FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 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 November 5, 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
ADEQ - Arizona Department of Environmental Quality
APS Energy Services - APS Energy Services Company, Inc., a Pinnacle West
subsidiary
Bookout - one party appears more than once in a contract path for the purchase
and sale of a commodity, resulting in an unplanned net settlement
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Arizona Public Service Company
EITF - Emerging Issues Task Force
El Paso - El Paso Natural Gas Company
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
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
PG&E - PG&E Corp.
Pinnacle West - Pinnacle West Capital Corporation
Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West
subsidiary
PPA - Purchase Power Agreement between Arizona Public Service Company and
Pinnacle West
PX - California Power Exchange
RTO - regional transmission organization
Rules - ACC retail electric competition rules
Salt River Project - Salt River Project Agricultural Improvement and Power
District
SCE - Southern California Edison Company
SFAS - Statement of Financial Accounting Standards
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 September 30,
--------------------------
2001 2000
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ......................................... $ 1,048,634 $ 1,565,622
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Purchased power ................................................... 505,867 977,103
Fuel for electric generation ...................................... 81,751 99,460
----------- -----------
Total .......................................................... 587,618 1,076,563
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .............. 461,016 489,059
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs 120,762 110,676
Depreciation and amortization ..................................... 105,771 112,848
Income taxes ...................................................... 70,017 80,317
Other taxes ....................................................... 29,327 25,629
----------- -----------
Total .......................................................... 325,877 329,470
----------- -----------
OPERATING INCOME .................................................... 135,139 159,589
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ...................................................... 1,752 1,446
Other - net ....................................................... (1,650) (3,599)
----------- -----------
Total .......................................................... 102 (2,153)
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................................... 135,241 157,436
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................................ 29,211 33,681
Interest on short-term borrowings ................................. 1,331 1,634
Debt discount, premium and expense ................................ 666 566
Capitalized interest .............................................. (3,523) (2,676)
----------- -----------
Total .......................................................... 27,685 33,205
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE ..................................... 107,556 124,231
Cumulative Effect of a Change in Accounting for Derivatives -
net of income taxes of $8,099 ................................... (12,446) --
----------- -----------
NET INCOME .......................................................... $ 95,110 $ 124,231
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Nine Months
Ended September 30,
--------------------------
2001 2000
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ......................................... $ 2,875,045 $ 2,730,997
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Purchased power ................................................... 1,315,465 1,259,151
Fuel for electric generation ...................................... 325,208 230,972
----------- -----------
Total .......................................................... 1,640,673 1,490,123
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .............. 1,234,372 1,240,874
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs 356,355 323,485
Depreciation and amortization ..................................... 314,110 321,642
Income taxes ...................................................... 156,425 163,669
Other taxes ....................................................... 80,071 76,606
----------- -----------
Total .......................................................... 906,961 885,402
----------- -----------
OPERATING INCOME .................................................... 327,411 355,472
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ...................................................... (33) 1,615
Other - net ....................................................... 1,915 (4,021)
----------- -----------
Total .......................................................... 1,882 (2,406)
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................................... 329,293 353,066
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................................ 93,031 99,626
Interest on short-term borrowings ................................. 3,807 6,754
Debt discount, premium and expense ................................ 2,001 1,411
Capitalized interest .............................................. (11,347) (7,582)
----------- -----------
Total .......................................................... 87,492 100,209
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE ..................................... 241,801 252,857
Cumulative Effect of a Change in Accounting for Derivatives -
net of income taxes of $9,892 ................................... (15,201) --
----------- -----------
NET INCOME .......................................................... $ 226,600 $ 252,857
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended September 30,
--------------------------
2001 2000
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES ......................................... $ 3,624,300 $ 3,230,874
