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, 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 November 14, 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
APS Energy Services - APS Energy Services Company, Inc., a subsidiary of
Pinnacle West
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Arizona Public Service Company
EITF - the FASB's Emerging Issues Task Force
ERMC - Pinnacle West's Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Financing Application - our application filed with the ACC on September 16, 2002
Fitch - Fitch, Inc.
Four Corners - Four Corners Power Plant
GAAP - Generally accepted accounting principles in the United States
Interim Financing Application - our application filed with the ACC on
November 8, 2002
IRS - Internal Revenue Service
ISO - California Independent System Operator
June 2002 10-Q - Arizona Public Service Company Quarterly Report on Form 10-Q
for the fiscal quarter ended June 30, 2002
Moody's - Moody's Investors Service
MW - megawatt, one million watts
MWh - megawatt hour
Native Load - retail and wholesale sales supplied under traditional cost-based
rate regulation
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
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 subsidiary of
Pinnacle West
PG&E - PG&E Corp.
PX - California Power Exchange
Rules - ACC retail electric competition rules
SCE - Southern California Edison
SEC - United States Securities and Exchange Commission
SFAS - Statement of Financial Accounting Standards
SPE - special-purpose entity
Standard & Poor's - Standard & Poor's Corporation
System - Non-trading energy related activities
T&D - transmission and distribution
Track A Order - ACC order dated September 10, 2002 regarding generation asset
transfers and related issues
Trading - Energy related activities entered into with the objective of
generating profits on changes in market prices
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 September 30,
--------------------------
2002 2001
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Electric retail segment .......................................... $ 744,463 $ 973,398
Marketing and trading segment .................................... 9,126 65,129
----------- -----------
Total ......................................................... 753,589 1,038,527
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Retail segment ................................................... 306,244 546,755
Marketing and trading segment .................................... 8,345 30,756
----------- -----------
Total ......................................................... 314,589 577,511
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ............. 439,000 461,016
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased
power and fuel cost ............................................ 132,787 120,762
Depreciation and amortization .................................... 100,603 105,771
Income taxes ..................................................... 58,407 70,017
Other taxes ...................................................... 26,751 29,327
----------- -----------
Total ......................................................... 318,548 325,877
----------- -----------
OPERATING INCOME ................................................... 120,452 135,139
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ..................................................... 1,806 1,752
Other income ..................................................... 1,962 1,169
Other expense .................................................... (6,073) (2,819)
----------- -----------
Total ......................................................... (2,305) 102
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS .................................. 118,147 135,241
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ....................................... 31,900 29,211
Interest on short-term borrowings ................................ 2,609 1,331
Debt discount, premium and expense ............................... 789 666
Capitalized interest ............................................. (3,721) (3,523)
----------- -----------
Total ......................................................... 31,577 27,685
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE .................................... 86,570 107,556
Cumulative effect of a change in accounting for derivatives -
net of income tax benefit of $8,099 ............................ -- (12,446)
----------- -----------
NET INCOME ......................................................... $ 86,570 $ 95,110
=========== ===========
See Notes to Condensed Financial Statements
2
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Nine Months
Ended September 30,
--------------------------
2002 2001
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Electric retail segment ......................................... $ 1,635,915 $ 2,125,522
Marketing and trading segment ................................... 22,188 543,045
----------- -----------
Total ........................................................ 1,658,103 2,668,567
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Retail segment .................................................. 490,887 1,120,925
Marketing and trading segment ................................... 20,712 313,270
----------- -----------
Total ........................................................ 511,599 1,434,195
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ............ 1,146,504 1,234,372
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased
power and fuel cost ........................................... 365,053 356,355
Depreciation and amortization ................................... 297,415 314,110
Income taxes .................................................... 123,681 156,425
Other taxes ..................................................... 81,127 80,071
----------- -----------
Total ........................................................ 867,276 906,961
----------- -----------
OPERATING INCOME .................................................. 279,228 327,411
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes .................................................... 4,176 (33)
Other income .................................................... 4,510 14,445
Other expense ................................................... (13,981) (12,530)
----------- -----------
Total ........................................................ (5,295) 1,882
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................................. 273,933 329,293
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ...................................... 95,938 93,031
Interest on short-term borrowings ............................... 4,908 3,807
Debt discount, premium and expense .............................. 2,129 2,001
Capitalized interest ............................................ (11,814) (11,347)
----------- -----------
Total ........................................................ 91,161 87,492
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE ................................... 182,772 241,801
Cumulative effect of a change in accounting for derivatives -
net of income tax benefit of $9,892 ........................... -- (15,201)
----------- -----------
NET INCOME ........................................................ $ 182,772 $ 226,600
=========== ===========
See Notes to Condensed Financial Statements.
3
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended September 30,
--------------------------
2002 2001
----------- -----------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Electric retail segment .......................................... $ 2,072,481 $ 2,581,094
Marketing and trading segment .................................... 28,383 705,870
----------- -----------
Total ......................................................... 2,100,864 3,286,964
----------- -----------
PURCHASED POWER AND FUEL COSTS:
Retail segment ................................................... 597,150 1,248,475
Marketing and trading segment .................................... 21,433 443,477
----------- -----------
Total ......................................................... 618,583 1,691,952
----------- -----------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS ............. 1,482,281 1,595,012
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased
power and fuel cost ............................................ 474,259 462,962
Depreciation and amortization .................................... 404,198 417,947
Income taxes ..................................................... 150,896 192,733
Other taxes ...................................................... 102,133 103,195
----------- -----------
Total ......................................................... 1,131,486 1,176,837
----------- -----------
OPERATING INCOME ................................................... 350,795 418,175
----------- -----------
OTHER INCOME (DEDUCTIONS):
Income taxes ..................................................... 4,713 2,664
Other income ..................................................... 10,018 17,227
Other expense .................................................... (21,987) (22,148)
----------- -----------
Total ......................................................... (7,256) (2,257)
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS .................................. 343,539 415,918
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ....................................... 129,025 127,836
Interest on short-term borrowings ................................ 5,508 4,508
Debt discount, premium and expense ............................... 2,778 2,695
Capitalized interest ............................................. (15,431) (14,659)
----------- -----------
Total ......................................................... 121,880 120,380
----------- -----------
INCOME BEFORE ACCOUNTING CHANGE .................................... 221,659 295,538
Cumulative effect of change in accounting for derivatives -
net of income tax benefit of $9,892 ............................ -- (15,201)
----------- -----------
NET INCOME ......................................................... $ 221,659 $ 280,337
=========== ===========
See Notes to Condensed Financial Statements
4
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Dollars in Thousands)
September 30, December 31,
2002 2001
----------- -----------
(Unaudited)
UTILITY PLANT:
Electric plant in service and held for future use ............ $ 8,205,695 $ 7,935,206
Less accumulated depreciation and amortization ............... 3,423,907 3,287,333
----------- -----------
Total ..................................................... 4,781,788 4,647,873
Construction work in progress ................................ 326,805 321,305
Intangible assets, net of accumulated amortization ........... 90,379 83,135
Nuclear fuel, net of accumulated amortization ................ 54,770 49,282
----------- -----------
Utility plant - net ....................................... 5,253,742 5,101,595
----------- -----------
INVESTMENTS AND OTHER ASSETS:
Decommissioning trust accounts ............................... 201,456 202,036
Assets from risk management and trading
activities - long-term ..................................... 24,141 2,082
Other assets ................................................. 26,315 76,322
----------- -----------
Total investments and other assets ........................ 251,912 280,440
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents .................................... 9,378 16,821
Accounts receivable:
Service customers ......................................... 213,522 182,749
Other ..................................................... 226,589 153,988
Allowance for doubtful accounts ........................... (1,782) (3,349)
Accrued utility revenues ..................................... 103,773 76,131
Materials and supplies, at average cost ...................... 80,868 81,215
Fossil fuel, at average cost ................................. 30,632 27,023
Assets from risk management and trading activities ........... 11,042 10,097
Other ........................................................ 68,220 42,009
----------- -----------
Total current assets ...................................... 742,242 586,684
----------- -----------
DEFERRED DEBITS:
Regulatory assets ............................................ 267,104 342,383
Unamortized debt issue costs ................................. 14,167 13,163
Other ........................................................ 58,818 42,789
----------- -----------
Total deferred debits ..................................... 340,089 398,335
----------- -----------
TOTAL ASSETS .............................................. $ 6,587,985 $ 6,367,054
=========== ===========
See Notes to Condensed Financial Statements.
5
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Dollars in Thousands)
September 30, December 31,
2002 2001
----------- -----------
(Unaudited)
CAPITALIZATION:
Common stock ...................................................... $ 178,162 $ 178,162
Additional paid-in capital ........................................ 1,246,804 1,246,804
Retained earnings ................................................. 845,561 790,289
Accumulated other comprehensive loss .............................. (32,737) (64,565)
----------- -----------
Common stock equity ............................................ 2,237,790 2,150,690
Long-term debt less current maturities ............................ 2,200,754 1,949,074
----------- -----------
Total capitalization ........................................... 4,438,544 4,099,764
----------- -----------
CURRENT LIABILITIES:
Commercial paper .................................................. 25,300 171,162
Current maturities of long-term debt .............................. 402 125,451
Accounts payable .................................................. 96,363 98,959
Accrued taxes ..................................................... 99,704 107,595
Accrued interest .................................................. 31,903 41,043
Customer deposits ................................................. 38,422 28,664
Deferred income taxes ............................................. 3,244 3,244
Liabilities from risk management and trading activities ........... 26,733 21,840
Other ............................................................. 167,900 117,770
----------- -----------
Total current liabilities ...................................... 489,971 715,728
----------- -----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ............................................. 1,195,595 1,023,079
Liabilities from risk management and trading
activities - long-term .......................................... 41,865 95,159
Unamortized gain - sale of utility plant .......................... 60,628 64,060
Customer advances for construction ................................ 52,161 69,293
Other ............................................................. 309,221 299,971
----------- -----------
Total deferred credits and other ............................... 1,659,470 1,551,562
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 12)
TOTAL LIABILITIES AND EQUITY ................................... $ 6,587,985 $ 6,367,054
=========== ===========
See Notes to Condensed Financial Statements.
