the retail MGCs from the bundled tariff. The computation of the
MGC and the CTC charge will be described in Exhibit A to this Agreement.
In addition, APS may file by September 1, 1999 an overall Company
"revenue neutral" rate case to realign standard offer and unbundled rates in
accordance with appropriate cost allocation and rate design principles. The
Commission shall take such action as is necessary to rule on the Company's
filing that redesigned, overall Company revenue neutral, rates will be effective
as of January 1, 2001. This rate application will not change the Company's
currently authorized cost of capital or request an overall revenue increase.
There may be a mismatch between the projected MGC and the MGC that
would have resulted from the forward price at the close of each month for the
following month. The
2
<PAGE>
difference between these two forward prices for the same month multiplied by the
competitive sales in a month shall be interpreted as an over or undercollection
of stranded costs. Monthly under and overcollections shall be accumulated with a
reasonable carrying charge. If the accumulated undercollection reaches $5
million, the Company may increase the generation component of all rates by a
factor that would collect these dollars within one year.. At the end of the
fixed rate period (end of 2002) or upon the cessation of the regulatory asset
charge, if this occurs earlier, the Company shall increase or decrease
generation rate charges to collect or return this amount during the remaining
CTC period.
III. RECOVERY OF REGULATORY ASSETS.
APS will be allowed 100 percent recovery of regulatory assets in
accordance with Section II. These will be identified separately in the unbundled
tariffs.
IV. TRANSITION REVENUES/STRANDED COSTS
APS and Tucson Electric Power Company ("TEP") have executed the
memorandum of understanding ("MOU"), attached hereto as Exhibit B, for the
exchange of certain APS transmission assets, consisting of its 345 kV and 500kV
facilities ("Transmission Assets"), for TEP's interests in the Four Corners
Generating Plant and Navajo Generating Plant. The MOU commits both parties to
negotiate in good faith to reach a definitive agreement on the exchange of
assets. This MOU also outlines the structure of the transaction, describes the
assets to be included in the exchange, establishes the Parties' good faith
estimate of asset values, establishes a transmission pricing structure and lists
the conditions to closing the transaction. These closing conditions include (1)
securing independent appraisals and fairness opinions, and (2) obtaining all
necessary consents and approvals from regulatory agencies and third parties in a
form and substance satisfactory to both parties. This MOU is supported in its
entirety by Commission Staff and approval of this Settlement Agreement by the
Commission shall be deemed to constitute all requisite approvals necessary to
consummate the transaction described in the MOU.
In the event that APS divests its transmission assets according to the
MOU, APS will be allowed recovery of transition revenues through a CTC according
to Section II of this Agreement until December 31, 2004. As part of this
Agreement, the Commission will not alter the transition revenue amounts before
December 31, 2004 unless the Commission finds that APS or its competitive
affiliate has significant market power and has manipulated the market price for
power in the region. This exceptions will allow the Commission to adjust,
terminate or declare interim and subject to refund the transition revenue amount
reflected in the CTC.
In the event that APS does not divest its transmission assets according
to the MOU, except to the extent that any joint owner of any such assets
exercises a right of first refusal, APS will not be allowed recovery of stranded
costs through a CTC but rather interim transition
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revenues will be implemented as identified in this Agreement. APS may file an
application with the Commission to recover transition revenues based on its
financial viability and actual load lost to unaffiliated electric service
providers. It is anticipated that divestiture would occur in a transaction
closing no later than December 31, 2000.
V. DIVESTITURE.
Staff believes that achieving the following three objectives will limit
the ability of APS to exercise vertical market power and will assist in
achieving competition:
(1) all network customers in an access area (or zone) should pay the same rate
for transmission service.
(2) all customers should have access to any generation within the region at no
additional cost; and
(3) transmission constraints and/or the allocation of Available Transmission
Capacity ("ATC") should not be allowed to unduly frustrate competition.
These objectives can be met using either a region-wide "postage stamp"
approach or a properly implemented "license plate" approach. If a "license
plate" approach is to be used, it needs to be "all inclusive", i.e., all
intra-regional transmission costs currently being paid by network customers
within each access area need to be absorbed by the access area provider and
reflected in the "license plate" rate. Under any pricing approach, congestion
management and ATC determination will be crucial to a successful implementation.
The following principles will apply :
<- Subject to rights of first refusal which may be exercised by joint owners,
APS shall transfer to TEP's affiliate ("Transco") all transmission
facilities owned by APS at a voltage level of 345 kV and above. This is
required for all components of the transmission system that may be subject
to Committed Uses or constraints which, in turn, may be used to promote
Vertical Market Power.
<- APS shall file an application with FERC to place all facilities below the
voltage level of 345 kV (which APS asserts serve a distribution function)
under the jurisdiction of the ACC, with appropriate provisions for
wholesale customers subject to FERC's jurisdiction.
<- APS will work with the Transco to file comparable network and
point-to-point tariffs, providing transmission service on a "license plate"
basis over the combined APS/TEP service areas, and including adjacent
systems as appropriate when the Independent Scheduling Administrator
("ISA") and/or Independent System Operator ("ISO") is implemented.
<- APS will work with TEP to pursue the "license plate" approach and requisite
filings even if the current ISA implementation plan fails to materialize or
receive FERC approval as currently proposed.
<- APS will work with TEP to ensure that all Committed Uses under their
control will be used for all customers within their respective access areas
on a non-discriminatory basis:
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<- APS will provide Staff with a comprehensive definition and explanation of
all Committed Uses supported by APS (existing or contemplated).
> If FERC rejects or otherwise orders APS to modify its commitments, APS
will comply accordingly and will not seek to relieve itself of the
obligations accepted herein.
> APS will work with TEP to ensure that any and all Committed Uses are
applied in a consistent manner for all transmission facilities so that
no generation resources are given a competitive advantage by virtue of
contractual constraints or protocols (as contemplated in the ISA
filing) designed to limit ATC.
> APS will pursue in good faith any mitigation measures (Re: The "license
plate" approach) that are necessary for a full region-wide Desert Star
(or other ISO) implementation without "pancaked" rates.
<- APS shall on a regular basis, but not less than quarterly, provide Staff a
written report and briefing on the activities described in this section.
APS' failure to comply with the provisions of this section, other than the
transfer of APS' transmission facilities as described herein, shall not, by
itself, provide a basis for the Commission to modify any provision of this
Agreement or of the order approving this Agreement, dealing with cost
recovery.
VI. FERC TRANSMISSION ISSUES
APS and TEP will develop and present to FERC a transmission pricing
structure for the use of such assets that will not increase rates to customers
in APS or TEP's current service territories. APS will enter into a Service
Agreement with TEP relating to APS' use of the Transmission Assets under an Open
Access Transmission Tariff ("OATT") accepted by FERC. The OATT shall have zonal
rates developed for the use of the transmission facilities pursuant to which the
transmission rates for any transmission user in either APS' or TEP's current
service territory, including APS' merchant group, shall not be adversely
affected by the transfer of the Transmission Assets. Where APS transmission
users are receiving service under a single agreement for both the Transmission
Assets and the lower voltage transmission assets to be retained by APS, the
Parties will agree to bifurcate those obligations in a manner that will not
result in any cost shifting or increase in transmission costs to such users or
APS. The Commission shall support the APS and TEP FERC filings to effectuate the
transmission pricing principles described in this paragraph.
