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 March 31, 2001
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)
(602) 250-1000
(Registrant's telephone number, including area code)
(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 May 15, 2001: 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.
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
APS Energy Services - APS Energy Services Company, Inc., a subsidiary of
Pinnacle West
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Arizona Public Service Company
DIG - Derivatives Implementation Group
EITF - Emerging Issues Task Force
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
ISO - California Independent System Operator
ITC - investment tax credit
KW - kilowatt, one thousand watts
KWh - kilowatt-hour, one thousand watts per hour
MW - megawatt, one million watts
MWh - megawatt-hour, one million watts per hour
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
Palo Verde - Palo Verde Nuclear Generating Station
PG&E - PG&E Corp.
Pinnacle West - Pinnacle West Capital Corporation
Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West
subsidiary
PX - California Power Exchange
Rules - ACC retail electric competition rules
SCE - Southern California Edison
SFAS- Statement of Financial Accounting Standards
Salt River Project - Salt River Project Agricultural Improvement and Power
District
2000 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 2000
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended March 31,
---------------------------
2001 2000
--------- ---------
(dollars in thousands)
ELECTRIC OPERATING REVENUES ............................................ $ 681,271 $ 445,981
--------- ---------
FUEL AND PURCHASED POWER COSTS:
Fuel for electric generation ......................................... 121,179 58,246
Purchased power ...................................................... 175,957 66,953
--------- ---------
Total ........................................................... 297,136 125,199
--------- ---------
OPERATING REVENUES LESS FUEL AND PURCHASED POWER COSTS ................. 384,135 320,782
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel and purchased power cost.... 114,541 108,377
Depreciation and amortization ........................................ 103,696 101,475
Income taxes ......................................................... 43,568 20,767
Other taxes .......................................................... 25,296 25,381
--------- ---------
Total ........................................................... 287,101 256,000
--------- ---------
OPERATING INCOME ....................................................... 97,034 64,782
--------- ---------
OTHER INCOME (DEDUCTIONS):
Income taxes ......................................................... 1,220 (697)
Other - net .......................................................... (3,406) 1,683
--------- ---------
Total ........................................................... (2,186) 986
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS ...................................... 94,848 65,768
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................................... 32,581 33,338
Interest on short-term borrowings .................................... 961 1,267
Debt discount, premium and expense ................................... 329 614
Capitalized interest ................................................. (3,629) (2,226)
--------- ---------
Total ........................................................... 30,242 32,993
--------- ---------
INCOME BEFORE ACCOUNTING CHANGE ........................................ 64,606 32,775
Cumulative Effect of a Change in Accounting for Derivatives -
net of income taxes of $1,793 ...................................... (2,755) --
--------- ---------
EARNINGS FOR COMMON STOCK .............................................. $ 61,851 $ 32,775
========= =========
See Notes to Condensed Financial Statements.
-3-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended March 31,
---------------------------
2001 2000
--------- ---------
(dollars in thousands)
ELECTRIC OPERATING REVENUES ............................................. $ 3,715,542 $ 2,324,796
----------- -----------
FUEL AND PURCHASED POWER COSTS:
Fuel for electric generation .......................................... 394,207 248,352
Purchased power ....................................................... 1,656,468 570,369
----------- -----------
Total ............................................................ 2,050,675 818,721
----------- -----------
OPERATING REVENUES LESS FUEL AND PURCHASED POWER COSTS .................. 1,664,867 1,506,075
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel and purchased power costs.... 436,256 445,391
Depreciation and amortization ......................................... 428,140 417,088
Income taxes .......................................................... 222,604 164,393
Other taxes ........................................................... 99,645 96,482
----------- -----------
Total ............................................................ 1,186,645 1,123,354
----------- -----------
OPERATING INCOME ........................................................ 478,222 382,721
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes .......................................................... 6,055 27,510
Other - net ........................................................... (15,506) (6,755)
----------- -----------
Total ............................................................ (9,451) 20,755
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ....................................... 468,771 403,476
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ............................................ 133,674 132,458
Interest on short-term borrowings ..................................... 7,149 7,471
Debt discount, premium and expense .................................... 1,820 2,164
Capitalized interest .................................................. (12,297) (5,919)
----------- -----------
Total ............................................................ 130,346 136,174
----------- -----------
INCOME FROM CONTINUING OPERATIONS ....................................... 338,425 267,302
Extraordinary charge - net of income taxes of $94,115 ................. -- (139,885)
Cumulative Effect of a Change in Accounting for Derivatives -
net of income taxes of $1,793 ....................................... (2,755) --
----------- -----------
EARNINGS FOR COMMON STOCK ............................................... $ 335,670 $ 127,417
=========== ===========
See Notes to Condensed Financial Statements
-4-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Dollars in Thousands)
March 31, December 31,
----------- ------------
2001 2000
----------- -----------
(Unaudited)
UTILITY PLANT:
Electric plant in service and held for future use ...... $ 7,880,943 $ 7,805,025
