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 June 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 1-4473
ARIZONA PUBLIC SERVICE COMPANY
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Arizona 86-0011170
------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 N. 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
--------------------------------------------------
(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 August 14, 2000: 71,264,947
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(A) AND
(B) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE
FORMAT.
<PAGE>
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
Company - Arizona Public Service Company
DOE - United States Department of Energy
EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity -- Issues Related to the Application 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"
EPA - United States Environmental Protection Agency
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
ITC - Investment tax credit
MW - Megawatts
NGS - Navajo Generating Station
1999 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1999
Settlement Agreement - APS' Settlement Agreement approved by the ACC in 1999
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
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
<PAGE>
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended June 30,
----------------------
2000 1999
--------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES .......................... $ 719,394 $ 511,434
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ....................... 73,808 58,283
Purchased power .................................... 215,095 76,473
--------- ---------
Total ........................................... 288,903 134,756
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES ................ 430,491 376,678
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses . 104,583 106,434
Depreciation and amortization ...................... 96,526 96,533
Income taxes ....................................... 71,441 49,856
Other taxes ........................................ 25,596 25,352
--------- ---------
Total ........................................... 298,146 278,175
--------- ---------
OPERATING INCOME ..................................... 132,345 98,503
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ........................................ (1,940) (1,485)
Income taxes ....................................... 801 7,227
--------- ---------
Total ........................................... (1,139) 5,742
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .................... 131,206 104,245
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ......................... 32,607 33,868
Interest on short-term borrowings .................. 3,853 1,936
Debt discount, premium and expense ................. 1,575 1,912
Capitalized interest ............................... (2,680) (3,013)
--------- ---------
Total ........................................... 35,355 34,703
--------- ---------
EARNINGS FOR COMMON STOCK ............................ $ 95,851 $ 69,542
========= =========
See Notes to Condensed Financial Statements.
<PAGE>
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Six Months
Ended June 30,
------------------------
2000 1999
----------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ........................ $ 1,165,375 $ 925,417
----------- ---------
FUEL EXPENSES:
Fuel for electric generation ..................... 132,619 110,399
Purchased power .................................. 282,048 124,703
----------- ---------
Total ......................................... 414,667 235,102
----------- ---------
OPERATING REVENUES LESS FUEL EXPENSES .............. 750,708 690,315
----------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses 213,111 206,696
Depreciation and amortization .................... 192,473 192,672
Income taxes ..................................... 95,708 74,659
Other taxes ...................................... 50,977 50,829
----------- ---------
Total ......................................... 552,269 524,856
----------- ---------
OPERATING INCOME ................................... 198,439 165,459
----------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ...................................... (312) (4,419)
Income taxes ..................................... 126 11,482
----------- ---------
Total ......................................... (186) 7,063
----------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .................. 198,253 172,522
----------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ....................... 65,945 67,424
Interest on short-term borrowings ................ 5,120 4,004
Debt discount, premium and expense ............... 3,468 3,757
Capitalized interest ............................. (4,906) (5,999)
----------- ---------
Total ......................................... 69,627 69,186
----------- ---------
NET INCOME ......................................... 128,626 103,336
PREFERRED STOCK DIVIDEND REQUIREMENTS .............. -- 1,016
----------- ---------
EARNINGS FOR COMMON STOCK .......................... $ 128,626 $ 102,320
=========== =========
See Notes to Condensed Financial Statements
<PAGE>
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Twelve Months
Ended June 30,
---------------------------
2000 1999
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
ELECTRIC OPERATING REVENUES .................... $ 2,532,755 $ 2,109,677
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ................. 266,069 241,604
Purchased power .............................. 708,991 366,155
----------- -----------
Total ..................................... 975,060 607,759
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES .......... 1,557,695 1,501,918
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel
expenses..................................... 444,156 423,452
Depreciation and amortization ................ 381,858 384,433
Income taxes ................................. 213,064 202,469
Other taxes .................................. 96,714 100,134
----------- -----------
Total ..................................... 1,135,792 1,110,488
----------- -----------
OPERATING INCOME ............................... 421,903 391,430
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net .................................. (7,430) (11,807)
Income taxes ................................. 21,171 32,291
----------- -----------
Total ..................................... 13,741 20,484
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS .............. 435,644 411,914
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ................... 131,197 135,295
Interest on short-term borrowings ............ 9,388 8,425
Debt discount, premium and expense ........... 7,034 7,470
Capitalized interest ......................... (5,586) (13,741)