6
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30,
----------------------
2002 2001
--------- ---------
(Dollars in Thousands)
Cash Flows from Operating Activities:
INCOME BEFORE ACCOUNTING CHANGE ........................ $ 182,772 $ 241,801
Items not requiring cash:
Depreciation and amortization ........................ 297,415 314,110
Nuclear fuel amortization ............................ 23,639 22,221
Deferred income taxes - net .......................... 149,970 (46,664)
Mark-to-market gains - trading ....................... -- (91,521)
Mark-to-market gains - system ........................ (1,951) (8,604)
Changes in certain current assets and liabilities:
Accounts receivable - net ............................ (103,606) 14,842
Accrued utility revenues ............................. (27,642) (28,385)
Materials, supplies and fossil fuel .................. (3,262) (14,766)
Other current assets ................................. 1,460 (251)
Accounts payable ..................................... (10,636) (46,542)
Accrued taxes ........................................ (35,562) 199,327
Accrued interest ..................................... (9,140) (23,004)
Other current liabilities ............................ 59,888 (11,518)
Increase in regulatory assets .......................... (8,709) (10,565)
Changes in risk management trading
investments - at cost ................................ (18,087) (5,512)
Changes in long-term assets ............................ (24,111) (4,273)
Change in long-term liabilities ........................ (5,858) 29,571
--------- ---------
Net cash flow provided by operating activities ........... 466,580 530,267
--------- ---------
Cash Flows from Investing Activities:
Trust fund for bond redemption ......................... -- (72,370)
Capital expenditures ................................... (361,701) (324,878)
Capitalized interest ................................... (11,814) (11,347)
Other .................................................. 50,007 (12,370)
--------- ---------
Net cash flow used for investing activities ........ (323,508) (420,965)
--------- ---------
Cash Flows from Financing Activities:
Issuance of long-term debt ............................. 369,930 --
Short-term borrowings - net ............................ (145,862) 92,400
Dividends paid on common stock ......................... (127,500) (127,500)
Repayment and reacquisition of long-term debt .......... (247,083) (61,864)
--------- ---------
Net cash flow used for financing activities ........ (150,515) (96,964)
--------- ---------
Net increase (decrease) in cash and cash equivalents ..... (7,443) 12,338
Cash and cash equivalents at beginning of period ......... 16,821 2,609
--------- ---------
Cash and cash equivalents at end of period ............... $ 9,378 $ 14,947
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized ................. $ 98,091 $ 108,842
Income taxes ......................................... $ 38,405 $ 41,705
See Notes to Condensed Financial Statements.
7
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Our unaudited condensed financial statements reflect all adjustments which
we believe are necessary for the fair presentation of our financial position and
results of operations for the periods presented. These adjustments are of a
normal recurring nature with the exception of the cumulative effect of a change
in accounting for derivatives (see Note 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
2001 10-K. We have reclassified certain prior year amounts to conform to the
current year presentation (see Note 8).
2. Weather conditions cause significant seasonal fluctuations in our revenues.
Consequently, 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. On March
15, 2002, we redeemed at maturity $125 million of our First Mortgage Bonds,
8.125% Series due 2002. On April 15, 2002, we redeemed $122 million of our First
Mortgage Bonds, 8.75% Series due 2024. The above items represent the primary
changes in capitalization for the nine months ended September 30, 2002.
On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation
issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona
Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned
the proceeds to us pursuant to a loan agreement. The bonds were issued to
refinance $90 million of outstanding pollution control bonds. In addition, see
"ACC Applications" in Note 5 for a discussion of our applications requesting the
ACC to permit us to make inter-affiliate loans to, or guarantees in favor of
Pinnacle West Energy and Pinnacle West.
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 were required to transfer all of our competitive electric assets
and services to an unaffiliated party or parties or to a separate corporate
affiliate or affiliates no later than December 31, 2002. Consistent with that
requirement, we had 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. The Rules also obligated 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.
8
On August 27, 2002, the ACC held an open meeting to consider various issues
relating to retail electric competition in Arizona. At that meeting, the ACC
determined, among other things, that we would not be permitted to transfer our
generation assets. The ACC stayed indefinitely the competitive bidding
requirements described in the preceding paragraph. Instead, the ACC required
that we competitively procure, at a minimum, any power needed for our retail
customers that we cannot produce from our existing generation assets. The ACC
ordered the ACC Staff and interested parties to develop a competitive
procurement process by March 1, 2003. For purposes of this competitive
procurement process, the ACC stated that the Pinnacle West Energy generation
assets "shall not be counted as [our] assets in determining the amount, timing,
and manner of the competitive solicitation." The ACC ordered the development of
a competitive solicitation process that can begin by March 1, 2003.
On September 16, 2002, we filed an application with the ACC requesting the
ACC to allow us to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to Pinnacle West; to guarantee up to $500 million of
Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to
exceed $500 million in the aggregate. In our application, we stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between us and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing provided
by Pinnacle West to fund the construction of Pinnacle West Energy generation
assets or from effectively competing in the wholesale markets. We noted that
Pinnacle West Energy had previously received investment-grade credit ratings
contingent upon its receipt of our generation assets, and that Pinnacle West's
credit ratings could be adversely affected if Pinnacle West Energy is unable to
finance its capital requirements. On November 4, 2002, Standard & Poor's lowered
the Company's corporate credit rating from BBB+ to BBB and Pinnacle West's
senior unsecured debt rating from BBB to BBB-. On November 8, 2002, we filed an
Interim Financing Application with the ACC requesting the ACC to permit us to
(a) make short-term advances to Pinnacle West in the form of an inter-affiliate
line of credit in the amount of $125 million or (b) guarantee $125 million of
Pinnacle West's short-term debt.
These regulatory developments and legal challenges to the Rules have raised
considerable uncertainty about the status and pace of retail electric
competition in Arizona. 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 a 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%,
9
effective July 1, 2000; approximately $27 million ($16 million after
taxes), or 1.5%, effective July 1, 2001; and approximately $28 million ($17
million after taxes), or 1.5%, effective July 1, 2002. The final 1.5% price
reduction is to be implemented July 1, 2003. For customers having loads of
three MW or greater, standard-offer rates have been 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 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 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. The
regulatory developments and legal challenges to the Rules discussed in this
note have raised considerable uncertainty about the status and pace of
electric competition in Arizona. Although some very limited retail
competition existed in our service area in 1999 and 2000, there are
currently no active retail competitors offering unbundled energy or other
utility services to our customers. As a result, we cannot predict when, and
the extent to which, additional competitors will re-enter our service
territory.
* 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 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
10
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 transfers no later than December 31, 2002. We will be allowed
to defer and later collect, beginning July 1, 2004, sixty-seven percent of
our costs to accomplish the required transfer of generation assets to an
affiliate. However, as noted above and discussed in greater detail below,
the ACC unilaterally modified this aspect of the 1999 Settlement Agreement
by issuing an order preventing us from transferring our generation assets.
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 to an unaffiliated party or parties or to
a separate corporate affiliate or affiliates. 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. However, as noted above and discussed in greater
detail below, the ACC reversed its decision, as reflected in the
Rules, to require us to transfer our generation assets.
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 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
11
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 decision was upheld by the Arizona Supreme Court.
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 at least 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; 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. 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 or transmission 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.
GENERIC DOCKET. In January 2002, the ACC opened a "generic" docket to
"determine if changed circumstances require the [ACC] to take another look at
electric restructuring in Arizona." 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 May 2, 2002, the ACC issued a procedural order
stating that hearings would 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
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.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order, which documents
decisions made by the ACC at an open meeting on August 27, 2002. The major
provisions of the Track A Order include, among other things:
Provisions related to the reversal of the generation asset transfer requirement:
12
* The ACC reversed its decision, as reflected in the Rules, to require
us to transfer our generation assets either to an unrelated third
party or to a separate corporate affiliate; and
* the ACC unilaterally modified the 1999 Settlement Agreement, which
authorized the transfer of our generating assets and directed us to
cancel the activities to transfer our generation assets to Pinnacle
West Energy.
Provisions related to the wholesale competitive energy procurement process
("Track B" issues):
* The ACC stayed indefinitely the requirement of the Rules that we
acquire 100% of our energy needs for our standard offer customers from
the competitive market, with at least 50% obtained through a
competitive bid process;
* the ACC established a requirement that we competitively procure, at a
minimum, any required power that we cannot produce from our existing
assets in accordance with the ultimate outcome of the Track B
proceedings;
* the ACC directed the parties to develop a competitive procurement
("bidding") process that can begin by March 1, 2003; and
* the ACC stated that "the [Pinnacle West Energy] generating assets that
APS may acquire from [Pinnacle West Energy] shall not be counted as
APS assets in determining the amount, timing and manner of the
competitive solicitation" for Track B purposes, thereby bifurcating
the regulatory treatment of our existing assets and the Pinnacle West
Energy assets.