Less accumulated depreciation and amortization ......... 3,238,049 3,187,328
----------- -----------
Total ........................................... 4,642,894 4,617,697
Construction work in progress .......................... 248,601 245,749
Nuclear fuel, net of amortization ...................... 51,686 47,389
----------- -----------
Utility plant - net ............................. 4,943,181 4,910,835
----------- -----------
INVESTMENTS AND OTHER ASSETS ........................... 323,458 269,678
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents .............................. 124,502 2,609
Accounts receivable:
Service customers .................................... 264,439 422,012
Other ................................................ 79,303 48,711
Allowance for doubtful accounts ...................... (2,218) (2,380)
Accrued utility revenues ............................... 61,600 74,566
Materials and supplies, at average cost ................ 75,523 71,966
Fossil fuel, at average cost ........................... 19,976 19,405
Deferred income taxes .................................. 5,793 5,793
Assets from risk management activities.................. 168,562 17,506
Other .................................................. 38,911 38,414
----------- -----------
Total current assets ............................ 836,391 698,602
----------- -----------
DEFERRED DEBITS:
Regulatory assets ...................................... 436,474 469,867
Unamortized debt issue costs ........................... 12,739 12,805
Other .................................................. 50,401 37,928
----------- -----------
Total deferred debits ........................... 499,614 520,600
----------- -----------
TOTAL ........................................... $ 6,602,644 $ 6,399,715
=========== ===========
See Notes to Condensed Financial Statements.
-5-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Dollars in Thousands)
March 31, December 31,
2001 2000
---------- ----------
(Unaudited)
CAPITALIZATION:
Common stock ................................................. $ 178,162 $ 178,162
Additional paid-in capital ................................... 1,246,804 1,246,804
Retained earnings ............................................ 714,152 694,802
Accumulated Other Comprehensive Income ....................... 37,425 --
---------- ----------
Common stock equity ....................................... 2,176,543 2,119,768
Long-term debt less current maturities ....................... 1,669,001 1,806,908
---------- ----------
Total capitalization ...................................... 3,845,544 3,926,676
---------- ----------
CURRENT LIABILITIES:
Commercial paper ............................................. 137,950 82,100
Current maturities of long-term debt ......................... 375,266 250,266
Accounts payable ............................................. 169,863 267,999
Accrued taxes ................................................ 167,148 106,515
Accrued interest ............................................. 13,787 39,488
Customer deposits ............................................ 25,689 24,498
Liabilities from risk management activities................... 81,297 37,179
Other ........................................................ 188,669 104,947
---------- ----------
Total current liabilities ................................. 1,159,669 912,992
---------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ........................................ 1,120,439 1,110,437
Unamortized gain - sale of utility plant ..................... 67,492 68,636
Customer advances for construction ........................... 41,994 40,694
Other ........................................................ 367,506 340,280
---------- ----------
Total deferred credits and other .......................... 1,597,431 1,560,047
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 6, 7 and 9)
TOTAL ..................................................... $6,602,644 $6,399,715
========== ==========
See Notes to Condensed Financial Statements.
-6-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months
Ended March 31,
--------- ---------
2001 2000
--------- ---------
(dollars in thousands)
Cash Flows from Operating Activities:
INCOME BEFORE ACCOUNTING CHANGE .................................... $ 64,606 $ 32,775
Items not requiring cash:
Depreciation and amortization .................................... 103,696 101,475
Nuclear fuel amortization ........................................ 7,581 7,931
Deferred income taxes - net ...................................... (12,558) (7,058)
Changes in certain current assets and liabilities:
Accounts receivable - net ........................................ 126,820 44,935
Accrued utility revenues ......................................... 12,966 9,826
Materials, supplies and fossil fuel .............................. (4,127) (3,193)
Other current assets ............................................. (14,748) (3,943)
Accounts payable ................................................. (99,618) (51,087)
Accrued taxes .................................................... 60,633 60,444
Accrued interest ................................................. (25,701) (14,817)
Other current liabilities ........................................ 122,090 21,025
Risk management activities - net ................................. (99,504) (5,658)
Other - net ........................................................ (4,176) (3,627)
--------- ---------
Net cash flow provided by operating activities ............... 237,960 189,028
--------- ---------
Cash Flows from Investing Activities:
Capital expenditures ............................................... (99,430) (82,342)
Capitalized interest ............................................... (3,629) (2,226)
Other .............................................................. (13,291) (2,675)
--------- ---------
Net cash flow used for investing activities .................. (116,350) (87,243)
--------- ---------
Cash Flows from Financing Activities:
Short-term borrowings - net ........................................ 55,850 90,500
Dividends paid on common stock ..................................... (42,500) --
Repayment and reacquisition of long-term debt ...................... (13,067) (89,138)
--------- ---------
Net cash flow provided (used) for financing activities........ 283 1,362
--------- ---------
Net increase (decrease) in cash and cash equivalents ................ 121,893 103,147
Cash and cash equivalents at beginning of period .................... 2,609 7,477
--------- ---------
Cash and cash equivalents at end of period .......................... $ 124,502 $ 110,624
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........................ $ 55,515 $ 31,932
Income taxes ..................................................... $ 19,721 $ --
See Notes to Condensed Financial Statements.