----------- -----------
Total ..................................... 142,033 137,449
----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE ............. 293,611 274,465
Extraordinary charge - net of income
taxes of $94,115............................. 139,885 --
----------- -----------
NET INCOME ..................................... 153,726 274,465
PREFERRED STOCK DIVIDEND REQUIREMENTS .......... -- 5,406
----------- -----------
EARNINGS FOR COMMON STOCK ...................... $ 153,726 $ 269,059
=========== ===========
</TABLE>
See Notes to Condensed Financial Statements
<PAGE>
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Unaudited)
June 30, December 31,
2000 1999
----------- -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for
future use ................................ $ 7,671,230 $ 7,545,575
Less accumulated depreciation and
amortization .............................. 3,139,302 3,026,041
----------- -----------
Total ................................... 4,531,928 4,519,534
Construction work in progress .............. 195,770 184,764
Nuclear fuel, net of amortization .......... 47,864 49,114
----------- -----------
Utility plant - net ..................... 4,775,562 4,753,412
----------- -----------
INVESTMENTS AND OTHER ASSETS ................. 230,950 208,457
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents .................. 8,172 7,477
Accounts receivable:
Service customers ....................... 307,572 201,704
Other ................................... 57,822 35,684
Allowance for doubtful accounts ......... (1,566) (1,538)
Accrued utility revenues ................... 112,261 72,919
Materials and supplies, at average cost .... 73,038 69,977
Fossil fuel, at average cost ............... 18,727 21,869
Deferred income taxes ...................... 8,163 8,163
Other ...................................... 40,096 30,885
----------- -----------
Total current assets .................... 624,285 447,140
----------- -----------
DEFERRED DEBITS:
Regulatory assets .......................... 545,622 613,729
Unamortized debt issue costs ............... 11,664 15,172
Other ...................................... 75,760 79,714
----------- -----------
Total deferred debits ................... 633,046 708,615
----------- -----------
TOTAL ................................... $ 6,263,843 $ 6,117,624
=========== ===========
See Notes to Condensed Financial Statements.
<PAGE>
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES
(Unaudited)
June 30, December 31,
2000 1999
---------- ------------
(Thousands of Dollars)
CAPITALIZATION:
Common stock ...................................... $ 178,162 $ 178,162
Additional paid-in capital ........................ 1,246,804 1,246,804
Retained earnings ................................. 559,333 558,208
---------- ----------
Common stock equity ............................ 1,984,299 1,983,174
Long-term debt less current maturities ............ 1,756,388 1,997,400
---------- ----------
Total capitalization ........................... 3,740,687 3,980,574
---------- ----------
CURRENT LIABILITIES:
Commercial paper .................................. 200,875 38,300
Current maturities of long-term debt .............. 114,886 114,711
Accounts payable .................................. 222,977 170,662
Accrued taxes ..................................... 189,552 62,858
Accrued interest .................................. 31,361 32,299
Common dividends payable .......................... 85,000 --
Customer deposits ................................. 25,016 24,682
Other ............................................. 34,095 26,248
---------- ----------
Total current liabilities ...................... 903,762 469,760
---------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ............................. 1,143,153 1,178,085
Unamortized gain - sale of utility plant .......... 70,924 73,212
Customer advances for construction ................ 40,409 38,150
Other ............................................. 364,908 377,843
---------- ----------
Total deferred credits and other ............... 1,619,394 1,667,290
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 9)
TOTAL .......................................... $6,263,843 $6,117,624
========== ==========
See Notes to Condensed Financial Statements.
<PAGE>
-7-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months
Ended June 30,
---------------------
2000 1999
--------- ---------
(Thousands of Dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................ $ 128,626 $ 103,336
Items not requiring cash:
Depreciation and amortization ....................... 192,473 192,672
Nuclear fuel amortization ........................... 15,124 15,673
Deferred income taxes - net ......................... (22,609) (21,445)
Changes in certain current assets and liabilities:
Accounts receivable - net ........................... (127,978) 32,376
Accrued utility revenues ............................ (39,342) (30,306)
Materials, supplies and fossil fuel ................. 81 (5,653)
Other current assets ................................ (9,211) (3,952)
Accounts payable .................................... 56,919 (17,952)
Accrued taxes ....................................... 126,694 89,322
Accrued interest .................................... (938) 991
Other current liabilities ........................... 8,181 (2,416)
Other - net ........................................... (7,979) (19,457)
--------- ---------
Net cash flow provided by operating activities.... 320,041 333,189
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures .................................. (189,401) (153,730)
Capitalized interest .................................. (4,906) (5,999)
Other ................................................. (3,114) 1,172
--------- ---------
Net cash flow used for investing activities ...... (197,421) (158,557)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt ........................................ -- 142,952
Short-term borrowings - net ........................... 162,575 45,120
Dividends paid on common stock ........................ (42,500) (42,500)
Dividends paid on preferred stock ..................... -- (1,393)
Repayment of preferred stock .......................... -- (96,499)
Repayment and reacquisition of long-term debt ......... (242,000) (216,184)
--------- ---------
Net cash flow used for financing activities...... (121,925) (168,504)
--------- ---------
Net increase in cash and cash equivalents .............. 695 6,128
Cash and cash equivalents at beginning of period ....... 7,477 5,558
--------- ---------
Cash and cash equivalents at end of period ............. $ 8,172 $ 11,686
========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (excluding capitalized interest) .......... $ 64,470 $ 64,233
Income taxes ....................................... $ -- $ 7,849
See Notes to Condensed Financial Statements.
