Securities and Exchange Commission
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended MARCH 31, 2003
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 by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Number of shares of common stock, $2.50 par value,
outstanding as of May 14, 2003: 71,264,947
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND
(b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE
FORMAT.
GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ADEQ - Arizona Department of Environmental Quality
ALJ - Administrative Law Judge
APS - Arizona Public Service Company, the Company
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 -Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
FIN - FASB Interpretation
Financing Order - ACC order issued on April 4, 2003 relating to our request to
provide financing or credit support to Pinnacle West Energy or Pinnacle West
Fitch - Fitch, Inc.
GAAP - accounting principles generally accepted in the United States of America
Interim Financing Order - Order issued by the ACC on November 22, 2002 relating
to our request to provide financing or credit support to Pinnacle West
IRS - United States Internal Revenue Service
ISO - California Independent System Operator
Moody's - Moody's Investors Service
MW - megawatt, one million watts
MWh - megawatt-hours, one million watts per 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
NRC - United States Nuclear Regulatory Commission
OCI - other comprehensive income
Palo Verde - Palo Verde Nuclear Generating Station
PG&E - PG&E Corp.
Pinnacle West - Pinnacle West Capital Corporation, parent company of the Company
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of
Pinnacle West
PX - California Power Exchange
Rules - ACC retail electric competition rules
SCE - Southern California Edison Company
SEC - United States Securities and Exchange Commission
SFAS - Statement of Financial Accounting Standards
1
SNWA - Southern Nevada Water Authority
SPE - special-purpose entity
Standard & Poor's - Standard & Poor's Corporation
SunCor - SunCor Development Company, a subsidiary of Pinnacle West
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
Track B Order - ACC order dated March 14, 2003 regarding competitive
solicitation requirements for power purchases by Arizona's investor-owned
electric utilities
Trading - energy-related activities entered into with the objective of
generating profits on changes in market prices
2002 10-K - the Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 2002
VIE - variable interest entity
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended March 31,
----------------------------
2003 2002
------------ ------------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Regulated electricity segment $ 387,168 $ 383,741
Marketing and trading segment 91,558 10,693
------------ ------------
Total 478,726 394,434
------------ ------------
PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment 89,382 68,285
Marketing and trading segment 85,940 10,100
------------ ------------
Total 175,322 78,385
------------ ------------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS 303,404 316,049
------------ ------------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs 121,837 109,321
Depreciation and amortization 95,557 97,622
Income taxes 10,966 21,134
Other taxes 28,214 26,751
------------ ------------
Total 256,574 254,828
------------ ------------
OPERATING INCOME 46,830 61,221
------------ ------------
OTHER INCOME (DEDUCTIONS):
Income taxes 504 365
Other income 1,789 3,152
Other expense (2,842) (3,811)
------------ ------------
Total (549) (294)
------------ ------------
INCOME BEFORE INTEREST DEDUCTIONS 46,281 60,927
------------ ------------
INTEREST DEDUCTIONS:
Interest on long-term debt 32,968 31,737
Interest on short-term borrowings 1,259 1,137
Debt discount, premium and expense 720 642
Capitalized interest (4,599) (4,352)
------------ ------------
Total 30,348 29,164
------------ ------------
NET INCOME $ 15,933 $ 31,763
============ ============
See Notes to Condensed Financial Statements.