-7-
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 cumulative effect of a change
in accounting for derivatives (see Note 9) and the extraordinary charge (see
Note 5). 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 2000 10-K. We have reclassified
certain prior year amounts to conform to the current year presentation.
2. Weather conditions and wholesale power marketing activities can have
significant impacts on our results for interim periods. 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 three months ended March 31, 2001.
5. Regulatory Accounting
We are regulated by the ACC and the FERC. The accompanying financial statements
reflect the ratemaking policies of these commissions. For regulated operations,
we prepare our financial statements in accordance with 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 EITF of the 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 1999 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. As a result, we
tested the generation assets for impairment and determined that the generation
assets were not impaired. Pursuant to the 1999 Settlement Agreement, a
regulatory disallowance removed $234 million pre-tax ($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 1999 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 that would have ended June
30, 2004.
-8-
The regulatory assets to be recovered under the 1999 Settlement Agreement are
now being amortized through June 30, 2004 as follows (dollars in millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
The majority of our remaining 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 (for additional generation information see
Note 8):
(dollars in thousands)
March 31, December 31,
2001 2000
---- ----
Electric plant in service and held for future use $ 3,862,127 $ 3,856,600
Accumulated depreciation and amortization (1,725,287) (1,693,079)
Construction work in progress 87,634 86,329
Nuclear fuel, net of amortization 51,686 47,389
6. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
1999 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 1999 Settlement Agreement,
with some modifications. On December 13, 1999, two parties filed lawsuits
challenging the ACC's approval of the 1999 Settlement Agreement. Each party
bringing the lawsuits appealed the ACC's order approving the 1999 Settlement
Agreement directly to the Arizona Court of Appeals, as provided by Arizona law.
In one of the appeals, on December 26, 2000, the Arizona Court of Appeals
affirmed the ACC's approval of the 1999 Settlement Agreement. This decision was
not appealed and has become final. In the other appeal, on April 5, 2001, the
Arizona Court of Appeals again affirmed the ACC's approval of the 1999
Settlement Agreement. The Arizona Consumers Council, which filed that appeal,
has petitioned the Arizona Supreme Court for review of the Court of Appeals'
decision.
The following are the major provisions of the 1999 Settlement Agreement, as
approved:
* We have reduced, and will reduce, rates for standard offer service for
customers with loads less than three MW in a series of annual retail
electricity price reductions
-9-
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 ($7 million after income taxes) related to
the 1996 regulatory agreement. See "1996 Regulatory Agreement" below.
Based on the price reduction authorized in the 1999 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 three MW or greater, standard offer rates
will be reduced in varying annual increments that total 5% in the
years 1999 through 2002.
* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the 1999 Settlement Agreement, retroactive to July 1,
1999, and also became 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 were 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), including an
additional 140 MW being made available to eligible non-residential
customers. We opened our distribution system to retail access for all
customers on January 1, 2001.
* Prior to the 1999 Settlement Agreement, we were recovering
substantially all of our regulatory assets through July 1, 2004,
pursuant to the 1996 regulatory agreement. In addition, the 1999
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 1999 Settlement Agreement provides that we will have the
opportunity to recover $350 million net present value through a
competitive transition charge that will remain in effect through
December 31, 2004, at which time it will terminate. The costs subject
to recovery
-10-
under the adjustment clause described above will be decreased or
increased by any over/under-recovery due to sales volume variances.