On September 30, 2002, we filed a Motion for Reconsideration of the Track A
Order and on October 17, 2002, the ACC voted to deny that motion. We intend to
appeal the Track A Order or otherwise seek restitution for the ACC's reversal of
the 1999 Settlement Agreement. Such restitution will also be addressed in our
2003 rate filing with the ACC.
The ACC Staff has conducted workshops on the Track B issues with various
parties to determine and define the appropriate process to be used for
competitive power procurement. On October 25, 2002, the ACC Staff issued its
report proposing a process by which we would procure power not supplied by our
own resources. Under the ACC Staff's proposal, we believe that we will be
required to competitively bid for about 1,500 MW of energy on peak. As described
above, the ACC has directed the parties to complete the Track B proceedings such
that the competitive procurement process can begin by March 1, 2003. The ACC
Staff also proposes that Pinnacle West Energy would be able to bid. In addition
to the ACC Staff workshop process, the ACC will conduct evidentiary hearings to
make its final determination on the Track B proceedings. The hearing is
scheduled to begin on November 21, 2002.
13
ACC APPLICATIONS
On September 16, 2002, we filed a Financing Application requesting the ACC
to allow us to borrow up to $500 million and to lend the proceeds to Pinnacle
West Energy or Pinnacle West; to guarantee up to $500 million of Pinnacle West
Energy's or Pinnacle West's debt; or a combination of both, not to exceed $500
million in the aggregate. The loan and/or the guarantee would be used to
refinance debt incurred to fund the construction of Pinnacle West Energy
generation assets. The ACC has established a procedural schedule with a hearing
to begin January 8, 2003.
The Financing Application addresses, among other things, the following
matters:
* We noted that our April 19, 2002 filing with the ACC had sought
unification of "[Pinnacle West Energy] Assets" (West Phoenix Combined
Cycle Units 4 and 5, Redhawk Units 1 and 2, and Saguaro Combustion
Turbine Unit 3) and our generation assets under a common financial and
regulatory regime. We further noted that the Track A Order's language
regarding the treatment of the Pinnacle West Energy Assets for Track B
purposes (see the last bullet point under Track A Order above) appears
to postpone a decision regarding the inclusion of the Pinnacle West
Energy Assets in our rate base, thereby effectively precluding the
consolidation of the Pinnacle West Energy Assets at the Company under
a common financial and regulatory regime at the present time.
* We stated that we did not intend or desire to foreclose the
possibility that we would acquire all or part of the Pinnacle West
Energy Assets or that we may propose that the Pinnacle West Energy
Assets be included in our rate base or afforded cost-of-service
regulatory treatment to the extent the Pinnacle West Energy Assets are
used by our customers. We stated that these issues would be
appropriate topics in our 2003 general rate case and noted that the
Track A Order specifically stated that the ACC would not pre-judge the
eventual rate treatment of the Pinnacle West Energy Assets.
* We stated that the Track A Order's reversal of the generation asset
transfer requirement and the resulting bifurcation of generation
assets between us and Pinnacle West Energy under different regulatory
regimes result in Pinnacle West Energy being unable to attain
investment-grade credit ratings. This, in turn, precludes Pinnacle
West Energy from accessing capital markets to refinance the bridge
financing provided by Pinnacle West to fund the construction of the
Pinnacle West Energy Assets or from effectively competing in the
wholesale markets. We noted that Pinnacle West Energy had previously
received investment-grade credit ratings contingent upon its receipt
of our generation assets and that Pinnacle West's credit ratings could
be adversely affected if Pinnacle West Energy is unable to finance its
capital requirements. On November 4, 2002, Standard & Poor's lowered
the Company's corporate credit rating from BBB+ to BBB and Pinnacle
West's senior unsecured debt rating from BBB to BBB-.
14
* We stated that the amount of the requested loan and/or guarantee is
our present estimate of the amount of credit support necessary through
us to restore Pinnacle West Energy and Pinnacle West to their credit
status prior to the ACC's issuance of the Track A Order. We further
stated that if the requested amount proves to be inadequate, we
reserve the right to submit a second financing application seeking
additional credit support.
In mid-2003, Pinnacle West will need to refinance approximately $550
million of parent company indebtedness. If the ACC does not grant the approvals
requested in the Financing Application in a timely fashion, Pinnacle West would
anticipate taking the following steps, to the extent necessary, in priority
order although the timing of Pinnacle West's liquidity needs may affect the
order of the steps taken:
* The reduction of capital expenditures through plant delay and
cancellation;
* The sale of non-core assets; and
* The issuance of new debt and, if appropriate, new equity.
Although we believe it would be inappropriate to discuss specific amounts
for each of the foregoing categories, Pinnacle West estimates the sum of these
steps to be approximately equivalent to the current outstanding debt at the
parent company, which totaled approximately $1.1 billion as of September 30,
2002.
On November 8, 2002, we filed an Interim Financing Application with the ACC
requesting a waiver of certain ACC rules to permit us to (a) make short-term
advances to Pinnacle West in the form of an inter-affiliate line of credit or
(b) guarantee Pinnacle West's short-term debt. In either case, the waiver would
be limited to a maximum aggregate principal amount of $125 million and for a
maximum term of 364 days. In the Interim Financing Application we stated that
Pinnacle West was facing short-term liquidity needs as a result of the pending
expiration of a $125 million bank facility, which is used as part of the backup
for the Pinnacle West's $250 million commercial paper program, on November 29,
2002. As of November 12, 2002, Pinnacle West had $100 million of commercial
paper outstanding. We further stated that many of Pinnacle West's lenders have
advised Pinnacle West that they will not renew the expiring facility because
they are unwilling to assume the regulatory risk that the ACC will act on the
Financing Application in a timely and favorable manner, particularly in light of
Standard & Poor's recent lowering of Pinnacle West's senior unsecured debt
rating. We stressed that Pinnacle West's need for the short-term line of credit
or guarantee was a direct result of the regulatory developments giving rise to
the Financing Application (see above) and stated that the line of credit or
guarantee was designed as a pure liquidity backstop and would be the last
borrowing choice for Pinnacle West. Pinnacle West is also evaluating other
options to ensure adequate liquidity. We also requested that the Interim
Financing Application be decided by the ACC on an emergency basis at its
November 19, 2002 meeting.
15
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, which has a price cap of approximately $90 per MWh and
was originally ordered to remain in effect until September 30, 2002, was
extended to remain in place until October 31, 2002. FERC has adopted a price cap
for the period thereafter of $250 per MWh.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for
Standard Market Design for wholesale electric markets. We are reviewing the
proposed rulemaking and cannot currently predict what, if any, impact there may
be to the Company if the FERC adopts the proposed rule.
GENERAL
The regulatory developments and legal challenges to the Rules discussed in
this note have raised considerable uncertainty about the status and pace of
electric competition in Arizona. Although some very limited retail competition
existed in our service area in 1999 and 2000, there are currently no active
retail competitors offering unbundled energy or other utility services to our
customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter our service territory. 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
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.
16
7. Business Segments
We have two principal business segments (determined by products, services
and the regulatory environment), which consist of our regulated retail
electricity business, regulated traditional wholesale electricity business, and
related activities (electric retail business segment) and our competitive
business activities (marketing and trading business segment). Our electric
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 related assets and liabilities, to Pinnacle West (see Note 14).
Financial data for our business segments follows (dollars in millions):
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
--------------- --------------- ---------------
2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------
Operating Revenues:
Electric retail $ 745 $ 974 $1,636 $2,126 $2,072 $2,581
Marketing and trading 9 65 22 543 29 706
------ ------ ------ ------ ------ ------
Total $ 754 $1,039 $1,658 $2,669 $2,101 $3,287
====== ====== ====== ====== ====== ======
Income Before
Accounting Change:
Electric retail $ 86 $ 87 $ 182 $ 103 $ 218 $ 136
Marketing and trading 1 21 1 139 4 160
------ ------ ------ ------ ------ ------
Total $ 87 $ 108 $ 183 $ 242 $ 222 $ 296
====== ====== ====== ====== ====== ======
8. Accounting Matters
In June 2002, the FASB's EITF issued certain guidance related to energy
trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities." The new guidance, which was effective July 1, 2002,
required that all energy trading activities within the scope of EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," be presented on a net basis in revenues and that prior period
amounts be restated.
In October 2002, the EITF reached a consensus that gains and losses on
derivative instruments within the scope of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," should be shown net in the
income statement if the derivative is held for trading purposes. This decision
effectively supersedes the guidance provided at the June meeting. Beginning in
the third quarter of 2002, we have netted all of our energy trading activities
on the income statement and have restated prior amounts.
In the October 2002 meeting, the EITF also rescinded EITF 98-10. This
guidance is effective immediately for all new contracts and on January 1, 2003
for existing contracts. As such, energy trading contracts will be accounted for
on an accrual basis with the associated revenues and costs recorded at the time
the contracted commodities are delivered or received, unless the contracts are
required to be marked to market as derivatives under SFAS No. 133, or if allowed
by other guidance. For existing contracts, we will record a cumulative effect
adjustment in net income for the previously recorded accumulated unrealized
mark-to-market on energy trading contracts that do not meet the definition of a
derivative under SFAS No. 133. We are currently evaluating the impact of this
guidance on our financial statements.