3
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended March 31,
----------------------------
2003 2002
------------ ------------
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Regulated electricity segment $ 2,062,766 $ 2,533,022
Marketing and trading segment 114,919 312,911
------------ ------------
Total 2,177,685 2,845,933
------------ ------------
PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment 616,465 1,165,846
Marketing and trading segment 108,502 178,024
------------ ------------
Total 724,967 1,343,870
------------ ------------
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS 1,452,718 1,502,063
------------ ------------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs 508,361 460,341
Depreciation and amortization 397,575 414,819
Income taxes 122,785 161,206
Other taxes 109,388 102,532
------------ ------------
Total 1,138,109 1,138,898
------------ ------------
OPERATING INCOME 314,609 363,165
------------ ------------
OTHER INCOME (DEDUCTIONS):
Income taxes 6,287 (351)
Other income 4,669 20,844
Other expense (19,252) (18,680)
------------ ------------
Total (8,296) 1,813
------------ ------------
INCOME BEFORE INTEREST DEDUCTIONS 306,313 364,978
------------ ------------
INTEREST DEDUCTIONS:
Interest on long-term debt 129,693 125,274
Interest on short-term borrowings 5,538 4,583
Debt discount, premium and expense 2,966 2,963
Capitalized interest (15,397) (15,687)
------------ ------------
Total 122,800 117,133
------------ ------------
INCOME BEFORE ACCOUNTING CHANGE 183,513 247,845
Cumulative effect of change in accounting for derivatives -
net of income tax benefit of $8,099 -- (12,446)
------------ ------------
NET INCOME $ 183,513 $ 235,399
============ ============
See Notes to Condensed Financial Statements
4
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
ASSETS
(Dollars in Thousands)
March 31, December 31,
2003 2002
------------ ------------
UTILITY PLANT:
Electric plant in service and held for future use $ 8,413,176 $ 8,299,131
Less accumulated depreciation and amortization 3,305,581 3,442,571
------------ ------------
Total 5,107,595 4,856,560
Construction work in progress 362,351 329,089
Intangible assets, net of accumulated amortization 111,012 93,259
Nuclear fuel, net of accumulated amortization 12,232 7,466
------------ ------------
Utility plant - net 5,593,190 5,286,374
------------ ------------
INVESTMENTS AND OTHER ASSETS:
Decommissioning trust accounts 204,179 194,440
Assets from risk management and trading activities - long-term 29,033 31,622
Other assets 8,865 19,964
------------ ------------
Total investments and other assets 242,077 246,026
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents 31,783 42,549
Trust fund for bond redemption 87,225 --
Accounts receivable:
Service customers 159,763 136,945
Other 111,777 202,597
Allowance for doubtful accounts (1,022) (1,341)
Accrued utility revenues 57,306 72,915
Materials and supplies, at average cost 78,459 79,985
Fossil fuel, at average cost 32,913 28,185
Deferred income taxes 4,094 4,094
Assets from risk management and trading activities 88,419 39,616
Other 43,941 45,361
------------ ------------
Total current assets 694,658 650,906
------------ ------------
DEFERRED DEBITS:
Regulatory assets 219,344 241,045
Unamortized debt issue costs 16,050 16,696
Other 84,020 80,760
------------ ------------
Total deferred debits 319,414 338,501
------------ ------------
TOTAL ASSETS $ 6,849,339 $ 6,521,807
============ ============
See Notes to Condensed Financial Statements.
5
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
CAPITALIZATION AND LIABILITIES
(Dollars in Thousands)
March 31, December 31,
2003 2002
------------ ------------
CAPITALIZATION:
Common stock $ 178,162 $ 178,162
Additional paid-in capital 1,246,804 1,246,804
Retained earnings 793,064 819,632
Accumulated other comprehensive loss:
Minimum pension liability adjustment (61,599) (61,487)
Derivative instruments (17,067) (23,799)
------------ ------------
Common stock equity 2,139,364 2,159,312
Long-term debt less current maturities 2,013,632 2,217,340
------------ ------------
Total capitalization 4,152,996 4,376,652
------------ ------------
CURRENT LIABILITIES:
Current maturities of long-term debt 208,413 3,503
Accounts payable 118,255 118,133
Accrued taxes 126,894 82,557
Accrued interest 29,489 42,608
Customer deposits 41,855 39,865
Liabilities from risk management and trading activities 88,477 59,773
Other 68,365 51,820
------------ ------------
Total current liabilities 681,748 398,259
------------ ------------
DEFERRED CREDITS AND OTHER:
Deferred income taxes 1,222,461 1,225,552
Liabilities from risk management and trading activities - long-term 27,119 36,678
Unamortized gain - sale of utility plant 58,340 59,484
Customer advances for construction 44,179 45,513
Pension liability 169,974 156,442
Liability for asset retirement (Note 13) 223,147 --
Other 269,375 223,227
------------ ------------
Total deferred credits and other 2,014,595 1,746,896
------------ ------------
COMMITMENTS AND CONTINGENCIES (Note 12)
TOTAL LIABILITIES AND EQUITY $ 6,849,339 $ 6,521,807
============ ============
See Notes to Condensed Financial Statements.