* We will form a separate corporate affiliate or affiliates and transfer
to such affiliate(s) our generating assets and competitive services at
book value as of the date of transfer, and will complete the transfer
no later than December 31, 2002. Accordingly, we plan to complete the
move of such assets and services to the parent company or to Pinnacle
West Energy by the end of 2002, as required. 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 1999 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
1999 Settlement Agreement. To protect our rights, we have several
lawsuits pending on ACC orders relating to stranded cost recovery and
the adoption and amendment of the ACC's electric competition rules,
which would be voluntarily dismissed at the appropriate time under
this provision.
As discussed in Note 5 above, we have discontinued the application of SFAS No.
71 for our generation operations.
Although the Rules allow retail customers to have access to competitive
providers of energy and energy services (see "Retail Electric Competition Rules"
below), we are the "provider of last resort" for standard offer customers under
rates that have been approved by the ACC. Energy prices in the western wholesale
market vary and, during the course of the last year, have been volatile. At
various times, prices in the spot wholesale market have significantly exceeded
the amount included in our current retail rates. We expect these market
conditions to continue in 2001. We believe we have adequately supplemented our
current generation portfolio with power purchased through contracts and hedging
techniques that limit exposure to the volatile spot wholesale power market.
However, in the event of shortfalls due to unforeseen increases in load demand
or generation outages, we may need to purchase additional supplemental power in
the wholesale spot market. Unless we are able to obtain an adjustment of our
rates under the 1999 Settlement Agreement, there can be no assurance that we
would be able to fully recover the costs of this power.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve rules that provide a framework for the introduction of retail electric
competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be
interpreted and applied, to the greatest extent possible, in a manner consistent
with the 1999 Settlement Agreement. If the two cannot be reconciled, we must
seek, and the other parties to the 1999 Settlement Agreement must support, a
waiver of the Rules in favor of the 1999 Settlement Agreement. 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 (including those described above), the adoption or
amendment of the Rules and the certification of competitive electric service
providers.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a
final judgement holding that the Rules are unconstitutional and unlawful in
their entirety due to
-11-
failure to establish a fair value rate base for competitive electric service
providers and because certain of the Rules were not submitted to the Arizona
Attorney General for certification. The judgement also invalidates all ACC
orders authorizing competitive electric service providers, including APS Energy
Services, to operate in Arizona. We do not believe the ruling affects the 1999
Settlement Agreement. The 1999 Settlement Agreement was not at issue in the
consolidated cases before the judge. Further, the ACC made findings related to
the fair value of our property in the order approving the 1999 Settlement
Agreement. The ACC and other parties aligned with the ACC have appealed the
ruling to the Arizona Court of Appeals, as a result of which the Superior
Court's ruling is automatically stayed pending further judicial review. In a
similar appeal concerning the issuance of telecommunications CC&N's, the Arizona
Court of Appeals invalidated rates for competitive carriers due to failure to
establish a fair value rate base.
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.
* Effective January 1, 2001, retail access became available to all of
our retail electricity customers.
* Electric service providers that get CC&N's 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 1999 Settlement Agreement, we
received a waiver to allow transfer of our generation and other
competitive assets and services to affiliates no later than December
31, 2002. See "1999 Settlement Agreement" above for a discussion of
the planned timing of the transfer.
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 (dollars in millions):
-12-
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 1999 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.
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 MW (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, results of operations or liquidity. 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 1992 Energy Act and recent rulemakings by FERC have promoted increased
competition in the wholesale energy markets. We do not expect these rules to
have a material impact on our financial statements.
-13-
Several electric utility industry restructuring bills will undoubtedly be
introduced during the current congressional session. Several bills have been
written to allow consumers to choose their electricity suppliers beginning in
2001 and beyond. These bills and other bills 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 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 activities (delivery business segment) and the generation of
electricity and wholesale activities (generation business segment).
These reportable segments reflect a change in the reporting of our functional
activities. Previously reported segment information combined transmission and
distribution of electricity activities with wholesale activities. Our current
operational activities are more closely based on the strong integration of our
wholesale activities and our generation of electricity activities, and have been
combined for segment reporting purposes. The corresponding information for
earlier periods has been restated.