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Purchased power ................................................... 1,603,778 1,353,477
Fuel for electric generation ...................................... 425,510 295,842
----------- -----------
Total .......................................................... 2,029,288 1,649,319
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .............. 1,595,012 1,581,555
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs 462,962 447,179
Depreciation and amortization ..................................... 417,947 422,739
Income taxes ...................................................... 192,733 184,667
Other taxes ....................................................... 103,195 100,177
----------- -----------
Total .......................................................... 1,176,837 1,154,762
----------- -----------
OPERATING INCOME .................................................... 418,175 426,793
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ...................................................... 2,664 9,398
Other - net ....................................................... (4,921) (11,814)
----------- -----------
Total .......................................................... (2,257) (2,416)
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................................... 415,918 424,377
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................................ 127,836 133,469
Interest on short-term borrowings ................................. 4,508 8,247
Debt discount, premium and expense ................................ 2,695 1,866
Capitalized interest .............................................. (14,659) (7,540)
----------- -----------
Total .......................................................... 120,380 136,042
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE ..................................... 295,538 288,335
Cumulative Effect of a Change in Accounting for Derivatives -
net of income taxes of $9,892 ................................... (15,201) --
----------- -----------
NET INCOME .......................................................... $ 280,337 $ 288,335
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Unaudited)
September 30, December 31,
2001 2000
----------- -----------
(Dollars in Thousands)
UTILITY PLANT:
Electric plant in service and held for future use $ 8,053,950 $ 7,805,025
Less accumulated depreciation and amortization ... 3,337,314 3,187,328
----------- -----------
Total ......................................... 4,716,636 4,617,697
Construction work in progress .................... 255,628 245,749
Nuclear fuel, net of amortization ................ 54,853 47,389
----------- -----------
Utility plant - net ........................... 5,027,117 4,910,835
----------- -----------
INVESTMENTS AND OTHER ASSETS ..................... 258,138 269,678
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ........................ 14,947 2,609
Trust fund for bond redemption ................... 72,370 --
Accounts receivable:
Service customers ............................. 408,843 422,012
Other ......................................... 139,000 48,711
Allowance for doubtful accounts ............... (2,821) (2,380)
Accrued utility revenues ......................... 102,951 74,566
Materials and supplies, at average cost .......... 81,304 71,966
Fossil fuel, at average cost ..................... 24,833 19,405
Deferred income taxes ............................ 5,793 5,793
Assets from risk management and trading activities 13,800 17,506
Other ............................................ 38,665 38,414
----------- -----------
Total current assets .......................... 899,685 698,602
----------- -----------
DEFERRED DEBITS:
Regulatory assets ................................ 370,943 469,867
Unamortized debt issue costs ..................... 11,647 12,805
Other ............................................ 52,832 37,928
----------- -----------
Total deferred debits ......................... 435,422 520,600
----------- -----------
TOTAL ......................................... $ 6,620,362 $ 6,399,715
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES
(Unaudited)
September 30, December 31,
2001 2000
----------- ----------
(Dollars in Thousands)
CAPITALIZATION:
Common stock .......................................... $ 178,162 $ 178,162
Additional paid-in capital ............................ 1,246,804 1,246,804
Retained earnings ..................................... 793,901 694,802
Accumulated Other Comprehensive Loss .................. (66,609) --
----------- ----------
Common stock equity ................................ 2,152,258 2,119,768
Long-term debt less current maturities ................ 1,620,523 1,806,908
----------- ----------
Total capitalization ............................... 3,772,781 3,926,676
----------- ----------
CURRENT LIABILITIES:
Commercial paper ...................................... 174,500 82,100
Current maturities of long-term debt .................. 375,266 250,266
Accounts payable ...................................... 227,149 267,999
Accrued taxes ......................................... 305,842 106,515
Accrued interest ...................................... 16,484 39,488
Customer deposits ..................................... 27,169 24,498
Liabilities from risk management and trading activities 44,107 37,179
Other ................................................. 90,758 104,947
----------- ----------
Total current liabilities .......................... 1,261,275 912,992
----------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ................................. 1,010,539 1,110,437
Unamortized gain - sale of utility plant .............. 65,204 68,636
Customer advances for construction .................... 68,763 40,694
Other ................................................. 441,800 340,280
----------- ----------
Total deferred credits and other ................... 1,586,306 1,560,047
----------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 9)
TOTAL .............................................. $ 6,620,362 $6,399,715
=========== ==========
See Notes to Condensed Financial Statements.