<PAGE>
-8-
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Our unaudited condensed financial statements reflect all adjustments which we
believe are necessary for the fair presentation of our financial position and
results of operations for the periods presented. These adjustments are of a
normal recurring nature with the exception of the extraordinary charge. We
suggest that these Condensed Financial Statements and Notes to Condensed
Financial Statements be read along with the Financial Statements and Notes to
Financial Statements included in our 1999 10-K. We have reclassified certain
prior year amounts to conform to the current year presentation.
2. Weather conditions and wholesale power marketing and trading activities can
have significant impacts on our results for interim periods. For these and other
reasons, results for interim periods do not necessarily represent results to be
expected for the year.
3. We are a wholly owned subsidiary of Pinnacle West.
4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
changes in capitalization for the six months ended June 30, 2000.
5. Regulatory Accounting
For regulated operations, we prepare our financial statements in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based,
rate-regulated enterprise to reflect the impact of regulatory decisions in its
financial statements.
During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be
discontinued no later than when legislation is passed or a rate order is issued
that contains sufficient detail to determine its effect on the portion of the
business being deregulated, which could result in write-downs or write-offs of
physical and/or regulatory assets. Additionally, the EITF determined that
regulatory assets should not be written off if they are to be recovered from a
portion of the entity which continues to apply SFAS No. 71.
The Settlement Agreement was approved by the ACC in September 1999 (see Note 6
for a discussion of the agreement). Consequently, we have discontinued the
application of SFAS No. 71 for our generation operations. This means that the
generation assets were tested for impairment and the portion of regulatory
assets deemed to be unrecoverable through ongoing regulated cash flows was
eliminated. We determined that the generation assets were not impaired. A
regulatory disallowance removed $234 million pretax ($183 million net present
value) from ongoing regulatory cash flows and was recorded as a net reduction of
regulatory assets. This reduction ($140 million after income taxes) was reported
as an extraordinary charge on the income statement during the third quarter of
1999. Prior to the Settlement Agreement, under the 1996 regulatory agreement
(see Note 6), the ACC accelerated the amortization of substantially all of our
regulatory assets to an eight-year period ending June 30, 2004.
The regulatory assets to be recovered under the 1999 Settlement Agreement are
now being amortized as follows (millions of dollars):
<PAGE>
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1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
----- ----- ----- ----- ----- ----- ----
$ 164 $ 158 $ 145 $ 115 $ 86 $ 18 $686
The majority of our regulatory assets relate to deferred income taxes and rate
synchronization cost deferrals.
The condensed balance sheets include the amounts listed below for generation
assets not subject to SFAS No. 71 (thousands of dollars):
June 30, December 31,
2000 1999
----------- -----------
Electric plant in service & held for future use $ 3,761,855 $ 3,770,234
Accumulated depreciation and amortization (1,678,752) (1,641,855)
Construction work in progress 85,220 67,306
Nuclear fuel, net of amortization 47,864 49,114
6. Regulatory Matters - Electric Industry Restructuring
STATE
SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive
Settlement Agreement with various parties, including representatives of major
consumer groups, related to the implementation of retail electric competition.
On September 23, 1999, the ACC voted to approve the Settlement Agreement, with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement Agreement. One of the parties questioned
the authority of the ACC to approve the Settlement Agreement and both parties
challenged several specific provisions of the Settlement Agreement. A decision
on the appeals to the Settlement Agreement is not expected until later this year
or next year.
The following are the major provisions of the Settlement Agreement, as approved:
* We will reduce rates for standard offer service for customers with
loads less than 3 megawatts in a series of annual retail electric
price reductions of 1.5% beginning July 1, 1999 through July 1, 2003,
for a total of 7.5%. The first reduction of approximately $24 million
($14 million after income taxes) included the July 1, 1999 retail
price decrease of approximately $11 million annually ($7 million after
income taxes) related to the 1996 regulatory agreement. See "1996
Regulatory Agreement" below. Based on the price reduction authorized
in the Settlement Agreement, there was a retail price decrease of
approximately $28 million ($17 million after taxes), or 1.5%,
effective July 1, 2000. For customers having loads 3 megawatts or
greater, standard offer rates will be reduced in varying annual
increments that total 5% through 2002.
<PAGE>
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* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the Settlement Agreement, retroactive to July 1, 1999, and
also will be subject to annual reductions beginning January 1, 2000,
that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
limited circumstances. Neither the ACC nor the Company will be
prevented from seeking or authorizing rate changes prior to July 1,
2004 in the event of conditions or circumstances that constitute an
emergency, such as an inability to finance on reasonable terms, or
material changes in our cost of service for ACC-regulated services
resulting from federal, tribal, state or local laws, regulatory
requirements, judicial decisions, actions or orders.