-14-
Eliminations primarily relate to intersegment sales of electricity. Segment
information for the three and twelve months ended March 31, 2001 and 2000 is as
follows (dollars in millions):
3 Months Ended 12 Months Ended
March 31, March 31,
------------------ ------------------
2001 2000 2001 2000
------- ------- ------- -------
Operating Revenues:
Delivery $ 408 $ 372 $ 2,006 $ 1,817
Generation 468 246 2,632 1,337
Eliminations (195) (172) (922) (829)
------- ------- ------- -------
Total $ 681 $ 446 $ 3,716 $ 2,325
======= ======= ======= =======
Income from Continuing Operations:
Delivery $ 24 $ 24 $ 105 $ 146
Generation 41 9 233 121
------- ------- ------- -------
Total $ 65 $ 33 $ 338 $ 267
======= ======= ======= =======
As of March 31, As of December 31,
2001 2000
------ ------
Assets:
Delivery $3,949 $3,987
Generation 2,654 2,413
------ ------
Total $6,603 $6,400
====== ======
9. Accounting Matters
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 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 derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances/credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodity. In addition, subject to
specified risk parameters, we engage in trading activities intended to profit
from market price movements.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 requires that entities
recognize all derivatives as either assets or liabilities on the balance sheet
and measure those instruments at fair value. Changes in the fair value of
derivative financial instruments are either recognized periodically in income or
shareholder's equity (as a component of other comprehensive income), depending
on whether or not the derivative meets specific hedge accounting criteria. Hedge
effectiveness is measured based on the relative changes in fair value between
the derivative contract and the hedged item over time. Any change in the
-15-
fair value resulting from ineffectiveness is recognized immediately in net
income. This new standard may result in additional volatility in our net income
and comprehensive income.
As a result of adopting SFAS No. 133, we recognized $118 million of derivative
assets and $16 million of derivative liabilities in our balance sheet as of
January 1, 2001. Also as of January 1, 2001, we recorded a $3 million after-tax
loss in net income as a cumulative effect of a change in accounting principles
and a $65 million after-tax gain in equity (as a component of other
comprehensive income). The gain resulted from unrealized gains on cash flow
hedges.
For the three and twelve months ended March 31, 2001, a net gain of
approximately $2 million pretax was recognized in earnings (recorded in fuel and
purchased power) representing the amount of hedge ineffectiveness. We excluded
the time value component of options from the assessment of hedge effectiveness
and there were no reclassifications into earnings as a result of the
discontinuance of hedges. As of March 31, 2001, the maximum length of time over
which we are hedging our exposure to the variability in future cash flows for
forecasted transactions is forty-five months. During the twelve months ending
March 31, 2002, we estimate that a net gain of $43 million before income taxes
will be reclassified from accumulated other comprehensive income as an offset to
the effect on earnings of market price changes for the related hedged
transactions.
In December 2000, the FASB's DIG discussed whether contracts in the electric
industry that have some of the characteristics of purchased and written options
should qualify for the "normal purchases and sales" scope exception. The DIG did
not reach a conclusion on this issue. We account for electricity contracts with
characteristics of options as normal purchases and sales if it is probable that
the contract, if exercised, will not be settled in cash and will result in the
physical delivery of electricity. As a result, we do not mark these contracts to
their fair market values each reporting period. The DIG also discussed but did
not determine whether electricity contracts subject to "bookout" should qualify
for the normal scope exception. A bookout occurs when one party appears more
than once in a contract path for the sale and purchase of energy. In that
instance, the counterparties may agree that they will not schedule or deliver
physical energy that originates and ends with the same counterparty, but rather
will settle in cash the amounts due to or from each counterparty. We account for
our non-trading electricity transactions that bookout as gross settlement with
physical delivery (and eligible for the normal scope exception) if title
transfers, gross cash payment is made, and the transaction retains both
performance and credit risk. Trading contracts are marked to their fair market
values each reporting period.
In March 2001, the FASB discussed contracts in the electric industry that have
some of the characteristics of purchased and written options. There was not
sufficient FASB support for providing an exception that would enable electricity
option contracts to be eligible to qualify for the normal purchases and sales
exception. The DIG also concluded that contracts that are subject to being
booked out are prohibited from qualifying for the normal purchase and sale scope
exception. Both decisions are subject to a comment period, which ends on June 1,
2001. Final guidance is expected in the second quarter. Until final guidance is
issued, we will continue to account for these transactions as normal purchases
and sales. We are currently evaluating the impact the proposed guidance would
have on our financial statements.
-16-
Our accounting approach for non-trading electricity contracts, as described
above, reflects the non-storability of electricity and the unpredictability of
electricity demand at any point in time. If the FASB or DIG ultimately provides
us with contrary guidance, we will be required to mark certain of our
non-trading electricity contracts to their fair market values each reporting
period. This could have a material impact on our financial statements and add
significant volatility in both net income and comprehensive income that would
not be reflective of our underlying financial performance or condition. If we
are required in the future to treat these contracts as derivative instruments,
we will apply a cumulative effect of a change in accounting principles in the
quarter following final resolution of the issues.