VII. RATE REDUCTIONS.
The existing Second Restated and Amended Rate Reduction Agreement,
("1996 Agreement"), as reflected in Decision No. 59601, will be extended until
December 31, 2002, subject to the following revisions. In addition to the
revisions listed below, the provisions of the 1996 Agreement that are or will be
moot, extended with modifications or extended without
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modifications, are identified in Exhibit C hereto. Rate reductions for the years
1999 through 2002 will be:
For usage on and after July 1, 1999, 1.0% or the APS formula contained in
the existing Second Restated and Amended Rate Reduction Agreement, as
reflected in Decision No. 59601, using 1998 calendar year, whichever is
greater, to be applied to both Standard Offer and unbundled rates;
For usage on and after July 1, 2000, 1.0% or the APS formula using 1999
calendar year, whichever is greater, to be applied to both Standard Offer
and unbundled rates;
For usage on and after July 1, 2001, 1.0% or the APS formula using 2000
calendar year, whichever is greater, to be applied to Standard Offer rates
for residential customers only;
For usage on and after July 1, 2002, 1.0% or the APS formula using 2001
calendar year, whichever is greater, to be applied to Standard Offer rates
for residential customers only.
The impact of each year's rate reduction should be implemented through
reductions to generation rates that result in equal percentage reductions to
each class (including competitive customers).
Costs of complying with the Electric Competition Rules, system benefits
costs, and solar power costs in excess of levels included in current rates, may
be deferred subject to the limitations set forth below. Notwithstanding the rate
reduction provisions stated above, the Company's share of any property tax
expense decreases shall be used to offset other expense deferrals referred to in
this section. In any year that the APS formula is used to calculate the rate
reductions, ratepayer's 55% share above the stated, minimum 1% rate reduction,
would first be used to reduce amounts otherwise deferrable. APS will be allowed
full recovery of any remaining deferrable costs beginning January 1, 2003. APS
agrees to make an annual reporting of its level of deferred expenses to be
included in its rate reduction filings.
APS agrees to meet the requirements of the Solar Portfolio Standard,
Section 1609 of the rules, as amended in August 1998. APS agrees to support the
continuation of the Solar Portfolio Standard in future Commission proceedings.
APS agrees to continue the programs included in the System Benefits Charge at a
level equal to or greater than the level at which APS was funding those programs
in 1997.
As applied to APS (as a utility distribution company), the solar
portfolio standard ("SPS") established by the Commission for distribution
companies in A.A.C. R14-2-1609(C), as amended in August, 1998, will be met by
APS purchasing all the necessary solar power through an RFP process and
recovering the associated costs through a "green" solar rate to market such
solar power to its Standard Offer customers at a price designed to recover such
costs (but, in the event revenue from such rate plus any additional revenue
received from the sale of solar power to any other entities is not sufficient to
fully recover such costs, any deficiency shall be deferred for recovery
[including a reasonable return] as discussed above. The RFP process and cost
recovery mechanism will be subject to (1) approval of the RFP by the Director of
the Utilities Division by July 1, 1999, and (2) joint approval by APS and the
Director of the Utilities Division of a successful, qualified responsive bid to
such RFP.
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VIII. SEPARATION OF MONOPOLY AND COMPETITIVE SERVICES
APS will transfer its generation services and competition assets at
book value into a separate corporate affiliate no later than December 31, 2002.
APS is also granted a waiver from compliance with the provisions of A.A.C.
R14-2-1606(B) until December 31, 2002. Approval of this Agreement by the
Commission shall be deemed to constitute all requisite Commission approvals for
(1) the creation of a new corporate affiliate and the transfer thereto of APS'
generation services and competitive assets at book value; and (2) the full and
timely recovery through the mechanism referred to in Section VII above for the
reasonable and prudent costs of such action. Such transfers may require various
regulatory and third party approvals, consents or waivers from entities not
subject to APS' control, including the FERC and the NRC. No party to this
Settlement Agreement nor the Commission will oppose, or support opposition to,
APS requests to obtain such approvals, consents or waivers.
By December 15, 1998, the Company will provide the ACC Staff with a
detailed description of the process and the time necessary for a transfer of its
generation and competitive service assets into a separate corporate affiliate.
The Company shall also specify the nature and magnitude of any associated
transaction costs that APS will request be recovered in rates.
By November 15, 1998, the Company will establish a separate energy
services corporate affiliate (approval of which shall be deemed given by
Commission approval of this Agreement) and will apply for a competitive CC&N to
provide such competitive retail generation and other competitive services as it
intends to offer. No later than November 30, 1998, the Company will file in the
competitive CC&N docket a code of conduct that will address any and all concerns
regarding the separation of monopoly and competitive services that arise from
forming and operating a competitive affiliate while retaining generation assets
until December 31, 2002. Staff will recommend to the Commission, by December 1,
1998, that it grant such application, subject only to such conditions as are
reasonably imposed on other Energy Service Providers, unless specific
circumstances warrant additional conditions.
IX. INDEPENDENT SCHEDULING ADMINISTRATOR/INDEPENDENT SYSTEM OPERATOR.
The Company shall commit to having an independent scheduling
administrator ("ISA") in place and operational by April 1, 1999, and commit to
facilitating the development of an independent system operator ("ISO") for
Arizona by December 31, 2000. APS shall , on a regular basis, but not less than
quarterly, provide Staff a written report and briefing on the status of the ISA
and ISO. In the event APS does not have an independent scheduling administrator
in place by December 31, 1998 or, an independent system operator by December 31,
2002, the Commission shall examine the reason(s) for the failure and the efforts
expended by APS in compliance with this Section. APS' failure to comply with the
provisions of this section shall not, by itself, provide a basis for the
Commission to modify any provision of this Agreement or of the order approving
this Agreement, dealing with cost recovery The ISA/ISO also calculates available
transmission capacity and implements protocols for system transfer capabilities,
committed uses of the transmission system, must-run generating units (as
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determined by the Commission) and provides dispute resolution such that market
participants can expeditiously resolve dispute claims. If an Arizona only ISO is
established, it is anticipated that it would join a regional ISO when one is
established.
XI. SECTION 40-252 - CERTIFICATE OF CONVENIENCE AND NECESSITY
APS agrees to modify its Certificate(s) of Convenience and Necessity to
permit competition pursuant to A.A.C. R14-2-1600, et seq., as amended in August
1998. The order adopting this Settlement Agreement shall constitute the
necessary Commission Order modifying APS' CC&Ns to permit competition.
XII. RESOLUTION OF LITIGATION.
Upon issuance by the Commission of a final, non-appealable order
approving this Agreement, APS shall move to dismiss with prejudice all pending
litigation brought by APS against the Commission. As mutually agreed, APS will
actively support the Commission's position and assist the Commission in any
remaining litigation regarding the Commission's Electric Competition Rules or
related matters.
XIII. MUST RUN ASSETS.
To the extent such contracts are not subject to FERC jurisdiction,
contracts regarding the sale of output from must run generation units shall be
reviewed and approved by the Commission.
XIV. WAIVERS.
APS has requested waiver of certain Affiliated Interest Rules. Staff
concurs with APS' requests for waivers of certain Affiliated Interest Rules, and
agrees that the Commission's approval of this Agreement will constitute the
Commission's granting of the waivers, under the following conditions and
limitations:-
R14-2-801(5)
APS has requested a waiver of the definition of "reorganization" to exclude
corporate reorganizations that do not involve a reconfiguration of the
utility distribution company ("UDC") in the holding company structure.
