Securities and Exchange Commission
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended March 31, 2002
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 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (602) 250-1000
(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, 2002: 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
APSES - 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
EITF - Emerging Issues Task Force
ERMC - Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
GAAP - Generally accepted accounting principles in the United States
GCVTC - Grand Canyon Visibility Transport Commission
ISO - California Independent System Operator
MW - megawatt, one million watts
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
Native Load - retail and wholesale sales supplied under traditional cost-based
rate regulation
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation, parent company of the company
Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West
subsidiary
PPA - Purchase Power Agreement
PX - California Power Exchange
Rules - ACC retail electric competition rules
SFAS - Statement of Financial Accounting Standards
SPE - special purpose entity
T&D - transmission and distribution
2001 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 2001
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended March 31,
----------------------
2002 2001
--------- ---------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ............................................... $ 394,434 $ 764,940
--------- ---------
PURCHASED POWER AND FUEL COSTS:
Purchased power ......................................................... 19,529 259,626
Fuel for electric generation ............................................ 58,856 121,179
--------- ---------
Total ................................................................ 78,385 380,805
--------- ---------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .................... 316,049 384,135
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel cost ...... 109,321 114,541
Depreciation and amortization ........................................... 97,622 103,696
Income taxes ............................................................ 21,134 43,568
Other taxes ............................................................. 26,751 25,296
--------- ---------
Total ................................................................ 254,828 287,101
--------- ---------
OPERATING INCOME .......................................................... 61,221 97,034
--------- ---------
OTHER INCOME (DEDUCTIONS):
Income taxes ............................................................ 365 1,220
Other - net ............................................................. (659) (3,406)
--------- ---------
Total ................................................................ (294) (2,186)
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS ......................................... 60,927 94,848
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt .............................................. 31,737 32,581
Interest on short-term borrowings ....................................... 1,137 961
Debt discount, premium and expense ...................................... 642 329
Capitalized interest .................................................... (4,352) (3,629)
--------- ---------
Total ................................................................ 29,164 30,242
--------- ---------
INCOME BEFORE ACCOUNTING CHANGE ........................................... 31,763 64,606
Cumulative Effect of a Change in Accounting for Derivatives -
net of income tax benefit of $1,793 ................................... -- (2,755)
--------- ---------
NET INCOME ................................................................ $ 31,763 $ 61,851
========= =========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended March 31,
--------------------------
2002 2001
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ........................................ $ 2,940,286 $ 3,799,211
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Purchased power .................................................. 1,108,775 1,740,137
Fuel for electric generation ..................................... 329,448 394,207
----------- -----------
Total ......................................................... 1,438,223 2,134,344
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ............. 1,502,063 1,664,867
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel cost 460,341 436,256
Depreciation and amortization .................................... 414,819 427,810
Income taxes ..................................................... 161,206 222,735
Other taxes ...................................................... 102,532 99,645
----------- -----------
Total ......................................................... 1,138,898 1,186,446
----------- -----------
OPERATING INCOME ................................................... 363,165 478,421
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ..................................................... (351) 6,186
Other - net ...................................................... 2,164 (15,836)
----------- -----------
Total ......................................................... 1,813 (9,650)
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS .................................. 364,978 468,771
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ....................................... 125,274 133,674
Interest on short-term borrowings ................................ 4,583 7,149
Debt discount, premium and expense ............................... 2,963 1,820
Capitalized interest ............................................. (15,687) (12,297)
----------- -----------
Total ......................................................... 117,133 130,346
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE .................................... 247,845 338,425
Cumulative Effect of Change in Accounting for Derivatives -
net of income tax benefit of $8,099 and $1,793 ................. (12,446) (2,755)
----------- -----------
NET INCOME ......................................................... $ 235,399 $ 335,670
=========== ===========
See Notes to Condensed Financial Statements
-3-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Dollars in Thousands)
March 31, December 31,
2002 2001
----------- -----------
(Unaudited)
UTILITY PLANT:
Electric plant in service and held for future use ............ $ 8,002,421 $ 7,935,206
Less accumulated depreciation and amortization ............... 3,336,520 3,287,333
----------- -----------
Total ..................................................... 4,665,901 4,647,873
Construction work in progress ................................ 334,519 321,305
Intangible assets, net of accumulated amortization ........... 82,536 83,135
Nuclear fuel, net of accumulated amortization ................ 58,689 49,282
----------- -----------
Utility plant - net ....................................... 5,141,645 5,101,595
----------- -----------
INVESTMENTS AND OTHER ASSETS:
Decommissioning trust accounts ............................... 206,819 202,036
Assets from risk management and trading activities - long-term 14,530 2,082
Other assets ................................................. 49,486 76,322
----------- -----------
Total investments and other assets ........................ 270,835 280,440
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents .................................... 10,017 16,821
Trust fund for bond redemption ............................... 121,668 --
Accounts receivable:
Service customers ......................................... 136,985 182,749
Other ..................................................... 129,503 153,988
Allowance for doubtful accounts ........................... (1,726) (3,349)
Accrued utility revenues ..................................... 63,708 76,131
Materials and supplies, at average cost ...................... 79,428 81,215
Fossil fuel, at average cost ................................. 28,334 27,023
Assets from risk management and trading activities ........... 8,457 10,097
Other ........................................................ 42,757 42,009
----------- -----------
Total current assets ...................................... 619,131 586,684
----------- -----------
DEFERRED DEBITS:
Regulatory assets ............................................ 316,800 342,383
Unamortized debt issue costs ................................. 15,373 13,163
Other ........................................................ 46,037 42,789
----------- -----------
Total deferred debits ..................................... 378,210 398,335
----------- -----------
TOTAL ASSETS .............................................. $ 6,409,821 $ 6,367,054
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Dollars in Thousands)
March 31, December 31,
2002 2001
----------- -----------
(Unaudited)
CAPITALIZATION:
Common stock .............................................................. $ 178,162 $ 178,162
Additional paid-in capital ................................................ 1,246,804 1,246,804
Retained earnings ......................................................... 779,551 790,289
Accumulated other comprehensive loss ...................................... (39,257) (64,565)
----------- -----------
Common stock equity .................................................... 2,165,260 2,150,690
Long-term debt less current maturities .................................... 2,321,470 1,949,074
----------- -----------
Total capitalization ................................................... 4,486,730 4,099,764
----------- -----------
CURRENT LIABILITIES:
Commercial paper .......................................................... -- 171,162
Current maturities of long-term debt ...................................... 451 125,451
Accounts payable .......................................................... 49,477 98,959
Accrued taxes ............................................................. 130,073 107,595
Accrued interest .......................................................... 28,745 41,043
Customer deposits ......................................................... 30,108 28,664
Deferred income taxes ..................................................... 3,244 3,244
Liabilities from risk management and trading activities ................... 11,762 21,840
Other ..................................................................... 156,698 117,770
----------- -----------
Total current liabilities .............................................. 410,558 715,728
----------- -----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ..................................................... 1,028,784 1,023,079
Liabilities from risk management and trading activities - long-term........ 60,694 95,159
Unamortized gain - sale of utility plant .................................. 62,916 64,060
Customer advances for construction ........................................ 60,651 69,293
Other ..................................................................... 299,488 299,971
----------- -----------
Total deferred credits and other ....................................... 1,512,533 1,551,562
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 12)
TOTAL LIABILITIES AND EQUITY .......................................... $ 6,409,821 $ 6,367,054
=========== ===========
See Notes to Condensed Financial Statements.