* We will be permitted to defer for later recovery prudent and
reasonable costs of complying with the ACC electric competition rules,
system benefits costs in excess of the levels included in current
rates, and costs associated with our "provider of last resort" and
standard offer obligations for service after July 1, 2004. These costs
are to be recovered through an adjustment clause or clauses commencing
on July 1, 2004.
* Our distribution system opened for retail access effective September
24, 1999. Customers will be eligible for retail access in accordance
with the phase-in adopted by the ACC under the electric competition
rules (see "Retail Electric Competition Rules" below), with an
additional 140 megawatts being made available to eligible
non-residential customers. Unless subject to judicial or regulatory
restraint, we will open our distribution system to retail access for
all customers on January 1, 2001.
* Prior to the Settlement Agreement, we were recovering substantially
all of our regulatory assets through July 1, 2004, pursuant to the
1996 regulatory agreement. In addition, the Settlement Agreement
states that we have demonstrated that our allowable stranded costs,
after mitigation and exclusive of regulatory assets, are at least $533
million net present value. We will not be allowed to recover $183
million net present value of the above amounts. The Settlement
Agreement provides that we will have the opportunity to recover $350
million net present value through a competitive transition charge
(CTC) that will remain in effect through December 31, 2004, at which
time it will terminate. Any over/under-recovery will be credited/
debited against the costs subject to recovery under the adjustment
clause described above.
* We will form a separate corporate affiliate or affiliates and transfer
to that affiliate(s) our generating assets and competitive services at
book value as of the date of transfer, which transfer shall take place
no later than December 31, 2002. We will be allowed to defer and later
collect, beginning July 1, 2004, sixty-seven percent of our costs to
accomplish the required transfer of generation assets to an affiliate.
* When the Settlement Agreement approved by the ACC is no longer subject
to judicial review, we will move to dismiss all of our litigation
pending against the ACC as of the date we entered into the Settlement
Agreement. To protect our rights, we have several lawsuits pending on
ACC orders relating to stranded cost recovery and
<PAGE>
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the adoption and amendment of the ACC's electric competition rules,
which would be voluntarily dismissed at the appropriate time under
this provision.
As discussed in Note 5 above, we have discontinued the application of SFAS No.
71 for our generation operations.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve the rules that provide a framework for the introduction of retail
electric competition in Arizona (Rules). If any of the Rules conflict with the
Settlement Agreement, the terms of the Settlement Agreement govern. On December
8, 1999, we filed a lawsuit to protect our legal rights regarding the Rules.
This lawsuit is pending, along with several other lawsuits on ACC orders
relating to stranded cost recovery and the adoption or amendment of the Rules,
but two related cases filed by other utilities have been partially decided in a
manner adverse to those utilities' positions.
On July 12, 2000, a Maricopa County Superior Court judge issued a preliminary
ruling in favor of the ACC and denied substantive challenges to the Rules that
had been made by the electric cooperatives. However, he concluded that some of
the Rules were invalid because of procedural deficiencies. Specifically, the
judge concluded that several non-ratemaking Rules were required to be presented
to the Arizona Attorney General for certification. Additionally, the judge
determined that the Arizona Constitution requires the ACC to make findings
regarding the fair value of property in Arizona of competitive electric service
providers. We do not believe that the ruling affects the Settlement Agreement
with the ACC. The Settlement Agreement was not at issue in the consolidated
cases before the judge. Further, the ACC made findings related to fair value of
our property in the order approving our Settlement Agreement.
The ruling does not immediately affect the Rules. We expect that, in the next
few weeks, the court will consider proposed forms of judgment which will
establish the specific impact of the ruling. Although the ACC has not yet
indicated what steps it intends to take after a judgment is issued, the ACC
could appeal the ruling to the Court of Appeals or could elect to take
corrective action to correct the procedural deficiencies identified in the
judge's ruling. The cooperatives may also appeal the ruling. There is authority
indicating that if the order is appealed by the ACC, it will be automatically
stayed pending further judicial review. Certain other appeals of the Rules are
still pending in the Maricopa County Superior Court. We believe that the court
may rule on the remaining appeals later this year or next year.
On January 14, 2000, a special action was filed requesting the Arizona Supreme
Court to enjoin implementation of the Rules and decide whether the ACC can allow
the competitive marketplace, rather than the ACC, to set just and reasonable
rates under the Arizona Constitution. The issue of competitively set rates has
been decided by lower Arizona courts in favor of the ACC in four separate
lawsuits, two of which relate to telecommunications companies. The Supreme Court
denied to hear the case as a special action on March 17, 2000. The lower court
litigation will continue.
The Rules approved by the ACC include the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by
the ACC, including us.