Under the waiver proposed by APS, the holding company would be free to
reorganize, buy or sell non-regulated affiliates without Commission
approval. Staff agrees that R14-2-801(5) is waived as applied to APS'
non-regulated affiliates to the extent that the UDC is not implicated in
any reorganization of the holding company's structure or the non-regulated
affiliates' structure. In any reorganization where the UDC is implicated in
any manner as to reconfiguration of the holding company's structure or an
affiliates' reconfiguration, or if the UDC forms, divests
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or reconfigures any of its subsidiaries, Rule R14-2-801(5) is not waived
and is applicable to APS (UDC).
R14-2-804(A)
APS has requested a waiver of the rule that requires any affiliate that
transacts business with the UDC to open its books and records to Commission
review. Staff agrees that R14-2-804(A) may be waived as long as the
non-regulated affiliate's books and records reflect transactions with the
UDC and are included in the Code of Conduct required by the Electric
Competition Rules. By this waiver, the Commission still retains
jurisdiction to review and have access to the books and records of
affiliates of the UDC for whatever purposes the Commission deems
appropriate if the Commission's rate setting jurisdiction is implicated.
R14-2-805(A)
APS has requested waiver of the rule that requires a holding company to
file an annual report with respect to diversification plans and the
activities of unregulated subsidiaries. The affect of the waiver requested
by APS would be to limit the annual filing requirement to the UDC only.
Staff agrees that the annual filing under the rule can be limited to the
UDC unless the holding company or subsidiary's activities implicate the
UDC, and have a likely material adverse affect upon the UDC's financial
viability and integrity.
R14-2-805(A)(2)
This Rule requires a specific description of business activities of all
affiliates to be filed with the Commission on an annual basis. APS wishes
to have a waiver of the Rule and limit disclosure to the nature of the
business rather than specific activities. Staff agrees this Rule may be
waived to the extent indicated by APS.
R14-2-805(A)(6)
APS seeks a waiver of the disclosure requirement in the annual filing for
bases for allocation of all plant revenue expenses to all regulated and
unregulated entities in the holding company structure. APS' request limits
disclosure to allocations applicable to the UDC. Staff agrees with this
waiver to disclosure but reserves the Commission's jurisdiction to receive
disclosure of the bases for allocation if necessary in the Commission's
determinations in any matter, including but not limited to rate setting
matters.
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R14-2-805(A)(9), (10) and (11)
APS seeks a waiver of the annual submission of contracts and agreements for
transactions between the regulated utility and nonregulated affiliate.
Staff agrees to the waiver of this requirement as requested by APS as to
the contracts and agreements which are not covered by the Code of Conduct
required by the Retail Competition Rules or not subject to FERC approval.
However, the Commission reserves the jurisdiction to receive the
information that would have been submitted under the rule, if the
Commission deems necessary for any purpose including, but not limited to
rate setting matters.
XVI. IMPLEMENTATION OF RETAIL ACCESS.
Direct access to electric generation suppliers will be phased in for
all customers in APS' territory in accordance with A.A.C. R14-2-1604. APS shall
determine residential customers eligible for retail access pursuant to the plan
filed by APS with the Commission on September 15, 1998. For customers that are
20 kW or smaller at each premise, load profiling will be allowed.
XVII. CLARIFICATION OF SERVICES THAT MUST AND CAN BE OFFERED BY APS
Staff will support amending A.A.C. R14-2-1616.B, as provided in Exhibit
D hereto.
XVIII. CONSIDERATION FOR AGREEMENT
The Company's willingness to enter into this Agreement and to withdraw
from certain civil actions against the Commission is based upon the Commission's
irrevocable promise herein to permit recovery of the Company's regulatory assets
and stranded costs as provided herein. Such promise by the Commission shall
survive the expiration of the Agreement and shall be specifically enforceable
against this and any future Commission.
MISCELLANEOUS PROVISIONS
1. ADMISSIONS.
This Agreement represents an attempt to compromise and settle disputed
claims arising out of APS' Applications in a manner consistent with the public
interest. Nothing contained in this Agreement is an admission by any of the
parties that any of the positions taken, or that might be taken by each in
formal proceedings, is unreasonable. In addition, acceptance of this Agreement
by the parties is without prejudice to any position taken by any party in these
proceedings.
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2. COMMISSION ACTION.
Each provision of this Agreement is in consideration and support of all
the other provisions, and expressly conditioned upon acceptance by the
Commission without change. In the event that the Commission fails to adopt this
Agreement according to its terms by November 25, 1998, this Agreement shall be
deemed withdrawn and the parties shall be free to pursue their respective
positions in these proceedings without prejudice.
3. LIMITATIONS.
The terms and provisions of this Agreement apply solely to and are
binding only in the context of the provisions and results of this Agreement and
none of the positions taken herein by the parties may be referred to, cited or
relied upon by any other party in any fashion as precedent or otherwise in any
other proceeding before this Commission or any other regulatory agency or before
any court of law for any purpose except in furtherance of the purposes and
results of this Agreement.
4. To the extent that any provisions of this Agreement are inconsistent
with the Commission's Electric Competition Rules, the provisions of this
Settlement Agreement are intended to apply. However, no waivers of any
Commission rules are granted to APS except as provided herein.
5. LOW INCOME CUSTOMER PROGRAMS.
Prior to Commission consideration of this Settlement Agreement, the
parties acknowledge that APS may enter into discussions with others regarding
low income customer programs and, as a result, may request Commission
recognition of the results of such discussions.
6. PROPOSED ORDER.
The proposed form of order acceptable to the parties is contained in
Exhibit E, attached hereto.
Dated this November 4, 1998
Arizona Public Service Company Arizona Corporation Commission
By: William J. Post By: Jack Rose
--------------------------- ---------------------------
Title: CEO Title: Executive Secretary
------------------------ ------------------------
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CALCULATION OF THE MARKET GENERATION CREDIT
The Market Generation Credit ("MGC") will be stated as an Off-Peak and
an On-Peak value for each calendar month. For all customers less than 1 MW in
size, the total monthly dollar credit will be calculated by customer class and
will use the same energy consumption profile for each customer within a
particular class. The total monthly dollar credit for customers 1 MW or greater
will be calculated individually for each customer. All MGC values will be
determined in the month of November for the succeeding calendar year. The
calculations will be based on the NYMEX forward price curve for the succeeding
calendar year and the historical California PX Prices for the preceding year.
The MGC values will be grossed up by the distribution Loss Factor as well as the
Adder, as such terms are defined below.
ON-PEAK MGC = [(NYMEX) * (1 + LOSS FACTOR)] + ADDER
OFF-PEAK MGC = [(NYMEX) * (1 + LOSS FACTOR) * (LLR)] + ADDER
Where:
ADDER: An addendum to the calculated prices designed to
promote competition and credit customers for
ancillary services. This adder will be set at
0.300(cent) kWh for conforming loads (those with
coincident peak load factors equivalent to the
aggregate system load factor). This adder will be
adjusted by the ratio of system load factor to
customer load factor and stated in increments of 5
between 35 percent and 95 percent load factors.
LOSS FACTOR: A multiplier designed to reflect the appropriate
distribution losses by voltage level.
LLR: A light load ratio calculated by dividing the average
California Off-Peak price by the average California
On-Peak prices for the same month of the preceding
year. The California Off-Peak and On-Peak prices will
be the hourly day-ahead unconstrained California PX
prices.
OFF-PEAK: All holidays and hours recognized by the Western
Systems Coordinating Council as off-peak periods.