In February 1996, the FASB issued an exposure draft, "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets." This proposed
standard would require the estimated present value of the cost of
decommissioning and certain other removal costs to be recorded as a liability,
along with an offsetting plant asset when a decommissioning or other removal
obligation is incurred. The FASB issued a revised exposure draft in February
2000 and we are evaluating the impacts.
10. Comprehensive Income
Components of comprehensive income for the three-month and twelve-month periods
ended March 31, 2001 and 2000, are as follows (dollars in thousands):
3 Months Ended 12 Months Ended
March 31, March 31,
------------------------ ------------------------
2001 2000 2001 2000
--------- --------- --------- ---------
Net Income $ 61,851 $ 32,775 $ 335,670 $ 127,417
--------- --------- --------- ---------
Other comprehensive income:
Cumulative effect of change in accounting for
derivatives, net of tax of $42,101 64,700 -- 64,700 --
Unrealized holding losses arising during
period, net of tax of $3,681 (5,657) -- (5,657) --
Reclassification adjustment for realized gains
on derivatives, net of tax of $14,067 (21,618) -- (21,618) --
--------- --------- --------- ---------
Total other comprehensive income 37,425 -- 37,425 --
--------- --------- --------- ---------
Comprehensive income $ 99,276 $ 32,775 $ 373,095 $ 127,417
========= ========= ========= =========
11. California Energy Market Issues
We are closely monitoring developments in the California energy market and the
potential impact of these developments on us. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with SCE and
PG&E and power marketing exposures. Based upon the financial transactions to
date, we do not believe the foregoing matters will have a material adverse
effect on our financial position or liquidity. We cannot predict with certainty,
however, the impact that any future resolution, or attempted resolution, of the
California energy market situation may have on us or the regional energy market
in general.
-17-
12. Power Service Agreement
We are a party to a power service agreement with Citizens under which we supply
Citizens with power. By letter dated March 7, 2001, Citizens advised us that it
believes we have overcharged Citizens by over $50 million under the agreement
since the summer of 2000. We believe that our charges to Citizens under the
agreement are fully in accordance with the terms of the agreement and we will
vigorously defend any claims raised by Citizens.
-18-
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 three-month and twelve-month
periods ended March 31, 2001 and 2000;
* the effects of regulatory agreements on our results and outlook;
* our capital needs and resources;
* major factors that affect our financial outlook; and
* our management of market risks.
We are Arizona's largest electric utility and provide 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 and, directly or through Pinnacle
West's power marketing division, sell and deliver electricity to wholesale
customers in the western United States. Pinnacle West owns all of our
outstanding stock.
OPERATING RESULTS
The following table summarizes our revenues and earnings for the three-month and
twelve-month periods ended March 31, 2001 and the comparable prior-year periods:
Periods ended March 31,
(Unaudited)
(dollars in thousands)
Three Months Twelve Months
--------------------------- ---------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
Operating Revenues $ 681,271 $ 445,981 $3,715,542 $2,324,796
Earnings for Common Stock (1) $ 61,851 $ 32,775 $ 335,670 $ 127,417(2)
- ----------
(1) Each of the 2001 periods includes an after-tax loss related to the
cumulative effect of a change in accounting for derivatives of $2,755.
(2) The twelve-month period ended March 2000 includes an after-tax
extraordinary charge of $139,885.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2001 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 2000
Earnings for the three months ended March 31, 2001 were $62 million compared
with $33 million for the same period in the prior year. In January 2001, we
recognized a $3 million
-19-
after-tax loss in net income as a cumulative effect of a change in accounting
for derivatives. See Note 9 for further discussion.
Income before accounting change for the three-month period increased $32 million
over the comparable period in 2000 primarily because of increases in wholesale
and retail electricity sales. These increases were partially offset by
reductions in retail electricity prices, higher operations and maintenance
expense, and other miscellaneous factors. See Note 6 for information on the
price reductions.
Electric operating revenues increased $235 million because of:
* increased wholesale revenues ($213 million);
* weather impacts on retail revenues ($17 million); and
* increased retail revenues related to the number of electricity
customers and the average amount of electricity used by customers ($14
million).
As mentioned above, these positive factors were partially offset by reductions
in retail electricity prices ($6 million) and other miscellaneous factors ($3
million).
The increase in wholesale revenues resulted primarily from higher prices and
increased activity in western U.S. wholesale power markets. These revenues were
accompanied by increases in purchased power and fuel expenses of approximately
$110 million.
Fuel and purchased power expenses were also higher because of increased prices
and higher retail electricity sales volumes.