-5-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months
Ended March 31,
----------------------
2002 2001
--------- ---------
(Dollars in Thousands)
Cash Flows from Operating Activities:
Income before accounting change ......................................... $ 31,763 $ 64,606
Items not requiring cash:
Depreciation and amortization ......................................... 97,622 103,696
Nuclear fuel amortization ............................................. 7,484 7,581
Deferred income taxes - net ........................................... (10,894) (12,558)
Mark-to-market gains - trading ........................................ -- (52,425)
Mark-to-market gains - system ......................................... (2,402) (1,629)
Changes in certain current assets and liabilities:
Accounts receivable - net ............................................. 69,530 126,820
Accrued utility revenues .............................................. 12,423 12,966
Materials, supplies and fossil fuel ................................... 476 (4,127)
Other current assets .................................................. (748) (14,748)
Accounts payable ...................................................... (48,768) (99,618)
Accrued taxes ......................................................... 22,478 60,633
Accrued interest ...................................................... (12,298) (25,701)
Other current liabilities ............................................. 40,372 122,090
Increase in regulatory assets ........................................... (2,096) (2,856)
Other - net ............................................................. (26,993) (46,770)
--------- ---------
Net cash flow provided by operating activities ............................ 177,949 237,960
--------- ---------
Cash Flows from Investing Activities:
Trust fund for bond redemption .......................................... (121,668) (117,510)
Capital expenditures .................................................... (116,693) (99,430)
Capitalized interest .................................................... (4,352) (3,629)
Other ................................................................... 26,836 (13,291)
--------- ---------
Net cash flow used for investing activities ......................... (215,877) (233,860)
--------- ---------
Cash Flows from Financing Activities:
Issuance of long-term debt .............................................. 369,930 --
Short-term borrowings - net ............................................. (171,162) 55,850
Dividends paid on common stock .......................................... (42,500) (42,500)
Repayment and reacquisition of long-term debt ........................... (125,144) (13,067)
--------- ---------
Net cash flow provided by financing activities ...................... 31,124 283
--------- ---------
Net increase (decrease) in cash and cash equivalents ...................... (6,804) 4,383
Cash and cash equivalents at beginning of period .......................... 16,821 2,609
--------- ---------
Cash and cash equivalents at end of period ................................ $ 10,017 $ 6,992
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ............................. $ 40,716 $ 55,515
Income taxes .......................................................... $ 34,777 $ 19,721
See Notes to Condensed Financial Statements.
-6-
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 10). We have reclassified certain
prior-year amounts to conform to current-year presentation. 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 2001 10-K.
2. Weather conditions and wholesale 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. On March 1, 2002, we issued $375 million of 6.5% Notes due 2012. In
addition, as of March 31, 2002, we deposited $122 million, plus interest, with
the trustee under our Mortgage for the redemption in April 2002 of our First
Mortgage Bonds, 8.75% Series due 2024. The above items represent the primary
changes in capitalization for the three months ended March 31, 2002.
5. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW. On September 21, 1999, the ACC approved Rules that provide a
framework for the introduction of retail electric competition in Arizona. On
September 23, 1999, the ACC approved a comprehensive settlement agreement among
us and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, we are required to transfer all of our competitive electric assets
and services either to an unaffiliated party or to a separate corporate
affiliate no later than December 31, 2002. Consistent with that requirement, we
have been addressing the legal and regulatory requirements necessary to complete
the transfer of our generation assets to Pinnacle West Energy on or before that
date.
In February 2002, the ACC opened a "generic" docket to "determine if
changed circumstances require the [ACC] to take another look at electric
restructuring in Arizona." The ACC Staff filed a report with the ACC in this
docket stating, among other things, that transfers of generation assets required
by the Rules would be "unwise" at the present time and that such transfers
should be stayed pending the completion of the generic docket. On June 17, 2002,
ACC hearings are scheduled to begin on various issues, including our planned
divestiture of generation assets to Pinnacle West Energy. These regulatory
developments have raised uncertainty about the status and pace of retail
electric competition in Arizona, including our transfer of generation assets to
Pinnacle West Energy.
-7-
These matters are discussed in more detail below.
1999 SETTLEMENT AGREEMENT. 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 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 a
July 1, 1999 retail price decrease of approximately $11 million ($7
million after income taxes) related to the 1996 regulatory agreement.
Based on the price reductions authorized in the 1999 Settlement
Agreement, there were also retail price decreases of approximately $28
million ($17 million after taxes), or 1.5%, effective July 1, 2000,
and approximately $27 million ($16 million after taxes), or 1.5%,
effective July 1, 2001. For customers having loads of 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 we 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; material changes in our
cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or 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 then-current
(1999) rates, and costs associated with the "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 a 1996 regulatory agreement. In addition, the 1999
-8-
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 under the adjustment clause described above will be
decreased or increased by any over/under-recovery due to sales volume
variances.
* We will form, or cause to be formed, a separate corporate affiliate or
affiliates and transfer to such affiliate(s) our competitive electric
assets and services at book value as of the date of transfer, and will
complete the transfer no later than December 31, 2002. Consistent with
that requirement, we have been addressing the legal and regulatory
requirements necessary to complete the transfer of our generation
assets to Pinnacle West Energy on or before that date. However, as
noted above and discussed in greater detail below, the ACC's recent
establishment of a "generic" docket to consider electric industry
restructuring in Arizona could affect our ability to transfer assets
to Pinnacle West Energy. 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.
RETAIL ELECTRIC COMPETITION RULES. 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 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
noncompetitive 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
electric 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 competitive electric assets
and services to affiliates no later than December 31, 2002.
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.
-9-
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to 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 judgment also
invalidates all ACC orders authorizing competitive electric service providers 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 competitive telecommunications CC&N's, the Arizona
Court of Appeals invalidated rates for competitive carriers due to the ACC's
failure to establish a fair value rate base for such carriers. That
telecommunications case has been appealed to the Arizona Supreme Court, where a
decision is pending.
PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail
customers to have access to competitive providers of energy and energy services,
we are the "provider of last resort" for standard-offer, full-service customers
under rates that have been approved by the ACC. These rates are established
until July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment
of these rates in the event of emergency conditions or circumstances, such as
the inability to secure financing 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. Energy prices in the western wholesale market vary and, during the
course of the last two years, have been volatile. At various times, prices in
the spot wholesale market have significantly exceeded the amount included in our
current retail rates. 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 emergency provisions of the 1999 Settlement
Agreement, there can be no assurance that we would be able to fully recover the
costs of this power.
PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. Commencing on the
transfer of the fossil-fueled generating assets and the receipt of certain
regulatory approvals, Pinnacle West Energy expects to sell its power at
wholesale to Pinnacle West's marketing and trading division, which, in turn, is
expected to sell power to us and to non-affiliated power purchasers. In a filing
with the ACC on October 18, 2001, we requested the ACC to:
* grant us a partial variance from an ACC Rule that would obligate us to
acquire all of our customers' standard-offer, full-service generation
requirements from the competitive market (with at least 50% of those
requirements coming from a "competitive bidding" process) starting in
2003; and
-10-
* approve as just and reasonable a long-term purchase power agreement
between us and Pinnacle West.
We requested these ACC actions to ensure ongoing reliable service to our
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve our load.
GENERIC DOCKET. In February 2002, the ACC opened a "generic" docket to
"determine if changed circumstances require the [ACC] to take another look at
electric restructuring in Arizona." Also, in February 2002, the ACC docket
relating to our October 2001 filing was consolidated with several other pending
ACC dockets, including the generic docket. On April 19, 2002, we filed a motion
in the consolidated docket addressing the following issues, among others:
* We confirmed our position that whether or not the ACC approved the
matters requested in our October 2001 filing, we would proceed with
the divestiture of our generation assets by the end of 2002.
* We also advised the ACC that whether or not the ACC approved the
matters requested in our October 2001 filing, we would implement a
competitive bidding process later in 2002 to the extent legally
required.
* We noted that Pinnacle West Energy, the affiliate to which we intend
to transfer the generation assets, had committed to a $1 billion
investment in generating capacity to meet our customer needs in
reliance on the 1999 Settlement Agreement and in accordance with an
ACC Rule that prohibited our ownership of new generation assets. We
further noted that we had taken numerous actions in reliance on the
1999 Settlement Agreement and the ACC retail electric competition
rules, including writing off $234 million of prudently incurred costs,
reducing retail rates by approximately $120 million in a still-ongoing
series of rate reductions, and incurring tens of millions of dollars
in expenses related to the expected generation asset transfer. We
stated that if the ACC elects to reverse course on retail electric
competition or attempts to stay the transfer of our generation assets,
the ACC would be legally required to address just compensation to us
and Pinnacle West Energy, which would include, at a minimum:
* recognizing the transfer to us of all assets that Pinnacle West
Energy constructed to meet our load-serving requirements, and
subsequently including such units in our rate base in accordance
with traditional rate-of-return regulation;
* reversing our $234 million write-off and providing for the
recovery of such amounts in future rates; and
* providing for the recovery of all costs incurred as a result of
the transition to competition, including 100 percent of the costs
incurred in preparation for divestiture (and not just the
two-thirds of costs permitted under the 1999 Settlement
Agreement).
-11-
* We recommended that the ACC confirm whether or not Arizona would
proceed with the transition to a competitive electric market, and
proposed a procedural plan in response to issues identified by the ACC
Staff in a previous report.
On April 26, 2002, the ACC issued a procedural order in which the ACC
stayed the previously-scheduled April 29, 2002 hearing on the matters raised in
our October 2001 ACC filing (see "Proposed Rule Variance and Purchase Power
Agreement" above). On May 2, 2002, the ACC issued a procedural order stating
that hearings will begin on June 17, 2002 on various issues ("Track A Issues"),
including our planned divestiture of generation assets to Pinnacle West Energy
and associated market and affiliate issues. The procedural order stated that the
schedule is designed to have a recommended order issued by the administrative
law judge by approximately July 22, 2002, with comments on the recommended order
due from affected parties on July 31, 2002. Under this schedule, August 1, 2002
is the earliest date the ACC could consider a decision on the Track A Issues.
The procedural order also stated that consideration of the competitive
bidding process (the "Track B Issues") required by the Rules would proceed
concurrently with the Track A Issues. The objectives and process of the Track B
Issues will be determined in one or more meetings of affected parties beginning
the week of May 20, 2002, with a "target completion date" of October 21, 2002.
A modification to the Rules or the 1999 Settlement Agreement could, among
other things, adversely affect our ability to transfer our generation assets to
Pinnacle West Energy by December 31, 2002. We cannot predict the outcome of the
consolidated docket or its effect on the specific requests in our October 2001
filing, the existing Arizona electric competition rules, or the 1999 Settlement
Agreement.
FEDERAL
In June 2001, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The plan remains in effect until September 30, 2002. We cannot
accurately predict the overall financial impact of the plan on the various
aspects of our business, including our wholesale and purchased power activities.
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.
6. Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $200 million and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
-12-
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 interest
in the three Palo Verde units, our maximum potential assessment per incident for
all three units 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.
7. Business Segments
We have two principal business segments (determined by products, services
and regulatory environment) which consist of regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
includes activities related to electricity transmission and distribution, as
well as electricity generation. Our marketing and trading business segment
includes activities related to wholesale marketing and trading. During 2001, we
transferred most of our marketing and trading activities, including all of the
related assets and liabilities, to Pinnacle West (see Note 14). Financial data
for the business segments is provided as follows (dollars in millions):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2002 2001 2002 2001
------- ------- ------- -------
Operating Revenues:
Retail $ 383 $ 413 $ 2,533 $ 2,572
Marketing and trading 11 352 407 1,227
------- ------- ------- -------
Total $ 394 $ 765 $ 2,940 $ 3,799
======= ======= ======= =======
Income Before
Accounting Change:
Retail $ 32 $ 4 $ 166 $ 204
Marketing and trading -- 61 81 135
------- ------- ------- -------
Total $ 32 $ 65 $ 247 $ 339
======= ======= ======= =======
-13-
8. Accounting Matters
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." We have no goodwill recorded and have separately disclosed
other intangible assets in our balance sheets. This new standard has no material
impact to our financial statements, and the required disclosures are provided in
Note 13.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions for the disposal of
a segment of a business. This standard did not impact our financial statements
at adoption.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The standard requires 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. We are currently evaluating the impacts of the
new standard, which is effective for the year beginning January 1, 2003.