ON-PEAK: All non-Off-Peak hours.
NYMEX: The Palo Verde electricity futures contract traded on
the New York Mercantile Exchange for each month of
the following calendar year as determined in November
of the preceding year.
MONTHLY CUSTOMER TRANSITION CHARGE CALCULATION
The monthly Customer Transition Charge (CTC) will be calculated using
the following formula:
EXHIBIT A
<PAGE>
CTCS = [(TARIFF GENERATION CHARGES) * (BILLING DETERMINANTS)] - [(MGC +ADDER)
* (BILLING DETERMINANTS)]
The monthly CTC cannot be less than zero.
TRUE-UP OF THE MONTHLY CUSTOMER TRANSITION CHARGE CALCULATION:
The difference between the projected monthly NYMEX price as described
above and the actual NYMEX price as determined by the average of the last three
trading days for that month will be multiplied by that month's competitive
direct access sales. This monthly amount will be considered an over- or under-
recovery of stranded costs. These differences will then be accumulated
(including a return component), and at the end of each calendar year will be
divided by the next calendar year's projected competitive direct access sales.
The resultant factor (in (cent)/kWh) will be applied to any competitive direct
access sales during the following calendar year in order to adjust the CTC for
the calculated true-up.
Exhibit A
<PAGE>
MEMORANDUM OF UNDERSTANDING
BETWEEN
ARIZONA PUBLIC SERVICE COMPANY AND TUCSON ELECTRIC
POWER COMPANY
The purpose of this memorandum of understanding ("MOU") is to confirm
the understanding between ARIZONA PUBLIC SERVICE COMPANY ("APS"), and
TUCSON ELECTRIC POWER COMPANY ("TEP") regarding the transaction set
forth below.
1. RECITALS:
1.1. In connection with its Application for approval of its Plan
for Stranded Cost Recovery filed with the Arizona Corporation
Commission ("ACC") pursuant to A.A.C. R-14-2-1607, et. seq.,
TEP has proposed to divest all of its generation assets,
including, without limitation, TEP's interest in the Navajo
Generating Station located in Page, Arizona ("Navajo") and the
Four Corners Generating Units 4 and 5 located near Farmington,
New Mexico ("Four Corners"), all of which are more
particularly described on Attachment A ("Generating Assets");
1.2. APS is willing to divest its 345kV and 500kV transmission
system facilities and associated rights of way, which are more
particularly described on Attachment B (the "Transmission
Assets") only as part of, and conditioned upon, a
comprehensive settlement ("APS Settlement Agreement") with the
ACC Staff that requires such divestment to a third party, and
that satisfactorily resolves a number of competition-related
issues, and that is approved by an ACC order in form and
substance satisfactory to APS as more fully described below;
and
1.3. The Parties desire to outline in this MOU the principles that
will form the basis for negotiation of definitive terms and
conditions pursuant to which the Parties will exchange TEP's
Generation Assets for APS's Transmission Assets (the
"Transaction").
2. EXCHANGE OF ASSETS BETWEEN APS AND TEP:
At the Closing, as defined below, APS will transfer to TEP the
Transmission Assets and TEP will transfer to APS the Generation Assets.
In addition, subject to any consent requirements, APS shall transfer
and assign to TEP and TEP shall assume the obligations associated with
all existing agreements for transmission service over the Transmission
Assets. To the extent there is a difference between the agreed upon
fair market values of the Transmission Aassets and Generation Assets,
such difference will be paid in the form of cash at Closing, as defined
below, by the Party transferring the assets with the lower value. The
Transaction shall also include a power purchase agreement providing for
unit
Page 1 of 6
EXHIBIT B
<PAGE>
contingent power sales from APS to TEP, as more fully described in
Section 6 below ("Power Purchase Agreement").
3. CLOSING:
Subject to the terms and conditions set forth in the Definitive
Agreement, the closing of the Transaction (the "Closing") is estimated
to be on or before January 2, 2001. To the extent any condition
precedent set forth in the Definitive Agreement, including those
enumerated in Section 7 of this MOU, has not been satisfied by January
2, 2001, the Closing will be extended by mutual consent of the Parties
to a date by which the Parties reasonably believe that such condition
precedent will be satisfied. In the event all conditions have not been
satisfied or waived by the applicable Party or Parties by December 31,
2002, the Definitive Agreement between the Parties shall terminate.
4. DEFINITIVE AGREEMENT:
The completion of the Transaction is subject to the execution by the
Parties of an agreement, which will be based on the principles set
forth herein and which will include mutually agreeable and
comprehensive terms, conditions, representations, warranties,
indemnities, and covenants with respect to the Transaction and
structure (the "Definitive Agreement") on or before 60 days from the
date that the ACC enters both the APS Order and TEP Order, as described
herein. The obligation of APS to enter into the Definitive Agreement is
subject to the receipt by APS of a final Order, not subject to appeal,
which adopts the APS Settlement Agreement , which in form and substance
is satisfactory to APS ("APS Order"). The obligation of TEP to enter
into the Definitive Agreement is subject to the receipt by TEP of a
final Order, not subject to appeal, which adopts a settlement with the
ACC regarding TEP's Plan for Stranded Cost Recovery pursuant to A.A.C.
R-14-2-1607 et. seq ("TEP Order"). The Parties agree to negotiate in
good faith to reach a Definitive Agreement within the 60 day period
described above, provided, however, such time may be extended by mutual
agreement of the Parties. In the event APS and TEP do not obtain the
aforementioned Orders by December 15, 1998, or any mutually agreeable
extension thereof, either Party may terminate this MOU by providing
written notice to the other Party and neither Party shall have any
obligation or liability hereunder.
5. ASSET VALUATION
For purposes of the Transaction the value of the Transmission Assets
will be the book value at the date of Closing, which is estimated to be
approximately $162 million as of July, 1998; and the value of the
Generation Assets is $165 million as of January 1, 2001. The fair
market values are based on the Transaction being subject to the terms
and conditions outlined in this MOU; the asset descriptions contained
in Attachments A and B; and assumptions that the physical condition of
Page 2 of 6
<PAGE>
the Assets will not materially impair their operation or efficiency as
of the Closing date. Fair market values will be subject to adjustments
based on the final schedule of assets to be transferred; inventories of
equipment; and due diligence inspection of the physical condition of
the Assets and those rights and obligations to be transferred as part
of the Transaction. In the event that any of the Assets cannot be
transferred because of the exercise by any third party of a right of
first refusal to purchase a portion of such Assets, the fair market
value of such Assets shall be adjusted in proportion to the amount of
assets being transferred. The above values with respect to the
Generation Assets do not include any reserves for reclamation claims
through the date of Closing. Such reserves will be funded by a cash
payment to APS at Closing, if the amount of such reserves have been
definitively determined, or by establishment of an escrow reserve fund
to be agreed upon by the parties and to be funded in cash by TEP at
Closing. Fuel, material and supplies will be transferred at book value
at the time of Closing.
6. POWER PURCHASE AGREEMENT AND TRANSMISSION O&M
6.1. At Closing the parties will enter into a Power Purchase
Agreement which will provide for unit contingent power sales
from APS to TEP from the Generation Assets. The Power Purchase
Agreement will be based on the terms and conditions set forth
in Attachment C.
6.2. In negotiating the Definitive Agreement the Parties will
discuss the desirability of, and terms and conditions under,
which APS would continue to provide certain O&M support
functions for the Transmission Assets for a period subsequent
to Closing.