17
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which we will adopt January 1, 2003. The standard
requires the fair value of asset retirement obligations to be recorded as a
liability, along with an offsetting plant asset, when the obligation is
incurred. Accretion of the liability due to the passage of time will be an
operating expense and the capitalized cost will be depreciated over the useful
life of the long-lived asset.
We determined that we have asset retirement obligations for our nuclear
facilities (nuclear decommissioning) and certain other fossil generation,
transmission, and distribution assets. The standard is not expected to have a
material impact on net income because the assets with significant retirement
obligations are regulated. We expect to establish a regulatory asset or
liability to offset the impacts of this standard on the regulated assets.
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, which would be effective for us in 2004, would create a project
timeline framework for capitalizing costs related to property, plant and
equipment construction. It would 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 early 2003.
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 condensed balance sheets. This new standard has
no material impact on 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 April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
Nos. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" which, among other things, supersedes previous guidance for
reporting gains and losses from extinguishment of debt and accounting for
leases. The portion of the statement relating to the early extinguishment of
debt is effective for us beginning in 2003. We do not believe the adoption of
this statement will have a material impact on our financial statements.
18
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." The standard requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The guidance should be applied prospectively to exit or disposal activities
initiated after December 31, 2002.
See Note 9 for accounting developments related to special-purpose entities.
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 July 2002, the
FASB issued an exposure draft related to SPEs. It is expected that the FASB will
issue final guidance on accounting for SPEs during the fourth quarter of 2002
with an immediate effective date for newly-created entities and for all other
entities as of the beginning of the first fiscal period beginning on or after
April 1, 2003. We are currently evaluating the impacts of the exposure draft and
we may be required to consolidate the Palo Verde SPEs in our financial
statements.
If consolidation were required, the assets and liabilities of the SPEs that
relate to the sale-leaseback transactions would be reflected on our condensed
balance sheet at fair value on the date of implementation. We are currently
evaluating the impact of including the related fair value of assets and
liabilities. The secured lease obligation bonds that are not reflected on our
condensed balance sheet at September 30, 2002 total approximately $285 million.
The rating agencies have already considered this debt when evaluating our credit
ratings. This is our 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
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 commodities.
Effective January 1, 2001, we adopted SFAS No. 133. 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", or the amount by which the derivative contract and the hedge
commodity are not directly correlated, is recognized immediately in net income.
19
On January 1, 2001, we recorded a $3 million after-tax loss in net income
and a $65 million after-tax gain in equity (as a component of other
comprehensive income), both as cumulative effects 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 was reflected in net income and other comprehensive
income as cumulative effects 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 was April 1, 2002. The impact of this
guidance was immaterial to our financial statements.
The changes in derivative fair value included in the condensed statements
of income for the three, nine and twelve months ended September 30, 2002 and
2001 are comprised of the following (dollars in thousands):
20
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Gains (losses) on the
ineffective portion of
derivatives qualifying
for hedge accounting $ (561) $ (1,879) $ 2,554 $ (5,748) $ 2,246 $ (5,748)
Gains (losses) from the
discontinuance of cash
flow hedges -- (2,417) (44) (5,273) 546 (5,273)
Gains (losses) from
non-hedge derivatives (5,654) 1,050 (8,768) (6,733) (9,192) (6,733)
Prior period mark-to- market
losses realized upon
delivery of commodities 1,469 19,880 8,209 26,358 7,798 26,358
-------- -------- -------- -------- -------- --------
Total pretax gain (loss) $ (4,746) $ 16,634 $ 1,951 $ 8,604 $ 1,398 $ 8,604
======== ======== ======== ======== ======== ========
As of September 30, 2002, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted
transactions is twenty-seven months. During the twelve months ending September
30, 2003, we estimate that a net loss of $17 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.
11. Comprehensive Income
Components of comprehensive income for the three, nine and twelve months
ended September 30, 2002 and 2001, are as follows (dollars in thousands):
21
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
--------------------- --------------------- ----------------------
2002 2001 2002 2001 2002 2001
--------- --------- --------- --------- --------- ---------
Net income $ 86,570 $ 95,110 $ 182,772 $ 226,600 $ 221,659 $ 280,337
--------- --------- --------- --------- --------- ---------
Other comprehensive
income (loss):
Minimum pension liability,
net of tax -- -- -- -- (966) --
Cumulative effect of
change in accounting for
derivatives, net of tax -- 7,801 -- 72,501 -- 72,501
Unrealized gains (losses)
on hedging derivatives,
net of tax (a) 1,266 (11,353) 19,425 (92,493) 24,132 (92,493)
Reclassification of
hedging derivatives net
realized (gains) losses
to income, net of tax (b) 2,089 (11,145) 12,403 (46,617) 10,706 (46,617)
--------- --------- --------- --------- --------- ---------
Total other comprehensive
income (loss) 3,355 (14,697) 31,828 (66,609) 33,872 (66,609)
--------- --------- --------- --------- --------- ---------
Comprehensive income $ 89,925 $ 80,413 $ 214,600 $ 159,991 $ 255,531 $ 213,728
========= ========= ========= ========= ========= =========
(a) These amounts primarily include unrealized gains and losses on contracts
used to hedge our forecasted gas requirements to serve Native Load.
(b) These amounts primarily include the reclassification of unrealized gains
and losses to realized for contracted commodities delivered during the
period.
22
12. Commitments and Contingencies
California Energy Market Issues and Refunds in the Pacific Northwest
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 nor 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.
SCE and PG&E have publicly disclosed that their liquidity has been
materially and adversely affected because of, among other things, their
inability to pass on to ratepayers the prices each has paid for energy and
ancillary services procured through the PX and the ISO. PG&E filed for
bankruptcy protection in 2001.
We are closely monitoring developments in the California energy market and
the potential impact of these developments on us. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with SCE and
PG&E; and marketing and trading exposures. Based on our evaluations, we do not
believe the foregoing matters will have a material adverse affect 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.
CALIFORNIA ENERGY MARKET LITIGATION. 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." This complaint has been dismissed by FERC and the State of California
is now appealing the matter to the Ninth Circuit Court of Appeals. In addition,
the State of California and others have filed various claims, which have now
been consolidated, against several 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 and
Trading, LLP (and other Duke entities), filed cross-claims against various other
participants in the 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.
23
We were also named in a lawsuit regarding wholesale contracts in
California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United
States District Court in and for the District of Northern California, Case No.
C02-2855 EMC. The complaint alleges basically that the contracts entered into
were the result of an unfair and unreasonable market. The PX has filed a lawsuit
against the State of California regarding the seizure of forward contracts and
the State has filed a cross complaint against us and numerous PX participants.
CAL PX V. THE STATE OF CALIFORNIA Superior Court in and for the County of
Sacramento, JCCP No. 4203. Various preliminary motions are being filed and we
cannot currently predict the outcome of this matter. The "United States Justice
Foundation" is suing numerous wholesale energy contract suppliers to California,
including Pinnacle West, as well as the California Department of Water
Resources, based upon an alleged conflict of interest arising from the
activities of a consultant for Edison International who also negotiated
long-term contracts for the California Department of Water Resources.
MCCLINTOCK, ET AL. V. YUDHRAJA, Superior Court in and for the County of Los
Angeles, Case No. GC 029447. The California Attorney General has indicated that
an investigation by his office did not find evidence of improper conduct by the
consultant. We believe the claims against us in the lawsuits mentioned in this
paragraph are without merit and will have no material adverse impact on our
financial position, results of operations or liquidity.
Power Service Agreement
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised us that it believes we 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 $190 million at September 30, 2002 and $170 million at December
31, 2001. The related accumulated amortization was $100 million at September 30,
2002 and $87 million at December 31, 2001. Amortization expense for the three
month period ended September 30 was $5 million in 2002 and 2001. Amortization
expense for the nine month period ended September 30 was $13 million in 2002 and
$16 million in 2001. Amortization expense for the twelve month period ended
September 30 was $19 million in 2002 and $21 million in 2001. 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.
24
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 condensed income statements and condensed balance sheets related
to transactions with affiliated companies (dollars in millions):
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
------------- ------------- -------------
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Electric operating revenues:
Pinnacle West -
marketing and trading $120 $ 50 $167 $ 50 $167 $ 50
APS Energy Services -- -- -- 5 10 31
---- ---- ---- ---- ---- ----
Total $120 $ 50 $167 $ 55 $177 $ 81
==== ==== ==== ==== ==== ====
Purchased power and fuel costs:
Pinnacle West -
marketing and trading(a) $ 53 $ 18 $ 67 $ 44 $ 73 $ 44
Pinnacle West Energy -- 9 -- 9 5 9
---- ---- ---- ---- ---- ----
Total $ 53 $ 27 $ 67 $ 53 $ 78 $ 53
==== ==== ==== ==== ==== ====
- ----------
(a) Consistent with our October 2001 ACC filing, in which we requested approval
of a purchase power agreement with Pinnacle West to ensure ongoing reliable
service to our customers in a volatile generation market, during 2002 we
entered into agreements with our affiliates to buy power. The agreements,
which expire December 31, 2002, reflect a price based on the
fully-dispatchable dedication of the Pinnacle West Energy generating assets
to our Native Load customers.