* The Rules require each affected utility, including us, to make
available at least 20% of its 1995 system retail peak demand for
competitive generation supply beginning
<PAGE>
-12-
when the ACC makes a final decision on each utility's stranded costs
and unbundled rates (Final Decision Date) or January 1, 2001,
whichever is earlier, and 100% beginning January 1, 2001. Under the
Settlement Agreement, we will provide retail access to customers
representing the minimum 20% required by the ACC and an additional 140
megawatts of non-residential load in 1999, and to all customers as of
January 1, 2001, or such other dates as approved by the ACC.
* Subject to the 20% requirement, all utility customers with single
premise loads of one megawatt or greater will be eligible for
competitive electric services on the Final Decision Date, which for
our customers was the approval of the Settlement Agreement. Customers
may also aggregate smaller loads to meet this one megawatt
requirement.
* When effective, residential customers will be phased in at 1.25% per
quarter calculated beginning on January 1, 1999, subject to the 20%
requirement above.
* Electric service providers that get Certificates of Convenience and
Necessity (CC&Ns) from the ACC can supply only competitive services,
including electric generation, but not electric transmission and
distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
non-competitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
generation assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the Settlement Agreement, we
received a waiver to allow transfer of our competitive generation
assets and services to affiliates no later than December 31, 2002.
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and us. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (millions of dollars):
Annual Electric Percentage
Revenue Decrease Decrease Effective Date
---------------- -------- --------------
$49 3.4% July 1, 1996
$18 1.2% July 1, 1997
$17 1.1% July 1, 1998
$11 0.7% July 1, 1999 (a)
(a) Included in the first rate reduction under the Settlement Agreement
(see above).
The regulatory agreement also required the parent company to infuse $200 million
of common equity into us in annual payments of $50 million from 1996 through
1999. All of these equity infusions were made by December 31, 1999.
<PAGE>
-13-
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River
Project) and, at their option, smaller municipal electric systems must
(i) make at least 20% of their 1995 retail peak demand available to
electric service providers by December 31, 1998 and for all retail
customers by December 31, 2000; (ii) decrease rates by at least 10%
over a ten-year period beginning as early as January 1, 1991; (iii)
implement procedures and public processes comparable to those already
applicable to public service corporations for establishing the terms,
conditions, and pricing of electric services as well as certain other
decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt
River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive
basis during the first two years of competition only for customers
having demands in excess of one megawatt (and that are eligible for
competitive generation services), and thereafter for all customers
receiving competitive electric generation.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, or results of operations. As competition in the
electric industry continues to evolve, we will continue to evaluate strategies
and alternatives that will position us to compete in the new regulatory
environment.
FEDERAL
The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted
increased competition in the wholesale electric power markets. We do not expect
these rules to have a material impact on our financial statements.
Several electric utility industry restructuring bills have been introduced
during the current congressional session. Several of these bills are written to
allow consumers to choose their electricity suppliers beginning in 2000 and
beyond. These bills, other bills that are expected to be introduced, and ongoing
discussions at the federal level suggest a wide range of opinion that will need
to be narrowed before any comprehensive restructuring of the electric utility
industry can occur.
7. Nuclear Insurance
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, we
could be assessed retrospective premium adjustments. The maximum assessment per
reactor under the program for each nuclear incident is approximately $88
million, subject to an annual limit of $10 million per incident. Based upon our
29.1% interest in the three Palo Verde units, our maximum potential assessment
per
<PAGE>
-14-
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 stabilization and decontamination. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
8. Business Segments
We have two principal business segments (determined by products, services and
regulatory environment) which consist of the transmission and distribution of
electricity and wholesale power marketing and trading activities (delivery
business segment) and the generation of electricity (generation business
segment). We plan to move our wholesale power marketing and trading activities
to Pinnacle West by the end of 2000. Eliminations primarily relate to
intersegment sales of electricity. Segment information for the three, six and
twelve months ended June 30, 2000 and 1999 is as follows (millions of dollars):
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------- ----------------- -------------------
2000 1999 2000 1999 2000 1999
----- ----- ------- ----- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Delivery $ 719 $ 511 $ 1,165 $ 925 $ 2,533 $ 2,110
Generation 249 220 428 396 886 877
Eliminations (249) (220) (428) (396) (886) (877)
----- ----- ------- ----- ------- -------
Total $ 719 $ 511 $ 1,165 $ 925 $ 2,533 $ 2,110
===== ===== ======= ===== ======= =======
Earnings excluding Extraordinary
Charge:
Delivery $ 55 $ 34 $ 80 $ 55 $ 172 $ 144
Generation 41 36 49 47 122 125
----- ----- ------- ----- ------- -------
Total $ 96 $ 70 $ 129 $ 102 $ 294 $ 269
===== ===== ======= ===== ======= =======
As of June 30, As of December 31,
2000 1999
------ ------
Assets:
Delivery $3,938 $3,796
Generation 2,326 2,322
------ ------
Total $6,264 $6,118
====== ======
</TABLE>
9. Accounting Matters
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended,
which is effective for us in 2001. SFAS No. 133 requires that entities recognize
all derivatives as either assets or
<PAGE>
-15-
liabilities on the balance sheet and measure those instruments at fair value.