7. CONDITIONS PRECEDENT TO CLOSING:
7.1. The Definitive Agreement shall provide that Closing of the
Transaction shall be subject to certain conditions, which must
be satisfied prior to Closing. Each Party agrees to use its
best efforts to satisfy the conditions precedent applicable to
it prior to the Closing. In addition to any other conditions
the Parties may agree upon, conditions to Closing will include
the following:
7.2. MUTUAL CONDITIONS PRECEDENT:
7.2.1. Receipt of any necessary FERC approval of the
Transaction, including transfer of transmission
assets pursuant to ss. 203 of the Federal Power Act.
Page 3 of 6
<PAGE>
7.2.2. Receipt of FERC approval of a transmission pricing
structure as described in Section 8 of this MOU.
7.2.3. Receipt of any necessary ACC approval of the
Transaction.
7.2.4. Any consents or approvals of other regulatory
agencies and third Parties necessary to consummate
the Transaction as contemplated in the Definitive
Agreement.
7.2.5. Absence of any pending or threatened litigation or
adverse regulatory proceeding with respect to the APS
Order, the TEP Order or the Transaction.
7.2.6. Absence of any material adverse change in the
physical condition or value of the Transmission
Assets and Generation Assets between the date of the
Definitive Agreement and the Closing.
7.3. APS CONDITIONS PRECEDENT
7.3.1. Receipt of such consents or approvals as may be
required to effect the transfer of the Transmission
Assets, including satisfaction of any
rights-of-first-refusal held by the other
participants in the Transmission Assets.
7.3.2. Replacement of APS as Operating Agent for the Navajo
Project Southern Transmission System, the Four
Corners 500kV and 345kV Switchyards, and the Palo
Verde/North Gila 500kV line.
7.3.3. Execution of the Power Purchase Agreement by both
Parties.
7.3.4. Receipt of satisfactory fairness opinions and/or
independent appraisals and approval of its Board of
Directors.
7.4. TEP CONDITIONS PRECEDENT
7.4.1. Receipt of such consents or approvals as may be
required to effect the transfer of TEP's ownership
interest in Four Corners and Navajo, including
satisfaction of any rights-of-first-refusal held by
the other participants in the Navajo Project and the
Four Corners Project.
7.4.2. An order by the ACC which will allow TEP to recover
in rates its costs under the Power Purchase
Agreement.
7.4.3. Appointment of TEP as Operating Agent for the Navajo
Project Southern Transmission System, the Four
Corners 500kV and 345kV Switchyards, and the Palo
Verde/North Gila 500kV line.
Page 4 of 6
<PAGE>
7.4.4. Receipt of satisfactory fairness opinions and/or
independent appraisals and approval of its Board of
Directors.
7.5. All regulatory and third party consents and approvals shall be
satisfactory to each Party in form and substance.
8. TRANSMISSION PRICING:
In their applications to FERC for approval of the sale of the
Transmission Assets and the Open Access Transmission Tariff by which
APS will receive service over the Transmission Assets, the Parties will
develop and present to FERC a transmission pricing structure for the
use of such assets that will not increase rates to customers in the
Parties' current service territories. APS will enter into a Service
Agreement with TEP relating to APS' use of the Transmission Assets
under an Open Access Transmission Tariff accepted by FERC. This Open
Access Transmission Tariff shall contain zonal rates developed for the
use of EHV transmission facilities pursuant to which the transmission
rates for any transmission user in either Party's current service
territory, including APS' merchant group, shall not be adversely
affected by the transfer of the Transmission Assets. The Tariff will
also preserve and recognize the rights of transmission users under
their existing transmission agreements with the Parties. Where APS
transmission users are receiving service under a single agreement for
both the Transmission Assets and the lower voltage transmission assets
to be retained by APS, the Parties will agree to bifurcate those
obligations in a manner that will not result in any cost shifting or
increase in transmission costs to such users or APS.
9. EXCLUSIVITY:
unless and until this MOU is terminated pursuant to its terms, and
subject to the requirements associated with rights-of-first refusal
held by other participants in jointly owned projects in which the
Parties are also participants, the Parties shall not, directly or
indirectly, solicit or entertain offers from, negotiate with, or in any
manner encourage, discuss, accept, or consider any proposal of any
other person relating to the acquisition of the Assets, in whole or in
part. Notwithstanding the foregoing, the Parties understand and agree
that if all or any portion of the Transmission Assets are not
transferred to TEP due to a failure to satisfy any of the conditions
set forth in Section 7 above or in the Definitive Agreement, APS will,
in accordance with the terms of the APS Settlement Agreement, divest
those Transmission Assets to a third party upon such terms and
conditions as APS, in its sole and absolute discretion, determines to
be appropriate and TEP shall not take any action to prevent such
divestiture. The Parties further understand and agree that if all or
any portion of the Generation Assets are not transferred to APS due to
a failure to satisfy any of the conditions set forth in Section 7 above
or in the Definitive Agreement, TEP will, in accordance with the terms
of the TEP Order,
Page 5 of 6
<PAGE>
divest those Generation Assets to a third party upon such terms and
conditions as TEP, in its sole and absolute discretion, determines to
be appropriate and APS shall not take any action to prevent such
divestiture
10. CONFIDENTIALITY:
The Parties agree to continue to abide by the terms of the
Confidentiality Agreement between the Parties dated September 23, 1998.
11. COSTS:
Each Party shall be responsible for and bear all of its own costs and
expenses (including any broker's or finder's fees and the expenses of
its Representatives) incurred at any time in connection with the
negotiation of the Definitive Agreement and the pursuit or consummation
of the Transaction.
12. ENTIRE AGREEMENT:
This MOU constitutes the entire agreement between the Parties, and
supersedes all prior oral or written agreements, understandings,
representations and warranties, and courses of conduct and dealing
between the Parties on the subject matter hereof. Except as otherwise
provided herein, this MOU may be amended or modified only by a writing
executed by both Parties.
13. SIGNATURE CLAUSE:
The signatories hereto represent that they have been appropriately
authorized to enter into this Agreement in Principle on behalf of the
Party for whom they sign. This MOU is hereby executed as of this 4th
day of November, 1998.
ARIZONA PUBLIC SERVICE COMPANY
By Jack Davis
------------------------------------
Its President
------------------------------------
TUCSON ELECTRIC POWER COMPANY
By Vincent Nitido
------------------------------------
Its Vice President
------------------------------------
Page 6 of 6
<PAGE>
ATTACHMENT A
Generation Assets of TEP
NAVAJO GENERATING STATION
All of Tucson Electric Power Company's right, title, interest, and assets in the
Navajo Project and the Navajo Project Agreements including, but not limited to,
those specific interests as set forth in Sections 5.19, 6 and 7 of the Navajo
Project Co-Tenancy Agreement, as amended; excluding therefrom, however, any
right, title, and interest in facilities or agreements relating to the
transmission of electricity in excess of 230kV from the Navajo Generating
Station.
1. Adequate SO2 allowances to operate the generation facilities for their
remaining life.
2. Three steam electric generating units (Unit 1, Unit 2 and Unit 3), each
of which shall have a nameplate rating of 750,000 kw and shall be a
tandem-compound, four flow, single reheat, turbine-generator unit with
initial steam conditions of 3500 psig and 1000(degree) F, including
three pulverized coal-fired, super-critical steam generator units.