25
As of As of
September 30, 2002 December 31, 2001
------------------ -----------------
Accounts receivable - other:
Pinnacle West - marketing
and trading $143 $ 76
Pinnacle West 26 24
APS Energy Services -- 13
Pinnacle West Energy 2 2
---- ----
Total $171 $115
==== ====
Accounts payable:
Pinnacle West - marketing
and trading $ 41 $ 21
Pinnacle West 25 36
Pinnacle West Energy 1 2
---- ----
Total $ 67 $ 59
==== ====
15. Other Income and Other Expense
The following table provides detail of other income and other expense for
the three, nine and twelve months ended September 30, 2002 and 2001 (dollars in
thousands):
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Other income:
Environmental insurance
recovery $ -- $ -- $ -- $ 10,947 $ 1,402 $ 10,947
Investment gains - net -- -- 253 -- -- --
Interest income 1,521 923 2,947 2,625 5,326 4,854
Miscellaneous 441 246 1,310 873 3,290 1,426
-------- -------- -------- -------- -------- --------
Total other income $ 1,962 $ 1,169 $ 4,510 $ 14,445 $ 10,018 $ 17,227
======== ======== ======== ======== ======== ========
Other expense:
Investment losses - net $ (1,312) $ (66) $ -- $ (2,489) $ (612) $ (4,075)
Non-operating costs (a) (3,884) (2,641) (11,529) (7,552) (15,351) (13,037)
Miscellaneous (877) (112) (2,452) (2,489) (6,024) (5,036)
-------- -------- -------- -------- -------- --------
Total other expense $ (6,073) $ (2,819) $(13,981) $(12,530) $(21,987) $(22,148)
======== ======== ======== ======== ======== ========
(a) Primarily includes below-the-line non-operating utility costs.
26
16. 2002 Severance Charges
In July 2002, we announced cost containment measures that included a
voluntary workforce reduction. We recorded $23 million before taxes in voluntary
severance costs in the third quarter of 2002. We expect to record up to $11
million before taxes for additional severance costs in the fourth quarter of
2002.
17. 2002 IRS Tax Refund
As a result of a change in IRS guidance, we claimed a tax deduction related
to a tax accounting method change on the 2001 Pinnacle West Federal consolidated
income tax return. The accelerated deduction has resulted in a $200 million
reduction in our current tax liability.
18. Regulatory Accounting
We are regulated by the ACC and the FERC. The accompanying condensed
financial statements reflect the ratemaking policies of these commissions. 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. EITF 97-4 requires that SFAS No. 71 be discontinued no
later than when legislation is passed or a rate order is used that contains
sufficient detail to determine its effect on the portion of the business being
deregulated. In 1999, we discontinued the application of SFAS No. 71 for our
generation operations due to the 1999 Settlement Agreement with the ACC. See
Note 5 for a discussion of the 1999 Settlement Agreement. In the Track A Order,
the ACC determined that we would not be able to transfer our generation assets
as provided for in the 1999 Settlement Agreement (see Note 5). Accordingly, we
now consider our generation to be cost-based, rate-regulated and subject to the
requirements of SFAS No. 71. The impacts of this change were immaterial to our
financial statements.
27
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, 2002 and 2001;
* the effects of regulatory agreements and developments 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 an electric utility that provides retail and wholesale electric
service to substantially all of the state of Arizona, with the major exceptions
of the Tucson metropolitan area and about one-half of the Phoenix metropolitan
area. Electricity is provided through a distribution system owned by us. 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.
BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and the regulatory environment), which consist of our regulated retail
electricity business, regulated traditional wholesale electricity business, and
related activities (electric retail segment) and our competitive business
activities (marketing and trading segment). Our electric 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 to Pinnacle West (see
Note 14).
28
The following table summarizes net income by business segment for the
three, nine and twelve months ended September 30, 2002 and the comparable prior
year periods (dollars in millions):
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
--------------- --------------- ---------------
2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------
Electric retail $ 86 $ 87 $ 182 $ 103 $ 218 $ 136
Marketing and trading 1 21 1 139 4 160
------ ------ ------ ------ ------ ------
Income before accounting
change 87 108 183 242 222 296
Cumulative effect of change
in accounting - net of
income taxes (a) -- (12) -- (15) -- (15)
------ ------ ------ ------ ------ ------
Net income $ 87 $ 96 $ 183 $ 227 $ 222 $ 281
====== ====== ====== ====== ====== ======
(a) We recorded the cumulative effects of a change in accounting for
derivatives related to our adoption in 2001 of SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (see Note 10).
Consistent with our October 2001 ACC filing, in which we requested approval
of a purchase power agreement with Pinnacle West to ensure ongoing reliable
service to our customers in a volatile generation market, during 2002 we entered
into agreements with our affiliates to buy power. The agreements which expire
December 31, 2002 reflect a price based on the fully-dispatchable dedication of
the Pinnacle West Energy generating assets to our Native Load customers.
EARNINGS VARIANCE EXPLANATIONS
Throughout these explanations, we refer to "gross margin." With respect to
our electric retail segment and marketing and trading segment, gross margin
refers to electric operating revenues less purchased power and fuel costs. In
June and October 2002, the EITF provided certain guidance related to energy
trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities" (see Note 8). Beginning in the third quarter of
2002, we have netted all of our energy trading activities on the income
statement and have restated prior period amounts.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2002 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2001
Our net income for the three months ended September 30, 2002 was $87
million compared with $96 million for the same period in the prior year. We
recognized a $12 million after-tax loss in the three months ended September 30,
2001 as a cumulative effect of a change in accounting for derivatives, as
required by SFAS No. 133 (see Note 10).
Our income before accounting change for the three months ended September
30, 2002 was $87 million compared with $108 million for the same period in the
prior year. The period-to-period decrease was primarily the result of reduced
29
marketing and trading segment gross margin due to our transfer of marketing and
trading activities to Pinnacle West in 2001 and severance costs of $23 million
pretax recorded in the third quarter of 2002 related to a voluntary workforce
reduction (see Note 16). The regulated retail comparison was favorably impacted
by customer growth and higher average usage per customer, lower replacement
costs for power plant outages, and lower costs for purchased power costs related
to the 2001 generation reliability program. These factors were partially offset
by effects of weather on retail sales, higher hedged costs for purchased power
and gas and a 1.5% retail electricity price reduction that took effect July 1,
2002.
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Marketing and trading segment gross margin:
Decrease in generation sales other than Native Load due to lower
market prices and resulting lower sales volumes $ (2)
Decrease in marketing and trading segment margin resulting from our
transfer of marketing and trading activities to Pinnacle West in
2001 (32)
----------
Net decrease in marketing and trading segment gross margin (34)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower market
prices and fewer unplanned outages 15
Lower hedge management margin, partially offset by lower purchased
power and fuel costs due to lower spot market prices (18)
Lower purchased power and fuel costs related to the 2001 generation
reliability program 23
Effects of weather on retail sales (10)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 22
Retail price reduction effective July 1, 2002 (9)
Change in mark-to-market for hedged natural gas and purchased
power costs for future period deliveries (see Note 10) (10)
Miscellaneous factors, net (1)
----------
Net increase in electric retail segment gross margin 12
----------
30
Total decrease in electric retail and marketing and trading segments'
gross margins (22)
Higher operations and maintenance expense primarily related to severance
costs of $23 million (see Note 16), partially offset by decreased
advertising and other costs (12)
Lower depreciation and amortization expense primarily related to lower
regulatory asset amortization 5
Higher other expense (3)
Higher net interest expense primarily due to higher debt balances (4)
Miscellaneous factors, net 3
----------
Decrease in income before income taxes (33)
Lower income taxes primarily due to lower pretax income 12
----------
Decrease in income before accounting change $ (21)
==========
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $56 million lower in the
three-month period ended September 30, 2002, compared with the same period in
the prior year. The marketing and trading segment purchased power and fuel costs
were $22 million lower in the three-month period ended September 30, 2002,
compared with the same period in the prior year. The lower marketing and trading
segment revenues and purchased power and fuel costs are primarily a result of
our transfer of marketing and trading activities to Pinnacle West in 2001.
ELECTRIC RETAIL SEGMENT GROSS MARGIN
Revenues related to our regulated retail and wholesale electricity
businesses were $229 million lower in the three-month period ended September 30,
2002, compared with the same period in the prior year as a result of:
* decreased revenues related to retail load hedge management wholesale
sales, as a result of lower prices ($250 million);
* decreased retail revenues related to milder weather ($15 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($33 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($9 million); and
* other miscellaneous factors ($12 million net increase).
Electric retail segment purchased power and fuel costs were $241 million
lower in the three-month period ended September 30, 2002, compared with the same
period in the prior year as a result of:
* decreased costs related to lower prices for hedged natural gas and
purchased power ($232 million);
31
* lower purchased power costs related to the 2001 generation reliability
program ($23 million);
* decreased costs related to the effects of milder weather on retail
sales ($5 million);
* increased costs related to retail sales growth, excluding weather
effects ($11 million);
* change in mark-to-market for hedged natural gas and purchased power
costs for future period deliveries (see Note 10) ($10 million
increase);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned nuclear and coal plant outages ($15
million); and
* other miscellaneous factors ($13 million net increase).