In 2001, the American Institute of Certified Public Accountants issued an
exposure draft of a proposed Statement of Position, "Accounting for Certain
Costs Related to Property, Plant, and Equipment." This proposed Statement of
Position would create a project timeline framework for capitalizing costs
related to property, plant and equipment construction, which require that
property, plant and equipment assets be accounted for at the component level,
and require administrative and general costs incurred in support of capital
projects to be expensed in the current period. The American Institute of
Certified Public Accountants plans to issue the final Statement of Position in
the fourth quarter of 2002.
9. Off-Balance Sheet Financing
In 1986, we entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. In February 2002, the
FASB discussed issues related to SPEs. It is expected that the FASB will issue
additional guidance on accounting for SPEs later this year. As a result of
future FASB actions, we may be required to consolidate the Palo Verde SPEs in
our financial statements. If consolidation is required, the assets and
liabilities of the SPEs that relate to the sale-leaseback transactions would be
reflected on our balance sheets. The SPE debt that is not reflected on our
balance sheets is approximately $300 million at March 31, 2002. Rating agencies
have already considered this debt when evaluating our credit ratings. This is
the Company's only significant off-balance sheet financing activity.
10. Derivative Instruments
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
-14-
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 and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
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 sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. We use cash flow hedges to limit our exposure to cash flow variability
on forecasted transactions. Hedge effectiveness is related to the degree to
which the derivative contract and the hedged item are correlated. It is measured
based on the relative changes in fair value between the derivative contract and
the hedged item over time. We exclude the time value of certain options from our
assessment of hedge effectiveness. Any change in the fair value resulting from
ineffectiveness is recognized immediately in net income.
On January 1, 2001, we recorded a $3 million after-tax loss in net income
and a $64 million after-tax gain in equity (as a component of other
comprehensive income), both as a cumulative effect of a change in accounting
principle. The gain resulted from unrealized gains on cash flow hedges.
In June 2001, the FASB issued new guidance related to electricity
contracts. The effective date of this new guidance was July 1, 2001. As of July
1, 2001, we recorded an additional $12 million after-tax loss in net income and
an additional $8 million after-tax gain in equity (as a component of other
comprehensive income), as a result of adopting the new guidance related to
electricity contracts. The loss resulted primarily from electricity options
contracts. The gain resulted from unrealized gains on cash flow hedges. The
impact of the new guidance is reflected in net income and other comprehensive
income as a cumulative effect of a change in accounting principle.
In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance is April 1, 2002. We are currently
evaluating the new guidance to determine what impact, if any, it will have on
our financial statements.
The change in derivative fair value included in the statements of income
for the three and twelve months ended March 31, 2002 and 2001 are comprised of
the following (dollars in thousands):
-15-
Three Months Twelve Months
Ended Ended
March 31, March 31,
-------------------- --------------------
2002 2001 2002 2001
-------- -------- -------- --------
Losses on the ineffective
portion of derivatives
qualifying for hedge
accounting $ (111) $ (4,764) $ (3,718) $ (4,764)
Losses from the
discontinuance of cash
flow hedges for
forecasted transactions
that will not occur (1,300) -- (10,826) --
Prior period market-to-
market losses realized
upon delivery of the
commodities 3,813 6,393 23,368 6,393
-------- -------- -------- --------
Total pretax gain $ 2,402 $ 1,629 $ 8,824 $ 1,629
======== ======== ======== ========
As of March 31, 2002, the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is thirty-three months. During the twelve months ending March 31, 2003, we
estimate that a net loss of $7 million before income taxes will be reclassified
from accumulated other comprehensive loss as an offset to the effect on earnings
of market price changes for the related hedged transactions.
-16-
11. Comprehensive Income
Components of comprehensive income for the three and twelve months ended
March 31, 2002 and 2001, are as follows (dollars in thousands):
Three Months Ended Twelve Months Ended
March 31, March 31,
--------------------- ----------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Net income $ 31,763 $ 61,851 $ 235,399 $ 335,670
--------- --------- --------- ---------
Other comprehensive income (losses):
Minimum pension liability, net of tax -- -- (966) --
Cumulative effect of change in
accounting for derivatives, net
of tax -- 64,700 7,777 64,700
Unrealized gains (losses) on
derivative instruments, net of
tax 24,766 (10,453) (49,004) (10,453)
Reclassification of net realized
(gains) losses to income, net of
tax 542 (16,822) (34,489) (16,822)
--------- --------- --------- ---------
Total other comprehensive income (losses) 25,308 37,425 (76,682) 37,425
--------- --------- --------- ---------
Comprehensive income $ 57,071 $ 99,276 $ 158,717 $ 373,095
========= ========= ========= =========
12. Commitments and Contingencies
In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC also
ordered an evidentiary proceeding to discuss and evaluate possible refunds for
the Pacific Northwest. The administrative law judge at the FERC in charge of
that evidentiary proceeding made an initial finding that no refunds were
appropriate. The Pacific Northwest issues will now be addressed by the FERC
Commissioners. Although the FERC has not yet made a final ruling in the Pacific
Northwest matter or calculated the specific refund amounts due in California, we
do not expect that the resolution of these issues, as to the amounts alleged in
the proceedings, will have a material adverse impact on our financial position,
results of operations or liquidity.
On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
failed to properly file rate information at the FERC in connection with sales to
California from 2000 to the present. STATE OF CALIFORNIA V. BRITISH COLUMBIA
POWER EXCHANGE ET. AL., Docket No. EL02-71-000. The complaint requests the FERC
to require the wholesale sellers to refund any rates that are "found to exceed
just and reasonable levels." The complaint indicates that Pinnacle West sold
approximately $106 million of power to the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
-17-
amount above "just and reasonable levels." Pinnacle West believes that the
claims as they relate to Pinnacle West are without merit. In addition, the State
of California and others have filed various claims, which have now been
consolidated, against serveral power suppliers to California alleging antitrust
violations. WHOLESALE ELECTRICITY ANTITRUST CASES I AND II, Superior Court in
and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two
of the suppliers who were named as defendants in those matters, Reliant Energy
Services, Inc. (and other Reliant entities) and Duke Energy Trading and
Marketing, LLP (and other Duke entities), filed cross-claims against various
other participants in the California PX and ISO markets, including us,
attempting to expand those matters to such other participants. We have not yet
filed a responsive pleading in the matter, but we believe the claims by Reliant
and Duke as they relate to us are without merit.
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised us that it believes we have overcharged Citizens by over $50 million
under a power service agreement. We believe that our charges under the agreement
were fully in accordance with the terms of the agreement. In addition, in
testimony filed with the ACC on March 13, 2002, Citizens acknowledged that,
based on its review, "if Citizens filed a complaint with FERC, it probably would
lose the central issue in the contract interpretation dispute." We terminated
the power service agreement with Citizens effective July 15, 2001. In
replacement of the power service agreement, Pinnacle West and Citizens entered
into a power sale agreement under which Pinnacle West will supply Citizens with
specified amounts of electricity and ancillary services through May 31, 2008.