The increase in utility operations and maintenance expenses primarily related to
power plant maintenance.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2001 COMPARED WITH
TWELVE-MONTH PERIOD ENDED MARCH 31, 2000
Earnings for the twelve months ended March 31, 2001 were $336 million compared
with $127 million for the same period in the prior year. The increase primarily
relates to a $140 million after-tax extraordinary charge recorded in the third
quarter of 1999 and higher earnings from continuing operations in the
twelve-month period ended March 31, 2001, partially offset by a $3 million
after-tax loss for a cumulative effect of a change in accounting for derivatives
recorded in 2001.
The extraordinary charge related to a regulatory disallowance that resulted from
our comprehensive 1999 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 1999 Settlement Agreement.
The cumulative effect of a change in accounting for derivatives resulted from
the implementation of SFAS No. 133. See Note 9.
-20-
Income from continuing operations for the twelve-months ended March 31, 2001
increased $71 million over the comparable prior-year period primarily because of
an increase in the contribution of wholesale power marketing activities, an
increase in the number of retail electricity customers and in the average amount
of electricity used by customers, and a decrease in operations and maintenance
expense. These positive factors more than offset decreases due to the completion
of the amortization of ITCs in 1999, reductions in retail electricity prices,
higher depreciation expense, and other miscellaneous factors. See Note 6 for
information on the price reductions. See "Income Taxes" below for a discussion
of the ITC amortization.
Electric operating revenues increased $1.4 billion because of:
* increased wholesale revenues ($1.3 billion);
* increases in the number of retail customers and the average amount of
electricity used by customers ($93 million);
* weather impacts on retail revenues ($49 million); and
* miscellaneous factors ($7 million).
These positive factors were partially offset by reductions in retail electricity
prices ($28 million).
The increase in wholesale 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 approximately
$1.1 billion.
Fuel and purchased power expenses were also higher because of increased prices
and higher retail electricity sales volumes.
The decrease in utility operations and maintenance expenses is primarily related
to $19 million of non-recurring items recorded in 1999, offset by increases in
customer growth.
Depreciation and amortization expense increased primarily because of higher
plant balances.
INCOME TAXES
As part of a 1994 rate settlement, we accelerated amortization of substantially
all of our ITCs over a five-year period that ended on December 31, 1999. The
amortization of ITCs decreased annual income tax expense by approximately $28
million. Beginning in 2000, no further benefits were reflected in income tax
expense related to the acceleration of the ITCs.
LIQUIDITY AND CAPITAL RESOURCES
For the three months ended March 31, 2000, we incurred approximately $102
million in capital expenditures, which is approximately 22% of the most recently
estimated 2001 capital expenditures. Our projected capital expenditures for the
next three years are $455
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million in 2001; $401 million in 2002; and $294 million in 2003. These amounts
include about $30-$35 million each year for nuclear fuel expenditures.
Our long-term debt redemption requirements, including optional repayments on
long-term debt are: $380 million in 2001; $125 million in 2002; and zero in
2003. During the three months ended March 31, 2001, we satisfied all of our
long-term debt redemption requirements for the first quarter of 2001 with cash
from operations and short-term borrowings. On April 15, 2001, we redeemed $45
million (plus interest) of our First Mortgage Bonds, 9 1/2% Series due 2021. We
have also deposited $72 million, plus interest, with the trustee for the
redemption in December 2001 of our First Mortgage Bonds, 9% Series due 2021.
Based on market conditions and optional call provisions, we may make optional
redemptions of long-term debt from time to time.
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.
BUSINESS OUTLOOK
This section describes several major factors affecting our financial outlook.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See "Business Outlook - Competition and Industry Restructuring" in Item 7 of the
2000 10-K and Note 6 above for a discussion of developments affecting retail and
wholesale electric competition. See Note 5 for a discussion of regulatory
accounting.
CALIFORNIA ENERGY MARKET ISSUES
SCE and PG&E have publicly disclosed that their liquidity has been materially
and adversely affected because of, among other things, their inability to pass
on to ratepayers the prices each has paid for energy and ancillary services
procured through the PX and ISO. In April 2001, PG&E filed for bankruptcy
protection.
We are closely monitoring developments in the California energy market and the
potential impact of these developments on us. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with SCE and
PG&E; and power marketing exposures. Based upon the financial transactions to
date, we do not believe the foregoing matters will have a material adverse
effect on our financial position or liquidity. We cannot predict with certainty,
however, the impact that any future resolution, or attempted resolution, of the
California energy market situation may have on us or the regional energy market
in general.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in regulated
retail markets in Arizona, and in competitive retail and wholesale bulk power
markets in the western United States.