The increase in operations and maintenance expense of $12 million was due
to severance costs related to a voluntary workforce reduction of $23 million
(see Note 16), partially offset by decreased advertising costs and lower other
costs.
The decrease in depreciation and amortization expense of $5 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 Settlement Agreement, partially offset by increased depreciation on higher
plant balances.
Interest expense, net of amounts capitalized, increased $4 million
primarily due to higher debt balances.
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2002 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2001
Our net income for the nine months ended September 30, 2002 was $183
million compared with $227 million for the same period in the prior year. We
recognized a $15 million after-tax loss in the nine months ended September 30,
2001 as a cumulative effect of a change in accounting for derivatives, as
required by SFAS No. 133 (see Note 10).
Our income before accounting change for the nine months ended September 30,
2002 was $183 million compared with $242 million for the same period in 2001.
The period-to-period decrease was the result of reduced marketing and trading
segment gross margin due to our transfer of marketing and trading activities to
Pinnacle West in 2001, and severance costs of $23 million pretax recorded in the
third quarter related to a voluntary workforce reduction (see Note 16). These
factors were partially offset by increased earnings contributions from our
regulated retail electricity operations. The retail comparison was favorably
impacted by lower replacement costs for power plant outages, customer growth and
higher average usage per customer, lower purchased power costs related to the
2001 generation reliability program, partially offset by the effects of milder
weather and retail electricity price decreases.
32
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Marketing and trading segment gross margin:
Decrease in generation sales other than Native Load due to lower
market prices and resulting lower sales volumes $ (75)
Decrease in marketing and trading segment margin resulting from our
transfer of marketing and trading activities to Pinnacle West in
2001 (153)
----------
Net decrease in marketing and trading segment gross margin (228)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower market
prices and fewer unplanned outages 123
Lower hedge management margin, partially offset by lower
purchased power and fuel costs due to lower spot market prices (6)
Lower purchased power costs related to the 2001 generation reliability
program 28
Effects of weather on retail sales (21)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 37
Retail price reductions effective July 1, 2001 and July 1, 2002 (22)
Change in mark-to-market for hedged natural gas and purchased
power costs for future period deliveries (See Note 10) 5
Miscellaneous factors, net (4)
----------
Net increase in electric retail segment gross margin 140
----------
Total decrease in electric retail and marketing and trading segments'
gross margins (88)
Higher operations and maintenance expense primarily related to severance
costs of $23 million (See Note 16), partially offset by lower generation
reliability outages and other costs (9)
Lower depreciation and amortization expense primarily due to lower
regulatory asset amortization, partially offset by increased depreciation
and amortization on higher property, plant, and equipment balances 17
Lower other income (10)
Higher net interest expense primarily due to higher debt balances,
partially offset by lower interest rates (4)
Miscellaneous factors, net (2)
----------
Decrease in income before income taxes (96)
Lower income taxes primarily due to lower pretax income 37
----------
Decrease in income before accounting change $ (59)
==========
33
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $521 million lower in the
nine-month period ended September 30, 2002, compared with the same period in the
prior year as a result of:
* decreased revenues from generation sales other than Native Load due to
lower market prices and resulting lower sales volumes ($128 million);
and
* lower marketing and trading revenues as a result of our transfer of
marketing and trading activities to Pinnacle West in 2001 ($393
million).
Marketing and trading segment purchased power and fuel costs were $293
million lower in the nine-month period ended September 30, 2002, compared with
the same period in the prior year as a result of:
* decreased fuel costs related to generation sales other than Native
Load primarily because of lower natural gas prices and lower sales
volumes ($53 million); and
* lower marketing and trading purchased power and fuel costs as a result
of our transfer of marketing and trading activities to Pinnacle West
in 2001 ($240 million).
ELECTRIC RETAIL SEGMENT GROSS MARGIN
Revenues related to our regulated retail and wholesale electricity
businesses were $490 million lower in the nine-month period ended September 30,
2002, compared with the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($65 million);
* decreased revenues related to retail load hedge management wholesale
sales, as a result of lower prices and lower sales volumes ($418
million);
* decreased retail revenues related to milder weather ($50 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($68 million);
* decreased retail revenues related to reductions in retail electricity
prices ($22 million); and
* other miscellaneous factors ($3 million net decrease).
Electric retail segment purchased power and fuel costs were $630 million
lower in the nine-month period ended September 30, 2002, compared with the same
period in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($65 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power ($412 million);
* lower purchased power costs related to the 2001 generation reliability
program ($28 million);
34
* decreased costs related to the effects of milder weather on retail
sales ($29 million);
* increased costs related to retail sales growth, excluding weather
effects ($31 million);
* change in mark-to-market for hedged natural gas and purchased power
costs for future period deliveries (see Note 10) ($5 million
decrease);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned nuclear and coal plant outages ($123
million); and
* other miscellaneous factors ($1 million net increase).
The increase in operations and maintenance expense of $9 million was
primarily due to severance costs related to a voluntary workforce reduction of
$23 million (see Note 16), partially offset by lower costs related to generation
reliability plant outages and other costs.
The decrease in depreciation and amortization expense of $17 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 Settlement Agreement, partially offset by increased depreciation on higher
property, plant and equipment balances.
Other income decreased $10 million primarily due to an insurance recovery
recorded in the prior period related to environmental remediation costs.
Interest expense increased $4 million primarily due to higher debt
balances, partially offset by lower interest rates.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2002 COMPARED
WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2001
Our net income for the twelve months ended September 30, 2002 was $222
million compared with $281 million for the same period in the prior year. We
recognized a $15 million after-tax loss in the twelve months ended September 30,
2001 as a cumulative effect of a change in accounting for derivatives, as
required by SFAS No. 133 (see Note 10).
Our income before accounting change for the twelve months ended September
30, 2002 was $222 million compared with $296 million for the same period a year
earlier. The period-to-period decrease is the result of our transfer of
marketing and trading activities to Pinnacle West by the end of 2001, lower
earnings contributions from our marketing and trading activities and severance
costs of $23 million pretax recorded in the third quarter of 2002 relating to a
voluntary workforce reduction (see Note 16), partially offset by increased
earnings contributions from our regulated retail electricity. The retail
comparison was favorably impacted by lower replacement costs for power plant
outages, lower costs for purchased power related to the 2001 generation
reliability program, customer growth and higher average usage per customer,
partially offset by the effects of milder weather and retail electricity price
decreases.
35
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Marketing and trading segment gross margin:
Decrease in marketing and trading segment margin related to our
transfer of marketing and trading activities to Pinnacle West in
2001 $ (153)
Decrease in generation sales other than Native Load due to lower
market prices and resulting lower sales volumes (111)
Increase in other realized marketing and trading in the current period
primarily due to higher unit margins on increased volumes (4)(a)
Change in prior period mark-to-market gains on contracts delivered
during the current period (b) 11(a)
Higher mark-to-market gains for future period deliveries (b) 2
----------
Net decrease in marketing and trading segment gross margin (255)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower market
prices and fewer unplanned outages 148
Lower hedge management margins, partially offset by lower
purchased power and fuel costs due to lower market prices (27)
Lower purchased power costs related to the 2001 generation reliability
program 26
Effects of milder weather on retail sales (21)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 39
Retail price reductions effective July 1, 2001 and July 1, 2002 (28)
Change in mark-to-market for hedged natural gas and purchase
power costs for future period deliveries (see Note 10) 4
Miscellaneous factors, net 1
----------
Net increase in electric retail segment gross margin 142
----------
Total decrease in electric retail and marketing and trading segments'
gross margins (113)
Higher operations and maintenance expense primarily related to severance
costs for a voluntary workforce reduction of $23 million (see Note 16)
and an environmental reserve in the fourth quarter of 2000, partially
offset by decreased generation reliability, plant outages, and other
costs (11)
Lower depreciation and amortization primarily due to lower regulatory asset
amortization, partially offset by increased depreciation and
amortization on higher property, plant and equipment balances 14
Lower other income (7)
----------
Decrease in income before income taxes (117)
Lower income taxes primarily due to lower income 43
----------
Decrease in income before accounting change $ (74)
==========
36
(a) Net marketing and trading gains (excluding the effects of generation sales
other than Native Load) recognized for the current period increased $7
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is
economically hedged with a portfolio of forward purchases that protects the
economic value of the sales transactions.
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $677 million lower in the
twelve-month period ended September 30, 2002, compared with the same period in
the prior year as a result of:
* decreased revenues as a result of our transfer of marketing and
trading activities to Pinnacle West at the end of 2001 ($393 million);
* decreased revenues from generation sales other than Native Load due to
lower market prices and resulting lower sales volumes ($202 million);
* decreased revenues from other realized marketing and trading in the
current period primarily due to lower prices ($95 million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to higher volumes being delivered ($11
million increase); and
* higher mark-to-market gains for future period deliveries primarily as
a result of greater market liquidity and greater price volatility,
resulting in lower volumes ($2 million).
Marketing and trading segment purchased power and fuel costs were $422
million lower in the twelve-month period ended September 30, 2002, compared with
the same period in the prior year as a result of:
* decreased purchased power and fuel costs as a result of our transfer
of marketing and trading activities to Pinnacle West at the end of
2001 ($240 million);
* decreased fuel costs related to generation sales other than Native
Load primarily because of lower sales volumes and lower natural gas
prices ($91 million); and
* decreased purchased power costs related to other realized marketing
activities in the current period primarily due to lower prices ($91
million).