This new agreement does not address issues previously raised by Citizens with
respect to charges under the original power service agreement through June 1,
2001.
13. Intangible Assets
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." The Company's gross intangible assets (which are primarily
software) were $173 million at March 31, 2002 and $170 million at December 31,
2001. The related accumulated amortization was $90 million at March 31, 2002 and
$87 million at December 31, 2001. Amortization expense for the three-month
period ended March 31 was $4 million in 2002 compared with $5 million in 2001.
Amortization expense for the twelve-month period ended March 31, 2002 and 2001
was $20 million. Estimated amortization expense on existing intangible assets
over the next five years is $16 million in 2002, $14 million in 2003, $14
million in 2004, $12 million in 2005 and $11 million in 2006.
-18-
14. Related Party Transactions
During 2001, we transferred most of our marketing and trading activities to
Pinnacle West, which approximated $219 million in assets and $149 million in
liabilities. From time to time, we enter into transactions with Pinnacle West or
Pinnacle West's subsidiaries. The following table summarizes the amounts
included in the income statements and balance sheets related to transactions
with affiliated companies (dollars in millions):
Three Months Twelve Months
Ended Ended
March 31, March 31,
------------------ -------------------
2002 2001 2002 2001
------ ------ ------ ------
Electric operating revenues:
Pinnacle West - marketing
and trading $ 17 $ -- $ 67 $ --
APSES -- 5 10 31
------ ------ ------ ------
Total $ 17 $ 5 $ 77 $ 31
====== ====== ====== ======
Purchased power and fuel costs:
Pinnacle West - marketing
and trading $ 6 $ 12 $ 44 $ 12
Pinnacle West Energy -- -- 14 --
------ ------ ------ ------
Total $ 6 $ 12 $ 58 $ 12
====== ====== ====== ======
As of As of
March 31, December 31,
2002 2001
--------- ------------
Accounts receivable - other:
Pinnacle West - marketing
and trading $ 56 $ 76
Pinnacle West 24 24
APSES 1 13
Pinnacle West Energy 2 2
------ ------
Total $ 83 $ 115
====== ======
Accounts payable:
Pinnacle West - marketing
and trading $ 42 $ 21
Pinnacle West 47 36
Pinnacle West Energy -- 2
------ ------
Total $ 89 $ 59
====== ======
-19-
ARIZONA PUBLIC SERVICE COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
INTRODUCTION
In this section, we explain the results of operations, general financial
condition, and outlook including:
* the changes in our earnings for the three and twelve months ended
March 31, 2002 and 2001;
* the effects of regulatory agreements on our results and outlook;
* our capital needs, liquidity and capital resources;
* our business outlook; and
* our management of market risks.
We suggest this section be read along with the 2001 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 in this report. These Notes add further details to the discussion.
OVERVIEW OF OUR BUSINESS
We are Arizona's largest electric utility and provide either retail or
wholesale electric service to substantially all of the state, with the major
exceptions of the Tucson metropolitan area and about one-half of the Phoenix
metropolitan area. We also generate and, through Pinnacle West's marketing and
trading division, sell and deliver electricity to wholesale customers in the
western United States. Pinnacle West owns all of our outstanding stock.
We are required to transfer our competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, we have been addressing the legal and regulatory
requirements necessary to complete the transfer of our generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail in Note
5, recent Arizona regulatory developments have raised uncertainty about the
status and pace of retail electric competition in Arizona, including our
transfer of generation assets to Pinnacle West Energy.
BUSINESS SEGMENTS
We have two principal business segments determined by products, services
and regulatory environment, which consist of our regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
includes activities related to electricity transmission and distribution, as
well as electricity generation. Our marketing and trading segment includes
-20-
activities related to wholesale marketing and trading. During 2001, we
transferred most of our marketing and trading activities to Pinnacle West (see
Note 14).
The following table summarizes net income by business segment for the three
and twelve months ended March 31, 2002 and the comparable prior-year periods
(dollars in millions):
Three Months Twelve Months
Ended Ended
March 31, March 31,
------------------- --------------------
2002 2001 2002 2001
------- ------- ------- -------
Retail $ 32 $ 4 $ 166 $ 204
Marketing and trading -- 61 81 135
------- ------- ------- -------
Income before accounting
change 32 65 247 339
Cumulative effect of change
in accounting - net of
income taxes -- (3) (12) (3)
------- ------- ------- -------
Net income $ 32 $ 62 $ 235 $ 336
======= ======= ======= =======
OPERATING RESULTS
OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2002 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 2001
Our net income for the three months ended March 31, 2002 was $32 million
compared with $62 million for the same period in the prior year. In 2001, we
recognized a $3 million after-tax loss in net income as the cumulative effect of
a change in accounting for derivatives, as required by SFAS No.133.
Income before accounting change for the three months ended March 31, 2002
was $32 million compared with $65 million for the same period in the prior year.
The period-to-period decrease is the result of lower marketing and trading
earnings contributions and a retail electricity price decrease. These negative
factors were partially offset by lower costs for replacement power due to lower
market prices and less outages, power plant maintenance, and generation
reliability. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
-21-
Increase
(Decrease)
----------
Increases (decreases) in electric revenues, net of purchased power and fuel
expense due to:
Marketing and trading activities:
Decrease from generation sales other than native load due to lower
market prices and resulting lower sales volumes $ (47)
Increase in other realized marketing and trading in the current period
primarily due to higher unit margins on increased volumes 6(a)
Change in prior-period mark-to-market gains for contracts delivered
during the current period (b) (13)(a)
Lower mark-to-market gains for future-period deliveries (b) (46)
----------
Net decrease in marketing and trading (100)
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages 50
Increased fuel costs related to higher hedged natural gas and
purchased power prices (16)
Change in mark-to-market for hedged natural gas and purchased power
costs for future-period deliveries related to accounting for
derivatives 3
Effects of milder weather on retail sales (6)
Higher retail sales volumes due to customer growth and higher average
usage excluding weather effects 4
Retail price reductions effective July 1, 2001 (5)
Miscellaneous factors - net 2
----------
Total decrease in electric revenues, net of purchased power and fuel expense (68)
Lower operations and maintenance expenses primarily related to reliability,
outage and maintenance costs partially offset by higher employee benefit
costs 5
Lower depreciation and amortization primarily due to lower regulatory asset
amortization 6
Miscellaneous items, net 2
----------
Decrease in income before income taxes (55)
Lower income taxes primarily due to lower income 22
----------
Decrease in income before accounting change $ (33)
==========
- ----------
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) realized during the current period decreased $7
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
-22-
Electric operating revenues decreased approximately $370 million primarily
because of:
* changes in marketing and trading revenues ($341 million, net decrease) due
to:
- decreased revenues related to generation sales other than native load
due to lower market prices and resulting lower sales volumes ($81
million);
- decreased realized revenues related to other realized marketing and
trading in the current period primarily due to lower prices ($208
million);
- change in prior-period mark-to-market gains on contracts delivered
during the current period ($6 million decrease);
- lower mark-to-market gains for future-period deliveries primarily as a
result of lower market price volatility ($46 million);
* decreased revenues related to other wholesale sales as a result of lower
sales volumes and lower prices ($24 million);
* decreased retail revenues related to milder weather ($9 million);
* increased retail revenues related to customer growth and higher usage
excluding weather effects ($7 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($5 million); and
* other miscellaneous factors ($2 million increase).