3. All auxiliary equipment associated with said units.
4. An administration building, machine shop and warehouse to be located
adjacent to the power plant.
5. A pumping station and all associated equipment to be located on the
Colorado River.
6. 500 kv step-up transformers and all equipment associated therewith up
to the point where the leads from the said transformers terminate at
the generator isolating 500 kv disconnect switch structures in the
Navajo 500 kv Switchyard.
7. Standby auxiliary power transformation equipment and related
facilities.
8. Plant control and communication facilities and associated buildings or
equipment.
9. Railroad approximately 80 miles in length extending from within the
Rail Loading Site into the Navajo Plant Site, rolling stock, related
facilities and equipment.
<PAGE>
10. All improvements owned by the Co-Tenants within the Ash Disposal Area,
Pumping Plant Site and Rail Loading Site.
11. All land and land rights acquired under the Indenture of Lease, the
ss.323 Grants and the Contract and Grant of Easement from the United
States for Water Intake and Discharge Facilities.
FOUR CORNERS GENERATING STATION
All of Tucson Electric Power Company's right, title, interest, and assets in the
Enlarged Four Corners Generating Station and the Four Corners Project Agreements
including, but not limited to, those specific interests as set forth in Sections
6, 7, and 8 of the Four Corners Project Co-Tenancy Agreement, as amended;
excluding therefrom, however, any right, title, and interest in facilities or
agreements relating to the transmission of electricity in excess of 230kV from
the Enlarged Four Corners Generating Station.
All SO2 allowances allotted to TEP's interest in the Four Corners
Project.
Steam Electric Generating Units 4 and 5 and their associated switchyard
facilities shall consist principally of two 755 mw class 3500 psig,
1000 F with reheat to 1000 F, cross-compound, 3600/1800 rpm, double
flow, outdoor turbine-generator units, complete with accessories; two
pressurized type, super-critical-pressure steam generating units,
designed for burning pulverized coal as primary fuel with natural gas
available for ignition fuel, complete with accessories; 345-500 kV tie
transformers; reserve auxiliary power source; and other items required
for the complete generating installation, excluding the Common
Facilities and Related Facilities allocated thereto.
COMMON FACILITIES FOR ENLARGED FOUR CORNERS GENERATING STATION:
1. Land Rights, including Lease Payments during Construction, Right-of-Way
Expense and Surveys.
2. Clearing Site of Brush and Rough Grading.
3. Landscaping and Planting Adjacent to Service Building.
4. Yard Finish Grading of Plant Areas not Requiring Paving or Gravel
Surfacing.
5. Plant Access Road, including Subbase, Surfacing, Auxiliary Dike,
Culverts and Asphalt Coat from San Juan Bridge to BIA Canal.
6. River Access Road, including Subbase, Gravel Surfacing, Pipeline Bridge
Crossing, Culverts and Riprap.
<PAGE>
7. Plant Area Roads, including Asphaltic Surfaced, Gravel Based and Other
Gravel Surfaced Roads.
8. Cement and Asphaltic Paving in Operating and Parking Areas, including
Curbing.
9. Concrete Walks at the Service Building, Warehouse and Circulating Water
Intake Area.
10. Plant Area Chain Link Fence, Remote Controlled Main Gate, Manual Gates
and Barbed Wire Fence.
11. Yard Lighting Standards, Conduit, Cable, Foundations and Lamps.
12. Fire Protection Pumps, Piping with Excavation and Backfill, Valves,
Hydrants and Hose Carts with Hoses and Nozzles.
13. Sanitary Sewer System, including Cast Iron and Clay Sewer Lines,
Manholes, Septic Tank and Accessories.
14. Service Water System Chlorinator, Coagulator, Filters, Pumps, Yard
Piping, Foundations and Domestic Water Lines.
15. Service and Shop Building Foundation, Walls, Doors, Windows, Heating
and Ventilating Equipment, Plumbing, Toilet Facilities and Lighting.
16. Warehouse Foundation, Floor Slab Superstructure and Lighting.
17. Miscellaneous Buildings, Foundations, Floor Slabs, Superstructures and
Lighting.
18. Coal Mobile Equipment, includes Hough D500 Paydozer.
19. Cooling Pond Dam, Spillway, Blowdown Structure, Intake Canal, Curtain
Wall and Temperature Recorders.
20. Concrete Intake Structure Excavation, Backfill, Caissons and Concrete
Structure for Service Water Pumps and Fire Pumps.
21. Hoist Structure and Hoist for Intake Area.
22. Screens and Stoplogs for Service Water and Fire Pumps.
23. Miscellaneous Equipment for Service Water and Fire Pumps.
24. Concrete Cribbing between Intake Structure and Canal Bank.
25. Circulating Water Discharge Canal to Cooling Pond.
<PAGE>
26. River Pumping Plant, includes River Weir, Sluiceway, Pump Chamber,
Gates, Stoplogs, Pumps, Motors, Lube Water Cooling System, Freeze
Protection, Switchgear, Motor Control Center, Transformers, Lighting,
Equipment Building, 69-kv Transmission Line, Power Supply, Fence,
Gates, Make-up Water Line, Metering Station and Canal.
27. Circulating and Service Water Intake Motor Control Center.
28. General Services Transformers for Area Lighting, Service Water Pump No.
2, Freeze Protection, Fire Booster Pump, etc.
29. Intake Area Transformer for Water Treatment Building, Fire Pump No. 1
Service Water Pumps No. 1 and No. 3, Service Building, Area Lighting,
Freeze Protection, etc.
30. Station Lighting Transformers.
31. Station Grounding and Cathodic Protection Systems, including Rectifier,
Anode Bed, Ground Rods and Ground Cable.
32. Freeze Protection Strip and Unit Heaters, Heating Cables, Controls and
Panels.
33. Underground Manholes, Handholes and Conduit, including Excavation,
Backfill and Concrete Envelope.
34. Miscellaneous Power Plant Equipment, including Portable Cranes and
Hoists, Fire Extinguishers, Vacuum Cleaner, Weather Station, Office
Equipment, Garage Equipment, Stores Equipment, Shop Equipment,
Laboratory Equipment, Small Tools, Kitchen Equipment, Testing Equipment
and Forklift.
35. 69-kv and 230-kv Switchyard Common to River Pumping Station, including
Portion of Site Improvement, Structures, Bus Conductors, Transformers,
Oil Circuit Breakers, Air Switches, Lighting Protection, Panels,
Wiring, Conduits, Ducts, Manholes, Grounding and Shielding.
36. ntra-site Communication (Gai-tronic and PAX Telephones Service Common
Facilities).
37. Spare Parts for Above Facilities.
RELATED FACILITIES:
1. COAL HANDLING SYSTEM
From the point of the Utah Mining termination at the surge bins down to
the gates in the bottom of the bins, including chutes, gates, motor
control center enclosure,
<PAGE>
and surge bins. Includes writing, lighting, foundations, dust control,
CO2 blanketing, electrical feed and control, structure, stairs and
platforms.
2. MACHINE SHOP STRUCTURE
Structure, foundation, lighting, wiring, doors, heating and ventilating
equipment, and plumbing, toilet, and shower facilities.
3. MODIFICATIONS TO SERVICE BUILDING
Structural changes, walls, doors, windows, heating and ventilating
equipment, lighting, and wiring.
4. VEHICLE BRIDGE OVER INTAKE CANAL
Structure, guard rail, pipe supports and surfacing.