6
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months
Ended March 31,
----------------------------
2003 2002
------------ ------------
(Dollars in Thousands)
Cash Flows from Operating Activities:
Net Income $ 15,933 $ 31,763
Items not requiring cash:
Depreciation and amortization 95,557 97,622
Nuclear fuel amortization 7,726 7,484
Deferred income taxes (7,706) (10,894)
Change in mark-to-market (19,924) (2,402)
Changes in certain current assets and liabilities:
Accounts receivable 67,855 69,530
Accrued utility revenues 15,609 12,423
Materials, supplies and fossil fuel (3,202) 476
Other current assets 1,420 (748)
Accounts payable (1,558) (48,768)
Accrued taxes 44,337 22,478
Accrued interest (13,119) (12,298)
Other current liabilities 18,534 40,372
Increase in regulatory assets (2,152) (2,096)
Change in risk management trading - assets 3,881 12,062
Change in customer advances (1,334) (8,643)
Change in pension liability 13,532 6,982
Change in other net long-term assets (7,435) (9,480)
Change in other net long-term liabilities (1,698) (27,914)
------------ ------------
Net cash flow provided by operating activities 226,256 177,949
------------ ------------
Cash Flows from Investing Activities:
Trust fund for bond redemption (87,225) (121,668)
Capital expenditures (110,264) (116,693)
Capitalized interest (4,599) (4,352)
Other 8,238 26,836
------------ ------------
Net cash flow used for investing activities (193,850) (215,877)
------------ ------------
Cash Flows from Financing Activities:
Issuance of long-term debt -- 369,930
Short-term borrowings - net -- (171,162)
Dividends paid on common stock (42,500) (42,500)
Repayment and reacquisition of long-term debt (672) (125,144)
------------ ------------
Net cash flow provided by (used for) financing activities (43,172) 31,124
------------ ------------
Net decrease in cash and cash equivalents (10,766) (6,804)
Cash and cash equivalents at beginning of period 42,549 16,821
------------ ------------
Cash and cash equivalents at end of period $ 31,783 $ 10,017
============ ============
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) $ 42,747 $ 40,716
Income taxes $ -- $ 34,777
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) and asset retirement obligations
(see Note 13). 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 2002 10-K. We have reclassified
certain prior year amounts to conform to the current year presentation (see Note
10).
2. Weather conditions cause significant seasonal fluctuations in our revenues.
In addition, trading and wholesale marketing activities can have significant
impacts on our results for interim periods. 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. In March 2003, we deposited monies with our first mortgage bond trustee to
redeem the entire $33 million of outstanding First Mortgage Bonds, 8% Series due
2025, and the entire $54 million of outstanding First Mortgage Bonds, 7.25%
Series due 2023. On April 7, 2003, we redeemed $33 million of our First Mortgage
Bonds, 8% Series due 2025. We will redeem $54 million of our First Mortgage
Bonds, 7.25% Series due 2023, on August 1, 2003.
On May 12, 2003, we issued $500 million of debt as follows: $300 million
aggregate principal amount of our 4.650% Notes due 2015 and $200 million
aggregate principal amount of our 5.625% Notes due 2033. Also on May 12, 2003,
we made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy
distributed the net proceeds of that loan to Pinnacle West to fund Pinnacle
West's repayment of a portion of the debt incurred to finance the construction
of the following Pinnacle West Energy power plants: Redhawk Units 1 and 2, West
Phoenix Units 4 and 5, and Saguaro Unit 3. See "ACC Financing Orders" in Note 5
for additional information.
5. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW
On September 10, 2002, the ACC issued the Track A Order, which, among other
things, directed us not to transfer our generation assets to Pinnacle West
Energy, as previously required under the Rules and the 1999 Settlement
Agreement. See "Track A Order" below. The Track A Order and legal challenges to
8
the Rules have raised considerable uncertainty about the status and pace of
retail electric competition in Arizona.
On March 14, 2003, the ACC issued the Track B Order, which requires us to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. See "Track B Order" below.
On April 4, 2003, the ACC issued the Financing Order authorizing us to lend
up to $500 million to Pinnacle West Energy, guarantee up to $500 million of
Pinnacle West Energy debt, or a combination of both, not to exceed $500 million
in the aggregate. See "ACC Financing Orders" below. On May 12, 2003, we issued
$500 million of debt pursuant to the Financing Order and made a $500 million
loan to Pinnacle West Energy. See Note 4.