Purchased power and fuel expenses decreased approximately $302 million
primarily because of:
* changes in purchased power and fuel costs related to marketing and trading
activities ($241 million, net decrease) due to:
- decreased fuel costs related to generation sales other than native
load primarily because of lower sales volumes and lower natural gas
prices ($34 million);
- decreased purchased power costs related to other realized marketing
and trading in the current period primarily due to lower prices ($214
million);
- change in prior-period mark-to-market fuel costs for current-period
deliveries related to accounting for derivatives ($7 million
increase);
* decreased costs related to other wholesale sales as a result of lower sales
volumes and lower prices ($24 million);
* increased fuel costs related to higher hedged natural gas and purchased
power prices ($16 million);
* change in mark-to-market for hedged natural gas and purchased power costs
for future-period deliveries related to accounting for derivatives ($3
million decrease);
* decreased costs related to the effects of milder weather on retail sales
($3 million);
* increased costs related to retail sales growth excluding weather effects
($3 million); and
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($50 million).
-23-
The decrease in operations and maintenance expenses of $5 million primarily
related to costs incurred in 2001 for the generation reliability program (the
addition of generation capacity to enhance reliability for the summer of 2001)
and plant outages and maintenance ($7 million). These factors were partially
offset by increased employee benefit and other costs in the current period ($2
million).
The decrease in depreciation and amortization expenses of $6 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 Settlement Agreement.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2002 COMPARED WITH
TWELVE-MONTH PERIOD ENDED MARCH 31, 2001
Our net income for the twelve months ended March 31, 2002 was $235 million
compared with $336 million for the same period in the prior year. We recognized
a $12 million after-tax loss in the twelve months ended March 31, 2002 and a $3
million after-tax loss in the twelve months ended March 31, 2001 as cumulative
effects of change in accounting for derivatives, as required by SFAS No.133.
Income before accounting change for the twelve months ended March 31, 2002
was $247 million compared with $339 million for the same period a year earlier.
The period-to-period decrease was primarily due to lower marketing and trading
results; continuing retail electricity price decreases; higher hedged purchased
power and fuel costs; costs of generation reliability measures; and charges
related to Enron and its affiliates. These negative factors were partially
offset by lower replacement power costs. The major factors that increased
(decreased) income before accounting change were as follows (dollars in
millions):
-24-
Increase
(Decrease)
----------
Increases (decreases) in electric revenues, net of purchased power and fuel
expense due to:
Marketing and trading activities:
Decrease from generation sales other than native load due to
lower market prices and resulting lower sales volumes $ (68)
Increase in other realized marketing and trading in the current
period primarily due to higher unit margins on decreased sales
volumes 5(a)
Change in prior-period mark-to-market gains for contracts
delivered in the current period (b) 20(a)
Decrease in mark-to-market gains for future-period deliveries (b) (45)
----------
Net decrease in marketing and trading (88)
Lower replacement power costs for plant outages related to lower
market prices and fewer unplanned outages 24
Retail price reductions effective July 1, 2001 and 2000 (27)
Charges related to purchased power contracts with Enron and its
affiliates(c) (13)
Change in mark-to-market for hedged natural gas and purchased
power costs for future-period deliveries related to accounting for
derivatives (9)
Higher purchased power costs related to 2001 generation reliability
program (30)
Higher hedged cost of purchased power and fuel and lower usage, partially
offset by higher retail sales primarily related
to customer growth and weather impacts (20)
----------
Total decrease in electric revenues, net of purchased power and fuel
expense (163)
Higher operations and maintenance expense primarily related to
increased employee benefit costs and the 2001 generation
reliability program (24)
Lower depreciation and amortization primarily due to lower regulatory
asset amortization 13
Lower net interest expense primarily due to lower interest rates 13
Lower other net expense primarily related to insurance recovery 18
Miscellaneous items, net (3)
----------
Net decrease in income before income taxes (146)
Lower income taxes primarily due to lower income 55
----------
Net decrease in income before accounting change $ (91)
==========
- ----------
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) realized during the current period increased $25
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
(c) We recorded charges totaling $13 million for exposure to Enron and its
affiliates in the fourth quarter of 2001.
-25-
Electric operating revenues decreased approximately $859 million primarily
because of:
* changes in marketing and trading revenues ($820 million, net decrease) due
to:
- decreased revenues related to generation sales other than native load
as a result of lower market prices and resulting lower sales volumes
($126 million);
- decreased realized revenues related to other marketing and trading in
the current period primarily due to lower sales volumes ($675
million);
- change in prior-period mark-to-market gains for contracts delivered
during the current period ($27 million increase);
- decreased mark-to-market gains for future-period deliveries primarily
because of higher sales volumes ($46 million);
* decreased wholesale and other revenues as a result of lower sales volumes
($67 million);
* higher retail sales related to customer growth and weather impacts,
partially offset by lower average residential usage ($55 million); and
* decreased retail revenues related to reductions in retail electricity
prices effective July 1, 2001 and 2000 ($27 million).
Purchased power and fuel expenses decreased approximately $696 million
primarily because of:
* changes in purchased power and fuel costs related to marketing and trading
activities ($732 million, net decrease) due to:
- decreased fuel costs related to generation sales other than native
load as a result of lower sales volumes ($58 million);
- decreased fuel and purchased power costs related to other realized
marketing and trading in the current period primarily due to lower
sales volumes ($680 million);
- change in prior-period mark-to-market fuel costs for current-period
deliveries related to accounting for derivatives ($7 million
increase);
- change in mark-to-market fuel costs for future-period deliveries
related to accounting for derivatives ($1 million decrease);
* decreased costs related to other wholesale sales as a result of lower sales
volumes ($67 million);
* lower replacement power costs primarily due to lower market prices and
fewer unplanned outages ($24 million);
* higher purchased power costs related to 2001 generation reliability program
($30 million);
* higher costs related to retail sales as a result of the higher hedged cost
of purchased power and fuel and higher retail sales volumes related to
customer growth and weather impacts ($75 million);
* change in mark-to-market for hedged natural gas and purchased power costs
for future-period deliveries related to accounting for derivatives ($9
million increase) and;
* charges related to purchased power contracts with Enron and its affiliates
($13 million).