-22-
These revenues are expected to be affected by electricity sales volumes related
to customer mix, customer growth and average usage per customer, as well as
electricity prices and variations in weather from period to period.
In our regulated retail market area, we will provide electricity services to
standard-offer, full-service customers and to energy delivery customers who have
chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in our service territory averaged 3.8% a year for
the three years 1998 through 2000; we currently expect customer growth to
average 3.5% to 4% a year for 2001 through 2003. We currently estimate that
retail electricity sales in kilowatt-hours will grow 3.5% to 4.5% a year in 2001
through 2003, before the retail effects of weather variations. The customer
growth and sales growth referred to in this paragraph apply to energy delivery
customers. As industry restructuring evolves in the regulated market area, we
cannot predict the number of our standard offer customers that will switch to
unbundled service.
Wholesale activities will be affected by electricity prices and costs of
available fuel and purchased power in the western United States, as well as
competitive market conditions and regulatory and legislative changes in various
state and federal jurisdictions. These factors have significantly affected our
wholesale power activities and their resultant earnings contributions over the
last several years. We cannot predict future contributions from wholesale
activities.
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Fuel and purchased power costs are impacted by our electricity sales volumes,
existing contracts for generation fuel and purchased power, our power plant
performance, prevailing market prices, and our hedging program for managing such
costs.
Operations and maintenance expenses are expected to be affected by sales mix and
volumes, power plant operations, inflation, and other factors.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, and changes in
regulatory asset amortization. See Note 5 for the regulatory asset amortization
that is being recorded in 1999 through 2004 pursuant to the 1999 Settlement
Agreement.
Taxes other than income taxes consist primarily of property taxes, which are
affected by tax rates and the value of property in service and under
construction. We expect property taxes to increase primarily due to additions to
existing facilities.
Interest expense is affected by the amount of debt outstanding and the interest
rates on that debt.
-23-
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.
Our financial results may be affected by the application of SFAS No. 133. See
Note 9 for further information.
Our financial results may be affected by a number of broad factors. See
"Forward-Looking Statements" below for further information on such factors,
which may cause our actual future results to differ from those we currently seek
or anticipate.
RATE MATTERS
See Note 6 for a discussion of a price reduction effective as of July 1, 2000,
and for a discussion of the 1999 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
This document contains forward-looking statements based on current expectations
and we assume no obligation to update these statements. Because actual results
may differ materially from expectations, we caution readers not to place undue
reliance on these statements. A number of factors could cause future results to
differ materially from historical results, or from results or outcomes currently
expected or sought by us. These factors include the ongoing restructuring of the
electric industry; the outcome of regulatory and legislative proceedings
relating to the restructuring; regional economic and market conditions,
including the California energy situation, which could affect customer growth
and the cost of power supplies; the cost of debt and equity capital; weather
variations affecting local and regional customer energy usage; conservation
programs; power plant performance; our ability to compete successfully outside
traditional regulated markets (including the wholesale market); 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 ensure that we have enough energy for our customers
and to limit our exposure to volatile wholesale prices for power and fuel. In
addition, we engage in trading activities intended to profit from favorable
movements on market prices.
-24-
As of March 31, 2001, 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 $66 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 complete the move of our wholesale power marketing and
trading activities to the parent company by the end of 2002.
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.
-25-
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 our construction and financing programs.
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.
WATER SUPPLY
A summons served on the Company in early 1986 required all water claimants in
the Lower Gila River Watershed in Arizona to assert any claims to water on or
before January 20, 1987. See "Water Supply" in Part I, Item 1 of the 2000 10-K.
The Company and other parties have petitioned the U.S. Supreme Court for review
of the Arizona Supreme Court's decision affirming the lower court's criteria for
resolving groundwater claims.
-26-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
In addition, 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:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.a DATE EFFECTIVE
- ----------- ----------- ---------------------------- -------- --------------
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
(b) Reports on Form 8-K
During the quarter ended March 31, 2001, and the period from April 1
through May 15, 2001, we filed the following reports on Form 8-K:
Report dated November 27, 2000, regarding (i) the Court of Appeals
affirming the ACC approval of the 1999 Settlement Agreement, (ii) a final
judgment relating to the Rules and (iii) the timing of the Company's
restructuring.
Report dated April 5, 2001, regarding the Arizona Court of Appeals
affirming the ACC approval of the 1999 Settlement Agreement.
- ----------
(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.
-27-
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: May 15, 2001 By: Michael V. Palmeri
-------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)