The standard also provides specific guidance for accounting for derivatives
designated as hedging instruments. We are currently evaluating what impact this
standard will have on our financial statements.
<PAGE>
-16-
ARIZONA PUBLIC SERVICE COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
In this section, we explain our results of operations, general financial
condition, and outlook including:
* the changes in our earnings for the periods presented
* the factors impacting our business, including competition
* the effects of regulatory decisions on our results and outlook
* our capital needs and resources and
* our management of market risks.
We are Arizona's largest electric utility, providing retail and wholesale
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate, sell, and deliver electricity to
wholesale customers in the western United States.
We suggest this section be read along with the 1999 10-K. Throughout this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, we refer to specific "Notes" in the Notes to Condensed Financial
Statements. These Notes add further details to the discussion.
OPERATING RESULTS
The following table summarizes our revenues and earnings for the three-month,
six-month and twelve-month periods ended June 30, 2000 and 1999:
Periods ended June 30
(Unaudited)
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
------------------- -------------------- -------------------------
2000 1999 2000 1999 2000 1999
-------- -------- ---------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $719,394 $511,434 $1,165,375 $925,417 $2,532,755 $2,109,677
Earnings for Common Stock $ 95,851 $ 69,542 $ 128,626 $102,320 $ 153,726(1) $ 269,059
</TABLE>
(1) The twelve months ended June 30, 2000 includes an extraordinary charge of
$139,885 net of income taxes of $94,115.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED JUNE 30, 2000 COMPARED WITH
THREE-MONTH PERIOD ENDED JUNE 30, 1999
Earnings for the three months ended June 30, 2000 were $96 million compared with
$70 million for the same period in the prior year. Earnings increased for the
three-month period
<PAGE>
-17-
primarily because of an increase in the profitability of wholesale power
marketing and trading activities and increases in the number of customers and in
the average amount of electricity used by customers. These positive factors more
than offset decreases due to the effects of increased fuel and purchased power
costs, the completion of the amortization of ITCs in 1999, and an electricity
price reduction. See Note 6 for information on the price reduction. See "Income
Taxes" below for a discussion of the ITC amortization.
Electric operating revenues increased $208 million because of:
* increased power marketing and trading revenues ($150 million)
* increases in the number of customers and the average amount of
electricity used by customers ($44 million)
* warmer weather impacts ($18 million) and
* miscellaneous factors ($3 million).
As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail electricity prices ($7 million).
The increase in power marketing and trading revenues resulted from higher prices
and increased activity in the western U.S. wholesale power markets. The revenues
were accompanied by an increase in purchased power and fuel expenses of $105
million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased fuel prices.
OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 2000 COMPARED WITH
SIX-MONTH PERIOD ENDED JUNE 30, 1999
Earnings for the six months ended June 30, 2000 were $129 million compared with
$102 million for the same period in the prior year. The increase primarily
relates to an increase in the profitability of wholesale power marketing and
trading activities, and increases in the number of customers and in the average
amount of electricity used by customers. These positive factors more than offset
decreases due to the effects of increased fuel and purchased power costs, the
completion of the amortization of ITCs in 1999, an electricity price reduction,
and higher utility operations and maintenance expense. See Note 6 for
information on the price reduction. See "Income Taxes" below for a discussion of
the ITC amortization.
Electric operating revenues increased $240 million because of:
* increased power marketing and trading revenues ($173 million)
* increases in the number of customers and the average amount of
electricity used by customers ($55 million)
* warmer weather impacts ($19 million) and
* miscellaneous factors ($6 million).
These positive factors were partially offset by the effect of a reduction in
retail electricity prices ($13 million).
<PAGE>
-18-
The increase in power marketing and trading revenues resulted from higher prices
and increased activity in the western U.S. wholesale power markets. The revenues
were accompanied by an increase in purchased power and fuel expenses of $129
million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased fuel prices.
Utility operations and maintenance expenses increased primarily because of
higher costs related to customer growth.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 2000 COMPARED WITH
TWELVE-MONTH PERIOD ENDED JUNE 30, 1999
Earnings for the twelve months ended June 30, 2000 were $154 million compared
with $269 million for the same period in the prior year. The decrease primarily
relates to an extraordinary charge recorded in the third quarter of 1999,
partially offset by higher income excluding the extraordinary charge.
The extraordinary charge related to a regulatory disallowance that resulted from
our comprehensive Settlement Agreement that was approved by the ACC in September
1999. See Notes 5 and 6 for additional information about the regulatory
disallowance and the Settlement Agreement.