-26-
The increase in operations and maintenance expenses of $24 million
primarily related to increased employee benefit and other costs ($16 million)
and the 2001 generation reliability program (the addition of generating
capability to enhance reliability for the summer of 2001) and scheduled plant
outages and maintenance ($8 million increase).
The decrease in depreciation and amortization expenses of $13 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 regulatory settlement agreement.
Net other expense decreased $18 million primarily because of an insurance
recovery of environmental remediation costs, partially offset by other
non-operating costs.
Net interest expense decreased by $13 million primarily because of lower
interest rates.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the
three months ended March 31, 2002 and estimated capital expenditures for the
next three years (dollars in millions):
Three Estimated
Months ----------------------------
Ended Years Ended December 31,
March 31, ----------------------------
2002 2002 2003 2004
-------- ------ ------ ------
Delivery $ 92 $ 349 $ 271 $ 280
Existing generation (a) 27 149 -- --
------ ------ ------ ------
Total $ 119 $ 498 $ 271 $ 280
====== ====== ====== ======
- ----------
(a) Pursuant to the 1999 Settlement Agreement, we are required to transfer our
competitive electric assets and services no later than December 31, 2002.
See Note 5.
We and the other Palo Verde participants are currently considering issues
related to replacement of the steam generators in Units 1 and 3. Although a
final determination of whether Units 1 and 3 will require steam generator
replacement to operate over their current full licensed lives has not yet been
made, we and the other participants have approved an expenditure in 2002 to
procure long lead-time materials for fabrication of a spare set of steam
generators for either Unit 1 or 3. Our portion of this expenditure is
approximately $7 million and is included in the estimated expenditures above.
This action will provide the Palo Verde participants an option to replace the
steam generators at either Unit 1 or 3 as early as fall 2005 should they
ultimately choose to do so.
Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants. Examples of the types
of projects included in this category are additions, upgrades and capital
replacements of various power plant equipment such as turbines, boilers, and
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environmental equipment. The existing generation also contains nuclear fuel
expenditures of approximately $30 million only in 2002.
Delivery capital expenditures are comprised of T&D infrastructure additions
and upgrades, capital replacements, new customer construction, and related
information systems and facility costs. Examples of the types of projects
included in the forecast include T&D lines and substations, line extensions to
new residential and commercial developments, and upgrades to customer
information systems. In addition, we began several major transmission projects
in 2001. These projects are periodic in nature and are driven by strong regional
customer growth. We expect to spend about $150 million on major transmission
projects during the 2002-2004 time frame.
CAPITAL RESOURCES AND CASH REQUIREMENTS
The following table summarizes actual cash commitments for the three months
ended March 31, 2002 and estimated commitments for the next three years (dollars
in millions):
Three Estimated
Months ----------------------------
Ended Years Ending December 31,
March 31, ----------------------------
2002 2002 2003 2004
-------- ------ ------ ------
Long-term debt payments $ 125 $ 247 $ -- $ 205
Operating leases payments 4 63 61 61
Fuel and purchase power commitments 46 252 124 80
------ ------ ------ ------
Total cash commitments $ 175 $ 562 $ 185 $ 346
====== ====== ====== ======
Our cash requirements and our ability to fund those requirements are
discussed under "Capital Needs and Resources" in Management's Discussion and
Analysis of Financial Condition and Results of Operation in Part II, Item 7 of
the 2001 10-K.
During the three-months ended March 31, 2002, we increased our outstanding
indebtedness by about $375 million. On March 1, 2002, we issued $375 million of
6.50% Notes due 2012. See the cash commitments table above for our debt
repayments. Based on market conditions and optional call provisions, we may make
optional redemptions of long-term debt from time to time.
As of March 31, 2002, we deposited $122 million, plus interest, with the
trustee under our Mortgage for the redemption in April 2002 of our First
Mortgage Bonds, 8.75% Series due 2024.
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.
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CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses, and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from
those estimates. Our most critical accounting policies include the determination
of the appropriate accounting for our derivative instruments, mark-to-market
accounting and the impacts of regulatory accounting on our financial statements.
See Note 1 in the 2001 10-K.
BUSINESS OUTLOOK
For 2001, our reported income before accounting change was $281 million and
included charges totaling $13 million before income taxes that we do not expect
to recur related to our exposure to Enron and its affiliates. Our earnings in
2002 are expected to be negatively affected by a significant decrease in the
earnings contribution from our marketing and trading activities and retail
electricity price decreases. These negative factors are expected to be
substantially offset in 2002 by the absence of significant expenses for
reliability and power plant outages that we incurred in 2001 that we do not
expect to recur in 2002 and by retail customer growth, although the pace of
growth is expected to be slower than in the past. These factors are described in
more detail below.
As of December 31, 2001, we completed the transition of most of our
marketing and trading activities to Pinnacle West's marketing and trading
division.
During 2001, in order to meet the highest customer demand in our history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts
cost approximately $140 million before income taxes, which is not expected to be
repeated in 2002.
We estimate our retail customer growth in 2002 to be 3.2%, which is slower
than the pace of growth in recent years, although still about three times the
national average. Our customer growth in 2001 was 3.7%. We expect the customer
growth rate to be weak in the first two quarters of 2002, then begin a rebound.
Our current estimate for customer growth in 2003 and 2004 is between 3.5% and
4.0% annually.
The foregoing discussion of future expectations is forward-looking
information. Actual results may differ materially from expectations. See
"Forward-Looking Statements" below.
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COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See "Business Outlook - Competition and Industry Restructuring" in Item 7
of the 2001 10-K and Note 5 above for a discussion of developments affecting
retail and wholesale electric competition.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona, and from competitive retail and wholesale
bulk power markets in the western United States. 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.
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 about 4% a year for the three years 1999 through
2001; we currently expect customer growth to be about 3.2% in 2002 and between
3.5% and 4.0% a year in 2003 and 2004. We currently estimate that retail
electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in 2002
through 2004, 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. As previously noted, under the 1999 Settlement Agreement, we
have retail electricity price reductions of 1.5% annually through July 1, 2003
(see Note 5).
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, new generating plants being placed
in service 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, outages and other factors.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, changes in regulatory
asset amortization, and our generation expansion program.
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. Our average property tax rate was 9.32% for 2001 and 9.16% for
2000. We expect property taxes to increase primarily due to our additions to
existing facilities.
Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factor affecting borrowing levels in
the next several years are expected to be our internally-generated cash flow.