-7-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30,
----------------------
2001 2000
--------- ---------
(Dollars in Thousands)
Cash Flows from Operating Activities:
INCOME BEFORE ACCOUNTING CHANGE .................... $ 241,801 $ 252,857
Items not requiring cash:
Depreciation and amortization .................... 314,110 321,642
Nuclear fuel amortization ........................ 22,221 23,139
Deferred income taxes - net ...................... (46,664) (73,729)
Changes in certain current assets and liabilities:
Accounts receivable - net ........................ (76,679) (446,059)
Accrued utility revenues ......................... (28,385) (38,396)
Materials, supplies and fossil fuel .............. (14,766) 3,787
Other current assets ............................. (251) (8,439)
Accounts payable ................................. (46,542) 298,198
Accrued taxes .................................... 199,327 145,999
Accrued interest ................................. (23,004) (8,699)
Other current liabilities ........................ (11,518) 24,350
Risk management and trading activities - net ..... (14,116) 17,934
Other - net ........................................ 14,733 26,619
--------- ---------
Net cash flow provided by operating activities .. 530,267 539,203
--------- ---------
Cash Flows from Investing Activities:
Trust fund for bond redemption ..................... (72,370) --
Capital expenditures ............................... (324,878) (278,282)
Capitalized interest ............................... (11,347) (7,582)
Other .............................................. (12,370) 18,349
--------- ---------
Net cash flow used for investing activities .... (420,965) (267,515)
--------- ---------
Cash Flows from Financing Activities:
Long-term debt ..................................... -- 300,000
Short-term borrowings - net ........................ 92,400 (36,300)
Dividends paid on common stock ..................... (127,500) (127,500)
Repayment and reacquisition of long-term debt ...... (61,864) (352,000)
--------- ---------
Net cash flow used for financing activities .... (96,964) (215,800)
--------- ---------
Net increase in cash and cash equivalents ............ 12,338 55,888
Cash and cash equivalents at beginning of period ..... 2,609 7,477
--------- ---------
Cash and cash equivalents at end of period ........... $ 14,947 $ 63,365
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........ $ 108,842 $ 96,723
Income taxes ..................................... $ 41,705 $ 133,817
See Notes to Condensed Financial Statements.
-8-
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Our unaudited Condensed Financial Statements reflect all adjustments which
we believe are necessary for the fair presentation of our financial position and
results of operations for the periods presented. These adjustments are of a
normal recurring nature with the exception of the cumulative effect of a change
in accounting for derivatives (see Note 10). 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 period amounts to conform to
current period presentation.
2. Weather conditions and trading 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 nine months ended September 30, 2001.
5. Regulatory Accounting
We are regulated by the ACC and 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 pretax ($183 million net present
value) from ongoing regulatory cash flows and was recorded as a net reduction of
regulatory assets. This reduction ($140 million after income taxes was reported
as an extraordinary charge on the income statement during the third quarter of
1999. Prior to the 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.
-9-
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)
September 30, December 31,
2001 2000
----------- -----------
Electric plant in service and held for future use .......... $ 3,897,732 $ 3,856,600
Accumulated depreciation and amortization .................. (1,771,158) (1,693,079)
Construction work in progress .............................. 97,537 86,329
Nuclear fuel, net of amortization .......................... 54,853 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,
petitioned the Arizona Supreme Court for review of the Court of Appeals'
decision. On October 5, 2001, the Arizona Supreme Court agreed to hear the
appeal on the singular issue of whether the ACC could itself become a party to
the Settlement Agreement by virtue of its approval of the Settlement Agreement.
The Supreme Court has not yet set a date for oral argument on this matter.
The following are the major provisions of the 1999 Settlement Agreement, as
approved:
-10-
* 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
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
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 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 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 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
-11-
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 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.
PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. As authorized by the
1999 Settlement Agreement, we intend to move substantially all of our generation
assets to Pinnacle West Energy no later than December 31, 2002. Commencing upon
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 power marketing 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 (a) grant us a partial
variance from an ACC rule that would obligate us to acquire all of our
customers' standard offer generation requirements from the competitive market
(with at least 50% of that coming from a "competitive bidding" process) starting
in 2003 and (b) approve as just and reasonable a long-term purchase power
agreement (PPA) between us and Pinnacle West. We have requested these ACC
actions to ensure continued reliable service to our standard offer customers in
a volatile generation market and to recognize Pinnacle West Energy's significant
investment to serve our load. The following are the major provisions of the PPA:
* The PPA would run through 2015, with three optional five-year renewal
terms, which renewals would occur automatically unless notice is given
by either us or Pinnacle West.
* The PPA would provide for all of our anticipated standard offer
generation needs, including any necessary reserves, except for (a)
those provided by us through renewable resources or other generation
assets retained by us; (b) amounts that we are obligated by law to
-12-
purchase from "qualified facilities" and other forms of distributed
generation; and (c) any purchased power agreements that we cannot
transfer to Pinnacle West Energy.
* Pinnacle West would assume contractual responsibility for reliability
and would supplement any potential shortfall even after full
utilization of Pinnacle West Energy's dedicated generating resources.
* Pinnacle West would supply our standard offer requirements through a
combination of (a) our generation assets transferred to Pinnacle West
Energy; (b) certain of Pinnacle West Energy's new Arizona generation
projects to be constructed during the 2001-2004 period to reliably
serve our load requirements; (c) power procured by Pinnacle West under
certain "dedicated contracts"; and (d) power procured on the open
market, including a competitively-bid component described below.