Electric Retail Segment Gross Margin
Revenues related to our regulated retail and wholesale electricity
businesses were $509 million lower in the twelve-month period ended September
30, 2002, compared with the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($79 million);
* decreased revenues related to retail load hedge management wholesale
sales, as a result of lower sales volumes and lower prices ($435
million);
* decreased retail revenues related to milder weather ($50 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($82 million);
37
* decreased retail revenues related to reductions in retail electricity
prices ($28 million); and
* other miscellaneous factors ($1 million net increase).
Electric retail segment purchased power and fuel costs were $651 million
lower in the twelve-month period ended September 30, 2002, compared with the
same period in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($79 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power prices ($408 million);
* lower purchased power costs related to the 2001 generation reliability
program ($26 million);
* decreased costs related to the effects of milder weather on retail
sales ($29 million);
* increased costs related to retail sales growth, excluding weather
effects ($43 million);
* change in mark-to-market for hedged natural gas and purchased power
costs for future period deliveries (See Note 10) ($4 million
decrease); and
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($148 million).
The increase in operations and maintenance expense of $11 million was
primarily due to higher costs related to severance costs related to a voluntary
workforce reduction of $23 million (see Note 16) and a reversal of an
environmental reserve in the fourth quarter of 2000, partially offset by lower
generation reliability, plant outages and maintenance costs.
The decrease in depreciation and amortization expenses of $14 million
primarily related to lower regulatory asset amortization, in accordance with the
1999 Settlement Agreement, partially offset by increased depreciation and
amortization on higher property, plant and equipment balances.
Other income decreased $7 million primarily due to an insurance recovery
recorded in the prior period related to environmental remediation costs and
other costs.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the nine
months ended September 30, 2002 and estimated capital expenditures for the next
three years (dollars in millions):
38
Nine Months
Ended Estimated
September 30, --------------------------
2002 2002 2003 2004
------ ------ ------ ------
Delivery $ 270 $ 347 $ 270 $ 267
Existing generation (a) 106 149 116 89
------ ------ ------ ------
Total $ 376 $ 496 $ 386 $ 356
====== ====== ====== ======
(a) This table assumes that our generation assets and Pinnacle West Energy
generation assets remain separate, consistent with the ACC's Track A Order
(see Note 5).
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 to 2004 time frame.
Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants and the replacement of
steam generators. 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 environmental equipment. The existing
generation also contains nuclear fuel expenditures of approximately $30 million
annually in 2002, 2003 and 2004.
Several years ago, we, along with the other Palo Verde participants,
decided to replace Palo Verde Unit 2 steam generators, which replacement is
presently scheduled to be completed in the fall of 2003. 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 fabrication of one set of spare steam generators. Our portion of
this expenditure is approximately $27 million, which will be spent from 2002 to
2005. Existing generation in the capital expenditures table above includes $21
million of the costs in 2002 through 2004. If the Palo Verde participants decide
to proceed with steam generator replacement at both Units 1 and 3, we have
estimated that our portion of the fabrication and installation costs and
associated power uprate modifications would be approximately $130 million over
the next seven years, which would be funded with internally-generated cash or
external financings.
CAPITAL RESOURCES AND CASH REQUIREMENTS
The following table summarizes actual contractual cash commitments for the
nine months ended September 30, 2002 and estimated contractual commitments for
the next five years and thereafter (dollars in millions):
39
Estimated
Nine ---------------------------------------------------
Months Years Ended December 31,
Ended ---------------------------------------------------
September 30, There-
2002 2002 2003 2004 2005 2006 after
------ ------ ------ ------ ------ ------ ------
Long-term debt payments $ 247 $ 247 $ -- $ 205 $ 400 $ 84 $1,518
Operating leases payments 44 63 61 61 60 60 514
Fuel and purchase power
commitments 240 307 129 82 65 68 170
------ ------ ------ ------ ------ ------ ------
Total cash commitments (a) $ 531 $ 617 $ 190 $ 348 $ 525 $ 212 $2,202
====== ====== ====== ====== ====== ====== ======
(a) Total cash commitments are approximately $4.1 billion. The total net
present value of these cash commitments is approximately $2.2 billion.
In mid-2003, Pinnacle West will need to refinance approximately $550
million of parent company indebtedness, including a total of $300 million
Pinnacle West expects to borrow under a credit facility. If the ACC does not
grant the approvals requested in the Financing Application in a timely fashion,
Pinnacle West would anticipate taking the following steps, to the extent
necessary in priority order, although the timing of Pinnacle West's liquidity
needs may affect the order of the steps taken:
* The reduction of capital expenditures through plant delay and
cancellation;
* The sale of non-core assets; and
* The issuance of new debt and, if appropriate, new equity.
Although we believe it would be inappropriate to discuss specific amounts
for each of the foregoing categories, we estimate the sum of these steps to
approximate the current outstanding debt at Pinnacle West, which, as noted
above, totaled approximately $1.1 billion as of September 30, 2002.
CREDIT RATINGS
The ratings of securities of the Company as of the date of this report are
shown below and reflect the respective views of the rating agencies, from whom
an explanation of the significance of their ratings may be obtained. There is no
assurance that these ratings will continue for any given period of time or that
they will not be revised or withdrawn entirely by the rating agencies, if, in
their respective judgments, circumstances so warrant. Any downward revision or
withdrawal may adversely effect the market price of the Company's securities and
serve to increase our cost of capital, and access to capital.
Moody's Standard & Poor's Fitch
------- ----------------- -----
Senior Secured A3 A- A-
Senior Unsecured Baa1 BBB BBB+
Secured Lease
Obligation Bonds Baa2 BBB BBB
Commercial Paper P-2 A-2 F-2
40
On November 4, 2002 Standard & Poor's affirmed our debt ratings in the
above chart but lowered Pinnacle West's senior unsecured debt rating from BBB to
BBB- "because of the structural subordination of this debt compared to the
unsecured debt of APS". On that same date, Standard & Poor's lowered our
corporate credit rating from BBB+ to BBB. All our credit ratings remain
investment grade. Standard & Poor's assigned a stable outlook to the ratings.
DEBT PROVISIONS
Our significant debt covenants related to our respective financing
arrangements include a debt-to-total-capitalization ratio and an interest
coverage test. We are in compliance with such covenants and we anticipate that
we will continue to meet all the significant covenant requirement levels.
Failure to comply with such covenant levels would result in an event of default
which, generally speaking, would require the immediate repayment of the debt
subject to the covenants.
Our financing agreements do not contain "ratings triggers" that would
result in an acceleration of the required interest and principal payments in the
event of a ratings downgrade. However, in the event of a ratings downgrade, we
may be subject to increased interest costs under certain financing agreements.
We are unable to quantify the effects, if any, Standard & Poor's lowering of our
corporate credit rating will affect the timing or nature of the Company's
capital requirements.
All of our bank agreements contain cross-default provisions under which a
default by us in a specified amount under another agreement would result in a
default and the potential acceleration of payment under the agreements. Our
credit agreements generally contain provisions under which the lenders could
refuse to advance loans in the event of a material adverse change in our
business or financial condition.
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.
CAPITAL REQUIREMENTS AND RESOURCES
Our capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. On September 16, 2002, we
filed a Financing Application with the ACC requesting the ACC to allow us to
borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to
Pinnacle West; to guarantee up to $500 million of Pinnacle West Energy's or
Pinnacle West's debt; or a combination of both, not to exceed $500 million in
the aggregate. On November 8, 2002, we filed an Interim Financing Application
with the ACC requesting the ACC to permit us to (a) make short-term advances to
Pinnacle West in the form of an inter-affiliate line of credit in the amount of
$125 million or (b) guarantee $125 million of Pinnacle West's short-term debt.
See "ACC Applications" in Note 5 for a discussion of the Financing Application
and the Interim Financing Application. See the table above for our cash
commitments, including our debt repayment obligations; that table does not take
into account any funds that we may lend to Pinnacle West Energy or Pinnacle West
consistent with the Interim Financing Application or the Financing Application.
41
We pay for our capital requirements with cash from operations and, to the
extent necessary, external financings. We pay for our dividends to Pinnacle West
with cash from operations.
On March 1, 2002, we issued $375 million of 6.5% Notes due 2012.
On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation
issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona
Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned
the proceeds to us pursuant to a loan agreement. The bonds were issued to
refinance $90 million of outstanding pollution control bonds.
On March 15, 2002, we redeemed at maturity $125 million of our First
Mortgage Bonds, 8.125% Series due 2002. On April 15, 2002, we redeemed $122
million of our First Mortgage Bonds, 8.75% Series due 2024. 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.
At September 30, 2002, we had credit commitments from various banks
totaling about $250 million, which were available either to support the issuance
of commercial paper or to be used as bank borrowings. At September 30, 2002, we
had approximately $25 million of commercial paper outstanding and no bank
borrowings.
We are part of a multi-employer pension plan sponsored by Pinnacle West,
Pinnacle West contributes at least the minimum amount required under Internal
Revenue Service regulations but no more than the maximum tax-deductible amount.