Earnings excluding the extraordinary charge increased $25 million over the
comparable prior period primarily because of increases in the number of
customers and in the average amount of electricity used by customers, and an
increase in the profitability of wholesale power marketing and trading
activities. These positive factors more than offset decreases due to a reduction
in retail electricity prices, higher utility operations and maintenance expense,
and the completion of the amortization of ITCs in 1999. See Note 6 for
information on the price reduction. See "Income Taxes" below for a discussion of
the ITC amortization.
Electric operating revenues increased $423 million because of:
* increased power marketing and trading revenues ($338 million)
* increases in the number of customers and the average amount of
electricity used by customers ($94 million) and
* miscellaneous factors ($18 million).
These positive factors were partially offset by the effect of a reduction in
retail prices ($27 million).
The increase in power marketing and trading revenues resulted primarily from
increased activity in western U.S. wholesale power markets and higher prices.
The revenues were accompanied by increases in purchased power and fuel expenses
of $306 million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased fuel prices.
Utility operations and maintenance expenses increased primarily because of $16
million of non-recurring items recorded in the current twelve-month period,
including a provision for
<PAGE>
-19-
certain environmental costs. Other increases primarily related to customer
growth, power marketing costs, and technology related costs.
INCOME TAXES
As part of a 1994 rate settlement with the ACC, we accelerated amortization of
substantially all deferred ITCs over a five-year period that ended on December
31, 1999. The ITC amortization decreased annual income tax expense by
approximately $28 million. Beginning in 2000, no further benefits from these
deferred ITCs will be reflected in income tax expense.
LIQUIDITY AND CAPITAL RESOURCES
For the six months ended June 30, 2000, we incurred approximately $181 million
in capital expenditures, which is approximately 48% of the most recently
estimated 2000 capital expenditures. Our projected capital expenditures for the
next three years are $380 million in 2000; $395 million in 2001; and $373 in
2002. These amounts include about $30 - $35 million each year for nuclear fuel
expenditures.
Our long-term debt redemption requirements, optional repayments on long-term
debt, and payment obligations on a capitalized lease are: $354 million in 2000;
$252 million in 2001; and $125 million in 2002. During the six months ended June
30, 2000, we redeemed approximately $242 million of our long-term debt with cash
from operations and short-term borrowings. On August 7, 2000, we issued $300
million of our 7-5/8% Notes Due 2005.
In 2001 we will purchase Units 1, 2 and 3 of the West Phoenix Power Plant at the
expiration of its lease term.
Although provisions in our first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds and preferred stock that we may issue, we do not expect any
of these provisions to limit our ability to meet our capital requirements.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 for a discussion of regulatory accounting. See Note 6 for a
discussion of a Settlement Agreement related to the implementation of retail
electric competition and to Arizona and federal legal and regulatory
developments.
RATE MATTERS
See Note 6 for a discussion of a price reduction effective as of July 1, 2000,
and for a discussion of a Settlement Agreement that will, among other things,
result in five annual price reductions over a four-year period ending July 1,
2003.
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;
<PAGE>
-20-
the outcome of the regulatory proceedings relating to the restructuring;
regulatory, tax, and environmental legislation; our ability to successfully
compete outside traditional regulated markets; regional economic conditions,
which could affect customer growth; the cost of debt and equity capital; weather
variations affecting customer usage; successfully managing market risks; and
technological developments in the electric industry.
These factors and the other matters discussed above may cause future results to
differ materially from historical results, or from results or outcomes we
currently expect or seek.
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in commodity
prices, interest rates, and investments held by the nuclear decommissioning
trust fund.
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage our risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into these
derivative transactions to hedge purchases and sales of electricity, fuels and
emissions allowances/credits. In addition, we engage in trading activities
intended to profit from favorable movements of market prices.
As of June 30, 2000, a hypothetical adverse price movement of 10% in the market
price of our commodity derivative portfolio would decrease the fair market value
of these contracts by approximately $53 million. This analysis does not include
the favorable impact this same hypothetical price move would have on the
underlying physical exposures being hedged with the commodity derivative
portfolio. We plan to move our wholesale power marketing and trading activities
to Pinnacle West by the end of 2000.
We are exposed to credit losses in the event of non-performance or non-payment
by counterparties. We use a credit management process to assess and monitor the
financial exposure of counterparties. Despite the fact that the great majority
of our trading counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could
default, resulting in a material impact on earnings for a given period.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by the nuclear decommissioning trust fund. Our policy is to
manage interest rates through the use of a combination of fixed-rate and
floating-rate debt. The nuclear decommissioning fund also has risks associated
with changing market values of equity investments. Nuclear decommissioning costs
are recovered in regulated electricity prices.
<PAGE>
-21-
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 construction and financing programs of the Company.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 6 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 and a settlement agreement with the
ACC.