* Beginning in 2003, Pinnacle West would acquire 270 MW of our standard
offer requirements on the open market through a competitive bidding
process. This competitive bid obligation would be increased by an
additional 270 MW each year through 2008 (representing approximately
23% of estimated 2008 peak load).
* Pinnacle West would charge us based on (a) a combination of fixed and
variable price components for the Pinnacle West Energy assets, subject
to periodic adjustment, and (b) a pass-through of Pinnacle West's
costs to procure power from the remaining sources.
* The PPA would take effect on the latest of the following events: (a)
transfer of non-nuclear generating assets from us to Pinnacle West
Energy; (b) ACC approval of the rule variance and the PPA; and (c)
FERC acceptance of the PPA and the companion agreement between
Pinnacle West and Pinnacle West Energy.
PROVIDER OF LAST RESORT OBLIGATION. 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 that the market may continue to be volatile. We believe
that through a combination of hedging and our current generation portfolio, we
will be able to adequately manage our exposure to the volatility of the 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 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.
-13-
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 involving us), 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 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,
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 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 case has been appealed to the Arizona Supreme Court, where a decision is
pending.
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
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
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received a waiver to allow transfer of our generation and other
competitive assets and services to affiliates no later than December
31, 2002. We plan to complete the move of such assets by the end of
2002, as required.
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):
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 that Pinnacle West 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
-15-
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.
In June 2001, 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. The Company
cannot accurately predict the overall financial impact of the plan on the
various aspects of its business, including its wholesale and purchased power
activities.
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 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 activities related to the
transmission and distribution of electricity (delivery business segment) and the
generation of electricity and wholesale and power trading (generation business
segment).
These reportable segments reflect a change in the reporting of our
functional activities. Before January 1, 2001, our reported segment information
combined transmission and distribution activities with wholesale and power
trading activities. Our current operational activities are more closely based on
the strong integration of our wholesale and power trading activities with our
generation of electricity, and have been combined for segment reporting
purposes. The corresponding information for earlier periods has been restated.
-16-
Beginning in 2001, we changed our method of allocating revenues between the
delivery business segment and the generation business segment to reflect the
seasonal impact of market prices. This change had the impact of decreasing
delivery segment income and increasing generation segment income in all the
periods presented when compared to the prior comparable periods. The after-tax
change is $45 million in the three-month period and $2 million in the nine- and
twelve-month periods.
Eliminations primarily relate to intersegment sales of electricity. Segment
information for the three, nine and twelve months ended September 30, 2001 and
2000 is as follows (dollars in millions):
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
------------------ ------------------ ------------------
2001 2000 2001 2000 2001 2000
------- ------- ------- ------- ------- -------
Operating Revenues:
Delivery $ 612 $ 683 $ 1,577 $ 1,563 $ 1,984 $ 1,963
Generation 805 1,194 2,086 1,886 2,609 2,169
Eliminations (368) (311) (788) (718) (969) (901)
------- ------- ------- ------- ------- -------
Total $ 1,049 $ 1,566 $ 2,875 $ 2,731 $ 3,624 $ 3,231
======= ======= ======= ======= ======= =======
Income Before
Accounting Change:
Delivery $ 6 $ 28 $ 95 $ 84 $ 116 $ 115
Generation 102 96 147 169 180 173
------- ------- ------- ------- ------- -------
Total $ 108 $ 124 $ 242 $ 253 $ 296 $ 288
======= ======= ======= ======= ======= =======
As of September 30, As of December 31,
2001 2000
---- ----
Assets:
Delivery $3,950 $3,987
Generation 2,670 2,413
------ ------
Total $6,620 $6,400
====== ======
9. Accounting Matters
In July 2001, the FASB issued 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 are currently evaluating the impacts of the new standard
and do not expect it to have a material impact on our financial statements. We
have no goodwill. This standard is effective for the year beginning January 1,
2002.
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.
-17-
In October 2001, the FASB issued 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. SFAS No. 144 is effective for the year
beginning January 1, 2002. We are currently evaluating the impacts of the new
standard and do not expect it to have a material impact on our financial
statements.
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
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 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.
In June 2001, the FASB determined that certain electricity contracts,
including those with option characteristics and those subject to "bookout,"
would qualify for the normal purchases and sales exception if certain criteria
were met. Prior to the issuance of the guidance, we accounted for electricity
contracts with characteristics of options and those subject to "bookout" as
normal purchases and sales. As a result, we did not previously mark these
contracts to their fair market values each reporting period. The effective date
of this new guidance was July 1, 2001.
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
principle 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.