5. REROUTE ACCESS ROAD THROUGH UNITS 4 AND 5 AREA
Subbase, base material, surfacing and culverts.
6. MODIFICATIONS TO RIVER PUMPING STATION AND MAKE-UP PIPELINE
Structures, foundations, pumps, motors, electrical supply facilities,
valves, piping and control apparatus for pump station and relocated
section of 36-inch make-up pipeline, new 2-inch pipeline for river pump
packing gland water, paving of roads and parking area and barricades
for protection from earth slides.
7. MOBILE EQUIPMENT MAINTENANCE BUILDING
Foundation, floor slab, superstructure and lighting and repair
equipment.
8. MISCELLANEOUS POWER PLANT EQUIPMENT
Small tools, machine shop tools, laboratory equipment, lockers, bins,
shelving, portable fire fighting equipment, etc.
9. ENLARGEMENT OF DISCHARGE CANAL
Excavation to enlarge channel for discharging circulating water to lake
and protection from erosion of channel walls.
10. COMBUSTIBLES STORAGE BUILDING
Foundation, floor slab, repairs to superstructure, and lighting.
11. STATION MOBILE EQUIPMENT
<PAGE>
Hydraulic crane, forklift trucks, small electric vehicles, and
bicycles.
12. PLANT ACCESS ROAD
Access road, including subbase preparation, base material, asphalt
surfacing, culverts and drainage facilities from BIA Canal to the
station gate.
13. COAL SAMPLING BUILDING AND EQUIPMENT
Sampling building structure from point of connection with the surge bin
structure including foundations, stairs, lighting, power facilities,
dust control facilities, hearing and ventilating sampling equipment,
sample preparation room with furnishings.
14. WIND VELOCITY AND DIRECTION INSTRUMENTS
Wind velocity and direction instruments, wiring conduit and recorders.
15. RIVER WATER SOLIDS MEASURING EQUIPMENT
Flow recorder, conductivity recorder and cells, conduit, wiring and
supports.
16. WAREHOUSE
Structure, floor slab, lighting, heating and ventilating equipment,
plumbing and office facilities.
17. NEW ADMINISTRATION BUILDING
Structure, foundation, lighting, windows, heating and ventilating
equipment.
18. GUARDHOUSE - MAIN AND SATELLITE
Structure, foundation, lighting, doors, heating and ventilating
equipment.
19. SWITCHYARD SHOP
Structures, foundation, lighting, doors, heating and ventilating
equipment and office facilities.
20. SHOP 4 & 5
Structure, foundation, lighting, wiring, doors, heating and ventilating
equipment, plumbing, toilet and shower facilities and office
facilities.
21. COMMON BUILDING
<PAGE>
Structure, foundation, lighting, wiring, doors, heating and ventilating
equipment, plumbing, toilet and shower facilities, office facilities
and lunch room facilities.
22. OVERHAUL SHOP
Structure, foundation, lighting, wiring, doors, heating and ventilating
equipment, plumbing, toilet facilities and office facilities.
23. 150 GALLON DEMINERALIZER
Structure, foundation, pumps, motors, electrical supply facilities and
water treatment facilities.
24. NATIONAL POLLUTION DISCHARGE ELIMINATION SYSTEM (NPDES) TRENCH
Excavated canal and concrete lined trench.
25. BRINE CONCENTRATOR AND RELATED CAPITAL IMPROVEMENTS
The brine concentrator and the capital improvements related thereto are
part of the SO2 removal project for Units 4 and 5 including the
separator blowdown line and the chemical cleaning piping.
<PAGE>
ATTACHMENT B
TRANSMISSION ASSETS
1. Cholla/Saguaro 500kV Line and rights-of-way
2. Cholla 500kV/345kV Switchyard and land rights
3. Saguaro 500kV Substation and land rights
4. Two Four Corners/Pinnacle Peak 345kV Lines and rights-of-way
5. Undivided interest in Four Corners345kV Switchyard and Project Agreements
6. Undivided interest in Pinnacle Peak 345kV Substation and land rights
7. Undivided interest in Four Corners 500kV Switchyard and Project Agreements
8. Preacher Canyon 345kV Substation and land rights
9. Undivided interest in Two Navajo/Westwing 500kV Lines, Project Agreements
and land rights
10. Undivided interest in Navajo 500kV Switchyard, Project Agreements, and land
rights
11. Undivided interest in Westwing 500kV Switchyard, Project Agreements, and
land rights
12. Undivided interest in Yavapai 500kV Substation, Project Agreements, and
land rights
13. Navajo Project breakers in Moenkopi 500kV Switchyard and Project Agreements
14. Navajo Project breakers, series capacitors, and a line reactor in the
Moenkopi Switchyard
15. Undivided interest in Two Palo Verde/Westwing 500kV Lines, agreements, and
rights-of-way
16. Undivided interest in Palo Verde 500kV Switchyard, agreements, and land
rights
17. Undivided interest in Interconnection Agreement with Westwing 500kV
Switchyard Participants
18. Undivided interest in Palo Verde/Kyrene 500kV Line, agreements, and
rights-of-way
19. Undivided interest in Palo Verde/North Gila 500kV Line, agreements, and
rights-of-way
<PAGE>
20. Undivided interest in Interconnection Agreement with Palo Verde 500kV
Switchyard Participants
21. Undivided interest in North Gila 500kV Substation, agreements, and land
rights
22. Undivided interest in Mead/Phoenix 500kV Line, Project Agreements, and
rights-of-way
23. Undivided interest in Perkins 500kV Substation, Phase Shifter, agreements,
and land rights
24. Undivided interest in Mead 500kV Substation, agreements and land rights
25. Undivided interest in Marketplace 500kV Switchyard, agreements and land
rights
26. Undivided interest in Market Place-Mead/Market Place - McCullough 500kV
Line, agreements, and rights-of-way
27. Undivided interest in McCullough 500kV Switchyard, agreements, and land
rights
28. Four Corners/El Dorado 500kV Line, Moenkopi Switchyard, Transmission
Service Agreement with Southern California Edison Company, and
rights-of-way
29. At substations, the ownership transition is at the high side of the
transformer, except Pinnacle Peak and Four Corners.
<PAGE>
ATTACHMENT C
POWER PURCHASE AGREEMENT
TERMS SHEET
PURCHASER: Tucson Electric Power Company
SELLER: Arizona Public Service Company
AMOUNT: 200MW
TERM: 4 years, beginning January 1, 2001
AVERAGE PRICE:
$/MWh
-----
2001 $31
2002 $32
2003 $33
2004 $35
Price to be shaped on an on-peak/off-peak basis, based on a
minimum load factor of 80% on-peak and 80% off-peak and a
maximum load factor which will be determined by mutual
agreement of the parties in the Power Purchase Agreement.
The Seller may also offer pricing for the purchase of power
in excess of the agreed maximums. The Power Purchase
Agreement will also allow the minimum obligations, or
capacity scheduled absent energy, to be satisfied through
the payment of dollars. The minimum annual load factor shall
be 80%.
CONTINGENCY: The 200MW will be pro-rated over the three Navajo Generating
Station Units and the two Four Corners Project Units, and
the availability of power and energy to Purchaser under the
Power Purchase Agreement will be contingent on the operation
of each of the five units at a level sufficient to provide
its allocated share of the 200MW ("Unit Availability").
SCHEDULING: The Power Purchase Agreement will include monthly minimum
and maximum capacity factors for scheduling purposes. The
Purhcaser will have the right to schedule capacity and/or
energy on an hourly basis pursuant to the pricing concepts
described above.