ENVIRONMENTAL MATTERS
EPA Environmental Regulation - Clean Air Act
As previously reported, EPA's final National Ambient Air Quality Standards for
ozone and particulate matter were challenged, and the court determined that
EPA's promulgation of the standards violated the constitutional prohibition on
delegation of legislative power. See "Environmental Matters--EPA Environmental
Regulation--Clean Air Act" in Part I, Item 1 of the 1999 10-K. The court
remanded the ozone and fine particulate standards and vacated the coarse
particulate matter standard. The U.S. Supreme Court recently agreed to review
these decisions. We cannot currently predict the outcome of this matter.
Purported Navajo Environmental Regulation
In April 2000, the Navajo Tribal Council approved operating permit regulations
under the Navajo Nation Air Pollution Prevention and Control Act. We believe
that the regulations do not recognize that the Tribe did not intend to assert
jurisdiction over Four Corners and NGS. On July 12, 2000, the Four Corners
participants and the NGS participants each filed a petition with the Navajo
Supreme Court for review of the operating permit regulations. We cannot
currently predict the outcome of this matter.
As previously reported, in April 1999, we filed a Petition for Review of EPA's
regulations regarding issuing Federal operating permits to cover stationary
sources on Indian reservations. See "Environmental Matters--Purported Navajo
Environmental Regulation" in Part I, Item 1 of the 1999 10-K. On June 29, 2000,
at the request of the Court, we filed a motion to dismiss Four Corners from this
petition on the grounds that the impact of the regulations on pre-existing
binding agreements was not "ripe" for judicial resolution based on EPA's
issuance of an official notice indicating that it had not yet determined whether
the pre-existing binding agreements with Four Corners and NGS were abrogated by
the Clean Air Act.
<PAGE>
-22-
WATER SUPPLY
As previously reported, we and other parties petitioned the U.S. Supreme Court
for review of the decision confirming that certain groundwater rights may be
available to the federal government and Indian tribes. See "Water Supply" in
Item I, Part 1 of the 1999 10-K. This petition was denied, and the pending lower
court litigation will continue.
PURCHASED POWER AGREEMENTS
As previously reported, in September 1990, we entered into a thirty year
agreement under which we and Pacificorp engage in a one-for-one seasonal
capacity exchange. We are entitled to receive up to 480 MW of capacity from
PacifiCorp during our summer peak season (through September 15). See "Generating
Fuel and Purchased Power - Purchased Power Agreements" in Part I, Item 1 of the
1999 10-K. There is currently a dispute under the Long-Term Power Transaction
Agreement (the "Agreement") relating to the value of power delivered to
PacifiCorp under the Supplemental Energy provisions of the Agreement. As a
result of the dispute, we understand that PacificCorp believes it is owed monies
by us and, since August 8, 2000, has been withholding power due to us under the
terms of Agreement. We believe PacificCorp is in breach of the Agreement, and
the breach has been and is resulting in damage claims against PacifiCorp which
are accruing daily in an amount dependent upon daily energy cost rates. The
parties are currently attempting to resolve the dispute and no litigation or
arbitration has been commenced.
<PAGE>
-23-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
27.1 Financial Data Schedule
In addition to those Exhibits shown above, the Company hereby incorporates the
following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation
ss.229.10(d) by reference to the filings set forth below:
<TABLE>
<CAPTION>
Exhibit No. Description Originally Filed as Exhibit: File No.(a) Date Effective
----------- ----------- ---------------------------- -------- --------------
<S> <C> <C> <C> <C>
10.1 Articles of Incorporation 4.2 to Form S-3 Registration 1-4473 9-29-93
restated as of May 25, 1988 Nos. 33-33910 and 33-55248
by means of September 24,
1993 Form 8-K Report
10.2 Bylaws, amended as of 3.1 to 1995 Form 10-K Report 1-4473 3-29-96
February 20, 1996
10.3 Amendment No. 14 to the 10.4 to the Pinnacle West 1-8962 8-14-00
ANPP Participation June 30, 2000 Form
Agreement 10-Q Report
10.4 Pinnacle West Capital 99.2 to Pinnacle West's 1-8962 7-3-00
Corporation and Arizona Registration Statement on
Public Service Company Form S-8 No. 333-40796
Directors' Retirement Plan
(as Amended and Restated)
</TABLE>
(b) Reports on Form 8-K
During the quarter ended June 30, 2000, and the period from July 1 through
August 14, 2000, we filed the following reports on Form 8-K.
Report dated July 12, 2000, relating to a preliminary ruling issued by a
Maricopa County Superior Court judge on cross-motions for summary judgment in
connection with lawsuits filed relating to the adoption or amendment of the
retail electric competition rules.
Report dated August 2, 2000 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-58445 and 333-94277) relating to
the Company's offering of $300 million of Notes.
----------
(a) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
<PAGE>
-24-
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: August 14, 2000 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)