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. These adjustments resulted primarily from contracts
-18-
with characteristics of options that did not meet the new criteria for the
normal purchases and sales exception. The impact of the new guidance is
reflected as a cumulative effect of a change in accounting principle. In October
2001, FASB again revised its guidance for option-like contracts. We are
currently in the process of evaluating the effect, if any, of this revised
guidance.
The change in derivative fair value in the condensed statements of income
for the three, nine and twelve months ending September 30, 2001 and 2000 is
comprised of the following (dollars in thousands):
Nine Months
Three Months Ended Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2001 2000 2001 2000 2001 2000
-------- -------- -------- -------- -------- --------
Ineffective portion of derivatives
qualifying for hedge accounting (a) $ (1,879) $ -- $ (8,063) $ -- $ (8,063) $ --
Discontinuance of cash flow hedges
for forecasted transactions that
will not occur (1,367) -- (9,692) -- (9,692) --
Reclassification of mark-to-market
to realized 19,880 -- 26,359 -- 26,359 --
-------- -------- -------- -------- -------- --------
Total $ 16,634 $ -- $ 8,604 $ -- $ 8,604 $ --
======== ======== ======== ======== ======== ========
(a) Time value component of options excluded from assessment of hedge
effectiveness.
As of September 30, 2001, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted
transactions is thirty-nine months. During the twelve months ending September
30, 2002, we estimate that a net loss of $23 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 transaction.
Net gains and losses on derivatives utilized for trading activities are
recognized in power marketing revenues on a current basis (the mark-to-market
method). Trading positions are measured at fair value as of the balance sheet
date. The mark-to-market gains recognized in power marketing revenues were the
following for the three, nine and twelve months ended September 30, 2001 and
2000 (dollars in millions):
-19-
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
------------- ------------- -------------
2001 2000 2001 2000 2001 2000
---- ---- ----- ---- ----- ----
Mark-to-market gains (losses) $ 40 $(45) $ 135 $(18) $ 162 $(17)
Realized gains (losses) (26) 66 (25) 80 (56) 83
---- ---- ----- ---- ----- ----
Total trading gains $ 14 $ 21 $ 110 $ 62 $ 106 $ 66
==== ==== ===== ==== ===== ====
11. Comprehensive Income
Components of comprehensive income for the three, nine and twelve months
ended September 30, 2001 and 2000, are as follows (dollars in thousands):
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
-------------------- --------------------- ---------------------
2001 2000 2001 2000 2001 2000
-------- -------- --------- -------- --------- --------
Net income $ 95,110 $124,231 $ 226,600 $252,857 $ 280,337 $288,335
-------- -------- --------- -------- --------- --------
Other comprehensive income(loss),
net of tax:
Cumulative effect of change in
accounting for derivatives 7,801 -- 72,501 -- 72,501 --
Unrealized holding losses arising
during period (11,353) -- (109,281) -- (109,281) --
Reclassification adjustment for
derivatives (11,145) -- (29,829) -- (29,829) --
-------- -------- --------- -------- --------- --------
Total other comprehensive loss (14,697) -- (66,609) -- (66,609) --
-------- -------- --------- -------- --------- --------
Comprehensive income $ 80,413 $124,231 $ 159,991 $252,857 $ 213,728 $288,335
======== ======== ========= ======== ========= ========
12. California Energy Market Issues and Refunds in the Pacific Northwest
We are closely monitoring developments in the California energy market and
the potential impact of those 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 on our current evaluations, we do not
believe the foregoing matters will have a material adverse effect on our
financial position and 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.
In July 2001, 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 FERC after
the California ISO provides necessary historical data. FERC also ordered an
evidentiary proceeding to discuss and evaluate possible refunds for the Pacific
Northwest. The Administrative Law Judge at 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 FERC Commissioners. Although FERC has
-20-
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 will have a material adverse impact on our financial position,
results of operations or liquidity.
13. Power Service Agreement
By letter dated March 7, 2001, Citizens 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. The Company and Citizens terminated the power service
agreement 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.
14. 2001 Generation Summer Reliability Program
We recently added over 200 MW of generating capability to enhance
reliability for the summer of 2001 in light of market conditions in the western
United States. We restored approximately 100 MW of previously mothballed
gas-fired steam units at the West Phoenix Power Plant and refurbished the entire
fossil plant fleet during the spring of 2001 (which resulted in additional
capability of approximately 110 MW). Additionally, Pinnacle West Energy added
over 300 MW of generating capacity (including 200 MW from leased portable
generators) for the summer of 2001.