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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 10 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 5 for a discussion of a price reduction effective as of July 1,
2001, 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
The above discussion 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, including the introduction of retail
electric competition in Arizona; the outcome of regulatory and legislative
proceedings relating to the restructuring; state and federal regulatory and
legislative decisions and actions, including the price mitigation plan adopted
by the FERC in June 2001; regional economic and market conditions, including the
California energy situation and completion of generation construction in the
region, 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 interest
rates, commodity prices, and investments held by our 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 risks associated with
these market fluctuations by utilizing various commodity derivatives, including
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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 and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
In 2001, subject to specified risk parameters established by Pinnacle
West's Board of Directors and monitored by Pinnacle West's ERMC, we engaged in
trading activities intended to profit from market price movements. In accordance
with Emerging Issues Task Force (EITF) 98-10, "Accounting For Contracts Involved
in Energy Trading and Risk Management Activities," such trading positions were
marked-to-market. These trading activities were part of our marketing and
trading activities and were reflected in our 2001 marketing and trading revenues
and expenses.
As of March 31, 2002, a hypothetical adverse price movement of 10% in the
market price of our risk management and trading assets and liabilities would
have decreased the fair market value of these contracts by approximately $24
million. A hypothetical favorable price movement of 10% would have increased the
fair market value of these contracts by approximately $26 million.
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of counterparties. Despite the fact that the great majority
of 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.
Counterparties in the portfolio consist principally of major energy companies,
municipalities, and local distribution companies. We maintain credit policies
that we believe minimize overall credit risk to within acceptable limits.
Determination of the credit quality of our counterparties is based upon a number
of factors, including credit ratings and our evaluation of their financial
condition. In many contracts, we employ collateral requirements and standardized
agreements that allow for the netting of positive and negative exposures
associated with a single counterparty. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our 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.
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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 5 of Notes to Condensed Financial Statements in Part I, Item 1 of
this report for a discussion of regulatory developments regarding the
introduction of retail electric competition in Arizona and related matters.
PALO VERDE NUCLEAR GENERATING STATION
In February 2002 the U.S. Secretary of Energy recommended to President Bush
that the Yucca Mountain, Nevada site be developed as a permanent repository for
spent nuclear fuel. See Note 10 of Notes to Financial Statements of the 2001
10-K. The President transmitted this recommendation to Congress and the State of
Nevada has vetoed the President's recommendation. A congressional decision on
whether to override the Nevada veto is expected sometime during the summer of
2002. We cannot currently predict what further steps will be taken in this area.
ENVIRONMENTAL MATTERS
The EPA reviewed an "Annex" to the GCVTC recommendations and, on April 26,
2002, the EPA proposed to accept the GCVTC's Annex, submitted by the Western
Regional Air Partnership (successor to GCVTC) in September 2000. See
"Environmental Matters - EPA Environmental Regulations - Clean Air Act" in Part
I, Item 1 of the 2001 10-K. The Annex specifies regional sulfur dioxide emission
reduction milestones. The EPA's final approval of the Annex would allow the
GCVTC states and tribes to pursue the alternate implementation of the regional
haze rules through 2018. Any states and tribes that implement this option would
have to submit state implementation plans by 2003 to address visibility in areas
identified in the GCVTC process, and revised implementation plans in 2008 to
address Class I Areas which were not included in the GCVTC process. The State of
Arizona is in the process of developing a State Implementation Plan to implement
the provisions of the Annex. Because Four Corners is located on the Navajo
Reservation and is currently regulated by EPA Region IX, the provisions of the
Annex currently could become applicable to Four Corners only through a Federal
Implementation Plan promulgated by EPA Region IX. At this time, it is uncertain
how the State of Arizona and/or EPA Region IX will proceed to implement the
Annex, so the actual impact on us cannot yet be determined.
In February 2001, the U.S. Supreme Court found, among other things, that
the EPA implementation policy for revised ozone standards was unlawful, and
remanded this issue for consideration along with other preserved challenges to
the National Ambient Air Quality Standards. See "Environmental Matters - EPA
Environmental Regulation - Clean Air Act" in the 2001 10-K. On remand, on March
26, 2002, the U.S. Court of Appeals for the District of Columbia upheld the more
stringent eight-hour ozone standard and the particulate matter standard.
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Because the actual level of emissions controls, if any, for any unit cannot be
determined at this time, we currently cannot estimate the capital expenditures,
if any, which would result from the final rules. However, we do not currently
expect these rules to have a material adverse effect on our financial position,
results of operations, or liquidity.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
12.1 Ratio of Earnings to Fixed Charges
In addition, the Company hereby incorporates the following Exhibits
pursuant to Exchange Act Rule 12b-32 and Regulation section 229.10(d) by
reference to the filings set forth below:
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Originally Filed Date
Exhibit No. Description as Exhibit: File No.(a) Effective
- ----------- ----------- -------------------- ----------- ---------
3.1 Articles of Incorporation 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, Registration Nos.
1988 33910 and 33--55248
by means of September
24, 1993 Form 8-K
Report
3.2 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 1-20-00
February 20, 1996 Report
10.1 Amendment No. 5 to the 10.1 to Pinnacle West's 1-8962 5-15-02
Amended and Restated March 2002 10-Q Report
Decommissioning Trust
Agreement (PVNGS
Unit 2), dated as of
June 30, 2000
10.2 Amendment No. 3 to the 10.2 to Pinnacle West's 1-8962 5-15-02
Decommissioning Trust March 2002 10-Q
Agreement (PVNGS Report
Unit 1), dated as of
March 18, 2002
10.3 Amendment No. 6 to the 10.3 to Pinnacle West's 1-8962 5-15-02
Amended and Restated March 2002 10-Q
Decommissioning Trust Report
Agreement (PVNGS
Unit 2), dated as of
March 18, 2002
10.4 Amendment No. 3 to the 10.4 to Pinnacle West's 1-8962 5-15-02
Decommissioning Trust March 2002 10-Q
Agreement (PVNGS Report
Unit 3), dated as of
March 18, 2002
- ----------
(a) Reports filed under File No. 1-8962 and 1-4473 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
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(b) Reports on Form 8-K
During the quarter ended March 31, 2002, and the period from April 1
through May 15, 2002, we filed the following reports on Form 8-K:
Report dated December 14, 2001 regarding (i) the Arizona Supreme Court
dismissal of an appeal related to the 1999 Settlement Agreement and (ii) a new
ACC generic docket related to electric restructuring in Arizona.
Report dated February 8, 2002 regarding the consolidation of pending ACC
dockets.
Report dated February 26, 2002 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-63994 and 333-83398) related to
the Company's offering of $375 million of Notes.
Report dated April 19, 2002 regarding a motion filed by the Company in a
consolidated ACC docket.
Report dated April 26, 2002 regarding ACC procedural orders.
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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, 2002 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)
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