The minimum required funding takes into consideration the value of the fund
assets and the pension obligation. Pinnacle West has voluntarily contributed
cash to the pension plan in each of the last four years; the minimum required
contributions during each of those years was zero. Specifically, Pinnacle West
contributed $24 million for 2001, $44 million for 2000, $25 million for 1999 and
$14 million for 1998. Pinnacle West again plans to voluntarily contribute $27
million in 2002. We fund our share of the pension contribution, of which we
represent approximately 90% of the total funding amounts described above. The
assets in the plan are mostly domestic common stocks, bonds and real estate.
Pinnacle West currently forecast a pension contribution in 2003 of approximately
$50-$80 million, all or part of which may be required depending on 2002 fund
performance. If the fund performance continues to decline as a result of a
continued decline in equity markets, Pinnacle West may be required to make
contributions in future years.
Although provisions in our first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds, debt, and preferred stock that we may issue, we do not
expect any of these provisions to limit our ability to meet our capital
requirements.
As a result of a change in IRS guidance, we claimed a tax deduction related
to a tax accounting method change on the 2001 Pinnacle West consolidated Federal
income tax return. The accelerated deduction has resulted in a $200 million
reduction in our current tax liability.
42
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 (see Note 8) and the impacts of regulatory accounting on our
financial statements (see Note 18). See Note 1 in the 2001 10-K.
BUSINESS OUTLOOK
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.
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
3.1% 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, although recent regulatory developments and
legal challenges to the Rules have raised considerable uncertainty about the
status and pace of retail electric competition in Arizona (see Note 5). As
previously noted, under the 1999 Settlement Agreement, we agreed to 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, higher trending
pension and other post-retirement costs and other factors. We implemented a
voluntary workforce reduction as part of our cost-reduction program announced in
July 2002. We recorded $23 million before taxes in voluntary severance costs in
the third quarter of 2002. We expect to record up to $11 million before taxes
for additional severance costs in the fourth quarter of 2002 (See Note 16). In
addition, we are expecting to produce annual operating expense savings of
approximately $30 million beginning in 2003.
43
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. The regulatory assets to be recovered under the 1999
Settlement Agreement are currently being amortized as follow (dollars in
millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
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% of assessed value 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 factors affecting borrowing levels in
the next several years are expected to be our internally-generated cash flow.
Capitalized interest offsets a portion of interest expense while capital
projects are under construction. We stop recording capitalized interest on a
project when it is placed in commercial operation.
The regulatory developments and legal challenges to the Rules discussed in
Note 5 have raised considerable uncertainty about the status and pace of
electric competition in Arizona. Although some very limited retail competition
existed in our service area in 1999 and 2000, there are currently no active
retail competitors offering unbundled energy or other utility services to our
customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter our service territory. 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.
On October 25, 2002, the EITF voted to rescind EITF 98-10 (see Note 8). We
are evaluating the current effect of the rescission on our financial results.
On November 4, 2002, Standard & Poor's lowered our corporate credit rating
from BBB+ to BBB, see "Credit Ratings" above. We are unable to quantify the
effects, if any, of Standard & Poor's lowering of our corporate credit rating
may have on our borrowing costs or whether the lower rating will affect the
timing or nature of the Company's capital requirements.
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.
44
RATE MATTERS
See Note 5 for a discussion of a price reduction effective as of July 1,
2002, 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.
RISK FACTORS
Exhibit 99.3, which is hereby incorporated by reference, contains a
discussion of risk factors involving the Company.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements or make any
further statements on any of these issues, except as required by applicable
laws. 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; 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; regulatory issues associated
with generation expansion, such as permitting and licensing; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); technological developments in the electric industry; and the
performance of the stock market, which affects the amount of our required
contributions to our pension plan.
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.
45
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
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 EITF 98-10, "Accounting For Contracts Involved in Energy Trading and Risk
Management Activities," such trading positions are marked-to-market. These
trading activities are part of our marketing and trading activities and are
reflected in the marketing and trading segment revenues and expenses. See Note 8
for a discussion of the EITF's decision to rescind EITF 98-10.
As of September 30, 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 $15
million. A hypothetical favorable price movement of 10% would have increased the
fair market value of these contracts by approximately $17 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 this and all other 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. 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. Valuation adjustments 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 funds. Our policy is to
manage interest rates through the use of a combination of fixed-rate and
floating-rate debt. The nuclear decommissioning trust funds also have risks
associated with changing market values of equity investments. Nuclear
decommissioning costs are recovered in regulated electricity prices.
46
ITEM 4. CONTROLS AND PROCEDURES
As of a date within 90 days of the date of this report (the "Evaluation
Date"), we carried out an evaluation, under the supervision and with the
participation of our management, including our President and Chief Executive
Officer and our Vice President, Finance and Planning, of the effectiveness of
the design and operation of our disclosure controls and procedures, as defined
in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended
(the "Exchange Act"). Based upon this evaluation, our President and Chief
Executive Officer and our Vice President, Finance and Planning, concluded that,
as of the Evaluation Date, our disclosure controls and procedures were adequate
to ensure that information required to be disclosed by us in the reports filed
or submitted by us under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the SEC's rules and forms.
There were no significant changes in our internal controls or in other
factors that could significantly affect these internal controls subsequent to
the date of the evaluation, including any corrective actions with regard to
significant deficiencies and internal weaknesses.
47
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.
REGIONAL TRANSMISSION ORGANIZATIONS
As previously reported, on October 16, 2001, we and other owners of
electric transmission lines in the Southwest filed with the FERC a request for a
declaratory order confirming that their proposal to form WestConnect RTO, LLC
would satisfy the FERC's requirements for the formation of a regional
transmission organization ("RTO"). See "Regulation and Competition - Wholesale -
Regional Transmission Organizations" in Part I, Item 1 of the 2001 10-K. On
October 10, 2002, the FERC issued an order finding that the WestConnect
proposal, if modified to address specified issues, could meet the FERC's RTO
requirements and provide the basic framework for a standard market design for
the Southwest. In its order, the FERC also stated that its approval of various
WestConnect provisions addressed in the order would not be overturned or
affected by the final rule the FERC intends to ultimately adopt in response to
its July 31, 2002 Notice of Proposed Rulemaking regarding a standard market
design for the electric utility industry (see "Federal" in Note 5 for additional
information regarding the Notice of Proposed Rulemaking). FERC did not address
all of the proposed WestConnect provisions in its order and some could still be
affected by a final rule in the pending rulemaking proceeding. We cannot
currently predict what, if any, impact there may be to the WestConnect proposal
or to us if the FERC adopts the proposed SMD rule. On November 12, 2002, APS and
other owners filed a request for rehearing and clarification on portions of the
October 10 order.
NATURAL GAS SUPPLY
As previously reported on May 31, 2002, the FERC issued an order requiring
the conversion of all Full Requirements contracts to Contract Demand contracts.
See "Natural Gas Supply in Part II, Item 5 of the June 2002 10-Q. On September
20, 2002, the FERC issued another order clarifying the capacity allocation
methodology, extending the conversion implementation date from November 1, 2002
to May 1, 2003 and approving reallocation of costs for service. We and other
Full Requirement contract holders have sought rehearings of the FERC orders. We
currently do not expect this to have a material adverse impact on our financial
position, results of operations or liquidity.
48
COAL SUPPLY
Because covenants under the Four Corners lease and related federal
rights-of-way and grants expired in July 2001, the Navajo Nation assessed taxes
on the coal supplier and the plant. See "Coal Supply" in Part II, Item 5 of the
June 2002 10-Q. In July 2002, we negotiated a settlement agreement with the
Navajo Nation relating to the plant pursuant to which we will make settlement
payments to the Navajo Nation and that settlement agreement was executed in
August 2002. Pursuant to the terms of the settlement agreement, we do not expect
the payments to have a material adverse impact 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
99.1 Certification of Jack E. Davis, the Registrant's
principal executive officer, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
99.2 Certification of Donald G. Robinson, the Registrant's
principal financial officer, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
99.3 APS Risk Factors
49
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.(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 3.2 to Pinnacle West 1-8962 11-14-02
September 18, 2002 September 2002 Form
10-Q Report
10.1 Employment 10.1 to Pinnacle West 1-8962 11-14-02
Agreement effective September 2002 Form
as of October 1, 2002 10-Q Report
between APS and
James M. Levine
- ----------
(a) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
(b) Reports on Form 8-K
During the quarter ended September 30, 2002, and the period from October 1
through November 14, 2002, we filed the following reports on Form 8-K:
Report dated July 11, 2002 regarding a letter the Company filed with the
ACC.
Report dated July 23, 2002 regarding an ACC Administrative Law Judge's
recommendation on Track A issues.
Report dated August 13, 2002 filing certifications of the Company's
principal executive officer and principal financial officer.
Report dated August 27, 2002 regarding the ACC's decision on Track A
issues.
Report dated September 10, 2002 regarding the ACC's Track A Order and APS'
filing of the Financing Application.
Report dated October 17, 2002 regarding the Company's earnings outlook.
50
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 14, 2002 By: Chris N. Froggatt
------------------------------------
Chris N. Froggatt
Vice President and Controller
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
CERTIFICATIONS
I, Jack E. Davis, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Arizona Public
Service Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the period presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
51
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002.
Jack E. Davis
-------------------------------------------
Jack E. Davis
Title: Chief Executive Officer
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
CERTIFICATIONS
I, Donald G. Robinson, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Arizona Public
Service Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the period presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
52
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002.
Donald G. Robinson
-------------------------------------------
Donald G. Robinson
Title: Vice President, Finance and Planning
53