-21-
ARIZONA PUBLIC SERVICE COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
INTRODUCTION
In this section, we explain our results of operations, general financial
condition, and outlook including:
* the changes in our earnings for the three, nine and twelve months
ended September 30, 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,
nine and twelve months ended September 30, 2001 and the comparable prior year
periods:
Periods ended September 30,
(Unaudited)
(dollars in millions)
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
----------------- ----------------- -----------------
2001 2000 2001 2000 2001 2000
------ ------ ------ ------ ------ ------
Operating Revenues $1,049 $1,566 $2,875 $2,731 $3,624 $3,231
Net Income $ 95(1) $ 124 $ 227(2) $ 253 $ 280(2) $ 288
(1) The three-month period ended September 30, 2001 includes an after-tax loss
related to the cumulative effect of a change in accounting for derivatives
of $12 million.
(2) These periods include an after-tax loss related to the cumulative effect of
a change in accounting for derivatives of $15 million.
-22-
Operating Results - Three-month period ended September 30, 2001 compared
with three-month period ended September 30, 2000
Net income for the three months ended September 30, 2001 was $95 million
compared with $124 million for the same period in the prior year. In July 2001,
we recognized a $12 million after-tax loss in net income as a cumulative effect
of a change in accounting for derivatives as required by SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities". See Note 10 for
further discussion.
Income before accounting change for the three months ended September 30,
2001 was $108 million compared with $124 million for the same period in the
prior year. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
Increase/(Decrease)
-------------------
Decreased margin on power marketing, trading and other
wholesale activities $(35)
Higher margin from retail sales 5
Retail price reductions (9)
Higher replacement power costs on plant outages (6)
SFAS No. 133 accounting adjustment 17
----
Decrease in revenues, net of purchased power and fuel expense (28)
Higher operations and maintenance expense primarily related to generation
reliability and other costs (10)
Miscellaneous items, net 11
----
Net decrease in income before income taxes (27)
Lower income taxes primarily due to lower income 11
----
Net decrease in income before accounting change $(16)
====
Electric operating revenues decreased approximately $517 million primarily
because of:
* decreased power marketing revenues related to trading and wholesale
activities primarily because of increased power marketing at Pinnacle West
($522 million);
* increased retail revenues primarily related to higher sales volumes due to
weather impacts and customer growth, partially offset by lower average
usage per customer ($14 million); and
* decreased retail revenues related to the reduction in retail electricity
prices ($9 million). See Note 6 for information on the price reductions.
Purchased power and fuel expenses decreased approximately $489 million
primarily because of:
* decreased power marketing costs related to trading and wholesale activities
primarily because of increased power marketing at Pinnacle West ($487
million);
* decreased costs for a SFAS No. 133 adjustment related to changes in
electricity and gas market prices ($17 million). See Note 10 for additional
information on SFAS No. 133;
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* increased costs related to higher retail sales volumes and associated
higher purchased power and fuel prices ($9 million); and
* higher replacement power costs primarily for increased plant outages ($6
million).
The increase in operations and maintenance expenses of $10 million
primarily related to the generation reliability and power plant maintenance
costs ($6 million) and other costs ($4 million). See Note 14 for additional
information on the generation summer reliability program.
Depreciation and amortization decreased $7 million primarily because of
lower regulatory asset amortization.
Interest expense decreased by $6 million primarily because of lower
interest rates.
Operating Results - Nine-month period ended September 30, 2001 compared
with nine-month period ended September 30, 2000
Net income for the nine months ended September 30, 2001 was $227 million
compared with $253 million for the same period in the prior year. In 2001, we
recognized a $15 million after-tax loss in net income as a cumulative effect of
a change in accounting for derivatives, as required by SFAS No. 133. See Note 10
for further discussion.
Income before accounting change for the nine months ended September 30,
2001 was $242 million compared with $253 million for the same period in the
prior year. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
Increase/(Decrease)
-------------------
Increased margin on generation sales other than Native Load $ 118
Decreased margin on power marketing, trading and other
wholesale activities (8)
Lower margin from retail sales (10)
Retail price reductions (22)
SFAS No. 133 accounting adjustments 9
Higher replacement power costs for plant outages (94)
-----
Decrease in revenues, net of purchased power and fuel expense (7)
Higher operations and maintenance expenses primarily related to generation
reliability and other costs (33)
Miscellaneous items, net 23
-----
Net decrease in income before income taxes (17)
Lower income taxes primarily due to lower income 6
-----
Net decrease in income before accounting change $ (11)
=====
Electric operating revenues increased approximately $144 million primarily
because of:
* increased wholesale revenues primarily related to generation sales other
than for Native Load ($182 million);
-24-
* decreased power marketing revenues related to trading and other wholesale
activities ($74 million);
* increased retail revenues primarily related to higher sales volumes due to
weather impacts and customer growth, partially offset by lower average
usage per customer ($58 million); and
* decreased retail revenues related to reductions in retail electricity
prices ($22 million). See Note 6 for information on the price reductions.