BALANCING ACCOUNT: A year-to-year balancing account will be maintained through
which any short falls in energy taken by Purchaser during a
calendar year
<PAGE>
will roll over into the following calendar year at the
previous year's price.
<PAGE>
CHANGES TO 1996 RATE REDUCTION AGREEMENT
MOOT SECTIONS (Not Extended by Instant Agreement):1
Sections 1, 5, 7, 8, 10, 11, 14
MODIFIED SECTIONS (Extended by Instant Agreement with Modifications):
Sections 2, 4, 6, 9, 12, 13
NON-MODIFIED SECTIONS (Extended by Instant Agreement without Modification):2
Sections 3, 15-17
- ---------------------------
1 This includes Sections referring to specific one-time obligations
that have either been fulfilled or which will be fulfilled under terms of
the 1996 Agreement without extension. It also includes sections that have
already been superseded by a subsequent Commission order or orders.
2 Or, alternatively, sections of the 1996 Rate Reduction Agreement
that would have extended beyond the end of the rate mechanism/rate
moratorium provisions in 1999 irrespective of this Agreement.
EXHIBIT C
<PAGE>
R14-2-1616
B. Beginning January 1, 1999, an Affected Utility or Utility Distribution
Company shall not provide competitive services as defined herein, except as
otherwise authorized by these rules or by the Commission. However, this
rule does not preclude an Affected Utility's or Utility Distribution
Company's affiliate from providing competitive services. Nor does this rule
preclude an Affected Utility or Utility Distribution Company from billing
its own customers for distribution service, or from providing billing
services to Electric Service Providers in conjunction with its own billing
or from providing meters for Load Profiled residential customers. Nor does
this rule require an Affected Utility or Utility Distribution Company to
separate such assets or services utilized in these circumstances. Affected
Utilities and Utility Distribution Companies shall provide, if requested by
an ESP or customer, metering, meter reading, billing, and collection
services within their service territories at tariffed rates to customers
that do not have access to these services, during the years 1999 and 2000,
subject to the following limitations. The Affected Utilities and Utility
Distribution Companies shall be allowed to continue to provide metering and
meter reading services within their service territories at tariffed rates
until such time as two competitive ESPs are offering such services to a
particular customer class. When two competitive ESPs are providing such
services to a particular customer class, the Affected Utilities and Utility
Distribution Companies will no longer be allowed to offer the services(s)
to new competitive customers in that customer class, but may continue to
offer the services(s) through December 31, 2000, to the existing
competitive customers signed up prior to the commencement of service by the
two competitive ESPs.
Exhibit D
<PAGE>
BEFORE THE ARIZONA CORPORATION COMMISSION
JIM IRVIN
Commissioner-Chairman
RENZ D. JENNINGS
Commissioner
CARL J. KUNASEK
Commissioner
IN THE MATTER OF THE APPLICATION ) DOCKET NO. E-01345A-98-0473
OF ARIZONA PUBLIC SERVICE )
COMPANY FOR APPROVAL OF ITS )
RECOVERY )
)
- -------------------------------------)
)
IN THE MATTER OF THE FILING OF ) DOCKET NO. E-01345A-97-0773
ARIZONA PUBLIC SERVICE COMPANY )
PURSUANT TO A.A.C. R14-2-1601 ET SEQ.)
)
- -------------------------------------)
)
IN THE MATTER OF COMPETITION IN ) DOCKET NO. RE-00000C-94-0165
THE PROVISION OF ELECTRIC )
SERVICES THROUGHOUT THE STATE ) Decision No. _____________
OF ARIZONA. )
) ORDER
- -------------------------------------)
Open Meeting
- ----------------
Phoenix, Arizona
FINDINGS OF FACT
----------------
1. Arizona Public Service Company ("APS") is an Arizona
corporation providing electric utility service within the State of Arizona.
2. The rates and charges currently in effect for APS were
determined to be just and reasonable in Decision No. 59601, as modified by
Decision Nos. 60216, 60225 and 61103. Decision No. 59601 approved a Settlement
Agreement between Staff and APS which reduced rates.
3. On February 15, 1998, APS filed its proposal for unbundled
tariffs.
4. On August 21, 1998, APS filed its proposal for stranded
cost recovery.
5. Staff and APS have reached agreement on a number of
interrelated issues in the above dockets.
6. The particulars of the agreement are memorialized in a
written Settlement Agreement ("Agreement") dated ____________. Staff and APS
filed the Agreement with the
Exhibit E
<PAGE>
DOCKET NO. E-01345A-98-0473
E-01345A-97-0773
RE-00000C-94-0165
Commission and provided all parties in the above dockets with copies of the
Agreement and proposed Order at the time of filing.
7. A procedural order governing the conduct of this proceeding
was issued. The procedural order did the following: required that APS provide
notice by publication (or other media) of the hearings in these matters, and
established procedures for intervention; established procedures for discovery;
established dates for Staff, APS and intervenors to file testimony or comments;
and set a hearing date at which all parties would be able to present witnesses
and evidence and cross-examine the witnesses of other parties.
8. All intervenors had the opportunity to file testimony or
comments regarding the Agreement, and to present witnesses and exhibits and to
cross-examine witnesses presented by other parties.
9. Commencing on _________, a hearing was held on these
matters at the Commission's offices in Phoenix, Arizona.
10. Staff and APS believe that the Agreement they have reached
is consistent with the best interests of the parties and the public interest
generally. A copy of the Agreement is attached hereto as Exhibit "A".
CONCLUSIONS OF LAW
------------------
1. APS is a public service corporation within the meaning of
Article 15 of the Arizona Constitution and Title 40 of the Arizona Revised
Statutes.
2. The Commission has jurisdiction over APS, over the subject
matter of these proceedings, and over the Agreement submitted by the Staff and
APS.
3. APS provided notice of this matter in accordance with law.
4. The Agreement resolves all matters contained therein in a
manner which is just and reasonable, and which promotes the public interest.
5. The Commission's acceptance and approval of the terms of
the Agreement between Staff and APS are in the public interest.
6. The rates and charges contained in the Agreement are just
and reasonable.
DECISION NO._______________
2
Exhibit E
<PAGE>
DOCKET NO. E-01345A-98-0473
E-01345A-97-0773
RE-00000C-94-0165
7. APS should be directed to file tariffs consistent with the
Agreement and the findings contained herein.
8. The waivers and approvals agreed to in the Agreement should
be approved.
ORDER
-----
IT IS THEREFORE ORDERED that this Order incorporates the
Agreement executed between APS and Staff, and such Order is expressly
conditioned thereon.
IT IS FURTHER ORDERED that the terms and conditions of the
Agreement be and the same are hereby adopted and approved.
IT IS FURTHER ORDERED that the waivers and approvals agreed to
in the Agreement are hereby approved.
IT IS FURTHER ORDERED that APS is authorized and directed to
file schedules of rates and charges consistent with the Findings and Conclusions
of this Order.
IT IS FURTHER ORDERED that this Order shall become effective
immediately.
BY ORDER OF THE ARIZONA CORPORATION COMMISSION
________________________________________________________________________________
Commissioner-Chairman Commissioner Commissioner
IN WITNESS WHEREOF, I, JACK ROSE, 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 ___ day of _____________ 1998.
_______________________________________
JACK ROSE
Executive Secretary
DISSENT__________________
DECISION NO._______________
3
Exhibit E