Purchased power and fuel expenses increased approximately $151 million
primarily because of:
* increased costs related to generation other than Native Load ($64 million);
* decreased power marketing costs related to trading and other wholesale
activities ($66 million);
* higher replacement power costs primarily for increased plant outages ($94
million), including costs of $12 million related to the Palo Verde outage
extension to replace fuel control element assemblies;
* increased costs related to higher retail sales volumes and associated
higher purchased power and fuel prices ($68 million); and
* decreased costs related to SFAS No. 133 adjustments related to changes in
electricity and gas market prices ($9 million). See Note 10 for additional
information on SFAS No. 133.
The increase in operations and maintenance expenses of $33 million
primarily related to generation reliability and increased power plant
maintenance ($27 million) and increased pension and other costs ($6 million).
Depreciation and amortization decreased $8 million primarily because of
lower regulatory asset amortization.
Other net income increased $6 million primarily because of insurance
recovery of environmental remediation costs.
Interest expense decreased by $13 million primarily because of lower
interest rates and increased capitalized interest resulting from higher
construction project balances.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2001 COMPARED
WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2000
Net income for the twelve months ended September 30, 2001 was $280 million
compared with $288 million for the same period in the prior year. In 2001, we
recognized a $15 million after-tax loss in net income as a cumulative effect of
a change in accounting for derivatives, as required by SFAS No.133. See Note 10
for further discussion.
Income before accounting change for the twelve months ended September 30,
2001 was $296 million compared with $288 million for the same period in the
prior year. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
-25-
Increase/(Decrease)
-------------------
Increased margin on generation sales other than Native Load $ 163
Decreased margin on power marketing, trading and other
wholesale activities (3)
Retail price reductions (27)
Lower margin from retail sales (13)
SFAS No. 133 accounting adjustments 9
Higher replacement power costs for plant outages (116)
-----
Increase in revenues, net of purchased power and fuel expense 13
Higher operations and maintenance expense primarily related to generation
reliability and other costs (16)
Miscellaneous items, net 26
-----
Net increase in income before income taxes 23
Higher income taxes primarily due to higher income (15)
-----
Net increase in income before accounting change $ 8
=====
Electric operating revenues increased approximately $393 million because
of:
* increased wholesale revenues primarily related to generation sales other
than for Native Load ($269 million);
* increased power marketing revenues related to trading and other wholesale
activities ($84 million);
* increased retail revenues primarily related to higher sales volumes due to
weather impacts and customer growth, partially offset by lower average
usage per customer ($67 million); and
* decreased retail revenues related to the reduction in retail electricity
prices ($27 million). See Note 6 for information on the price reductions.
Purchased power and fuel expenses increased approximately $380 million
primarily because of:
* increased costs related to generation other than Native Load ($106
million);
* increased power marketing costs related to trading and other wholesale
activities ($87 million);
* higher replacement power costs primarily for increased plant outages ($116
million), including costs of $12 million related to the Palo Verde outage
extension to replace fuel control element assemblies;
* higher costs related to retail sales volumes and associated purchased power
and fuel prices ($80 million); and
* decreased costs for SFAS No. 133 adjustments related to changes in
electricity and gas market prices ($9 million). See Note 10 for additional
information on SFAS No. 133.
The increase in operations and maintenance expenses of $16 million
primarily related to generation summer reliability programs and increased power
plant maintenance, partially offset by approximately $12 million of
non-recurring items recorded in the fourth quarter of 1999. See Note 14 for
information on the generation summer reliability program. See Note 12 for
additional information related to the California energy situation.
-26-
Other net income increased $7 million primarily because of insurance
recovery of environmental remediation costs.
Interest expense decreased by $16 million primarily because of increased
capitalized interest resulting from higher construction project balances and
lower interest rates.
LIQUIDITY AND CAPITAL RESOURCES
For the nine months ended September 30, 2001, we incurred approximately
$340 million in capital expenditures, which is approximately 74% of the most
recently estimated 2001 capital expenditures. Our projected capital expenditures
for the next three years are $461 million in 2001; $487 million in 2002; and
$305 million in 2003.
Our long-term debt redemption requirements, including optional repayments
on long-term debt are: $384 million in 2001; $125 million in 2002; and zero in
2003. During 2001, we expect to satisfy our long-term debt redemption
requirements with cash from operations and long and short-term borrowings.
Through September 2001, we redeemed $62 million of our long-term debt. 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. On October 5,
2001, we issued $400 million of our 6.375% Notes due 2011. 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 AND REFUNDS IN THE PACIFIC NORTHWEST
See Note 12 for information regarding California energy market issues and
possible Pacific Northwest refunds.
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.
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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 4.1% a year for
the three years 1998 through 2000; we currently expect customer growth to
average 3% to 4% a year for 2001 through 2003. We currently estimate that retail
electricity sales in kilowatt-hours will grow 3% 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, including the price mitigation plan adopted by
FERC in June 2001 (see Note 6). These factors have significantly affected our
trading and wholesale power activities and their resultant earnings
contributions over the last several years. We cannot predict future
contributions from trading and wholesale activities. See Note 10 and Item 3
below for additional information.
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, and our hedging program for
managing such costs. See "Natural Gas Supply" in Part II for additional
information on gas transportation 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 our
additions to existing facilities.
Interest costs are affected by the amount of debt outstanding and the
interest rates on that debt.
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
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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 6 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
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; state and federal
regulatory and legislative decisions and actions, including the price mitigation
plan adopted by FERC in June 2001; 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 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 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 limit our exposure to volatile wholesale prices for power and fuel. In
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addition, we engage in trading activities intended to profit from favorable
movements of market prices.
As of September 30, 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 $20 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 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 our construction and financing programs.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
RETAIL. 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.
WHOLESALE. On October 16, 2001, the Company and other owners of electric
transmission lines in the Southwest filed with FERC a request for a declaratory
order confirming that their proposal to form WestConnect would satisfy FERC's
requirements for the formation of a regional transmission organization. The
Company and the other filing parties have agreed to fund the start-up of
WestConnect's operations, which are projected to begin in 2004, subject to FERC
approval. WestConnect has been structured as a for-profit RTO and evolved from
DesertSTAR, a non-profit corporation in which we participated, which was
originally designed to serve as an RTO for the southwestern United States.
ENVIRONMENTAL MATTERS
The Arizona Department of Environmental Quality issued to us Notices of
Violation, dated September 25, 2001 and October 15, 2001 alleging, among other
things, burning of unauthorized materials and storage of hazardous waste without
a permit. Each Notice of Violation requires us to achieve and document
compliance with specific environmental requirements. Although ADEQ may still
seek civil penalties or take other enforcement action against us, we do not
expect these matters to have a material adverse effect on our financial
position, results of operations, or liquidity.
NATURAL GAS SUPPLY
The gas supply for the Company and Pinnacle West Energy gas-fired
facilities located, and to be located, in Pinal, Maricopa and Yuma Counties in
Arizona, is transported pursuant to a firm, Full Requirements Transportation
Service Agreement with El Paso Natural Gas Company. The transportation agreement
features a 10 year rate moratorium established in a comprehensive rate case
settlement entered into in 1996.
In a pending FERC proceeding, El Paso has proposed allocating its gas
pipeline capacity in such a way that our (and other companies' with the same
contract type) gas transportation rights could be significantly impacted.
Various parties, including us and Pinnacle West Energy, have challenged this
allocation as being inconsistent with El Paso's existing contractual obligations
and the 1996 settlement. At this time, there are ongoing discussions among FERC,
El Paso and other affected parties to resolve these issues. We cannot currently
predict the outcome of this matter.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
4.1 Fifth Supplemental Indenture, dated as of
October 1, 2001, to Indenture, dated as of
January 15, 1998, between the Company
and The Chase Manhattan Bank
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 ss.229.10(d) by reference to
the filings set forth below:
ORIGINALLY FILED DATE
EXHIBIT NO. DESCRIPTION AS EXHIBIT: FILE NO.(1) 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
(b) Reports on Form 8-K
During the quarter ended September 30, 2001, and the period from October 1
through November 5, 2001, we filed the following reports on Form 8-K:
Report dated October 18, 2001 regarding (i) the Arizona Supreme Court's
decision to review a lower court decision affirming the 1999 Settlement
Agreement; and (ii) the Company's October 18, 2001 filing with the ACC
requesting ACC approval of a rule variance and a purchase power agreement with
the Company.
Report dated October 2, 2001 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-58445 and 333-94277) relating to
the Company's offering of $400 million of Notes.
----------
(1) Reports filed under File No. 1-4473 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
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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: November 5, 2001 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)