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
we will file a general rate case with the ACC. The general rate case will also
address the implementation of retail rate adjustment mechanisms that were the
subject of ACC hearings in April 2003. See "General Rate Case and Retail Rate
Adjustment Mechanisms" below.
1999 SETTLEMENT AGREEMENT
The following are the major provisions of the 1999 Settlement Agreement, as
approved by the ACC:
o 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% on July 1 for each of the years
1999 to 2003 for a total of 7.5%. Based on the price reductions
authorized in the 1999 Settlement Agreement, there were retail price
decreases of approximately $24 million ($14 million after taxes),
effective July 1, 1999; approximately $28 million ($17 million after
taxes), effective July 1, 2000; approximately $27 million ($16 million
after taxes), effective July 1, 2001; and approximately $28 million
($17 million after taxes), effective July 1, 2002. The final 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.
o 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.
o 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.
9
o 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. See "General Rate Case and Retail Rate Adjustment Mechanisms"
below.
o 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 providing
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.
o 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 (in 1999 dollars).
We will not be allowed to recover $183 million net present value (in
1999 dollars) of the above amounts. The 1999 Settlement Agreement
provides that we will have the opportunity to recover $350 million net
present value (in 1999 dollars) through a competitive transition
charge that will remain in effect through December 31, 2004, at which
time it will terminate. The costs subject to recovery under the
adjustment clause described above will be decreased or increased by
any over/under-recovery due to sales volume variances.
o 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, 67% of our
costs to accomplish the required transfer of generation assets to an
affiliate. However, as noted above and discussed in greater detail
below, in 2002 the ACC unilaterally modified this aspect of the 1999
Settlement Agreement by issuing an order preventing us from
transferring our generation assets.
10
RETAIL ELECTRIC COMPETITION RULES
The Rules approved by the ACC included the following major provisions:
o They apply to virtually all Arizona electric utilities regulated by
the ACC, including us.
o Effective January 1, 2001, retail access became available to all of
our retail electricity customers.
o 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.
o Affected utilities must file ACC tariffs that unbundle rates for
noncompetitive services.
o The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
o 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, in 2002 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
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.
That appeal is still pending. In a similar appeal concerning the issuance of
11
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.
See "General Rate Case and Retail Rate Adjustment Mechanisms" below for a
discussion of retail rate adjustment mechanisms that were the subject of ACC
hearings in March 2003.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order, in which the ACC,
among other things:
o 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
o unilaterally modified the 1999 Settlement Agreement, which authorized
the transfer of our generating assets, and directed us to cancel our
activities to transfer our generation assets to Pinnacle West Energy.
On November 15, 2002, we filed appeals of the Track A Order in the Maricopa
County, Arizona Superior Court and in the Arizona Court of Appeals. ARIZONA
PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, CV 2002-0222 32.
ARIZONA PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, 1CA CC
02-0002. On December 13, 2002, we and the ACC staff agreed to principles for
resolving certain issues raised by us in our appeals of the Track A Order. We
and the ACC are the only parties to the Track A Order appeals. The major
provisions of this document include, among other things, the following:
12
o The parties agreed that it would be appropriate for the ACC to
consider the following matters in our upcoming general rate case,
anticipated to be filed before June 30, 2003:
o the generating assets to be included in our rate base, including
the question of whether certain power plants currently owned by
Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
Phoenix Units 4 and 5 and Saguaro Unit 3) should be included in
our rate base;
o the appropriate treatment of the $234 million pretax asset
write-off agreed to by us as part of the 1999 Settlement
Agreement; and
o the appropriate treatment of costs incurred by us in preparation
for the previously anticipated transfer of generation assets to
Pinnacle West Energy.
o Upon the ACC's issuance of a final decision that is no longer subject
to appeal approving our request to provide $500 million of financing
or credit support to Pinnacle West Energy or Pinnacle West, with
appropriate conditions, our appeals of the Track A Order would be
limited to the issues described in the preceding bullet points, each
of which would be presented to the ACC for consideration prior to any
final judicial resolution. As noted below, the ACC issued the
Financing Order on April 4, 2003. The Financing Order is final and no
longer subject to appeal. As a result, our appeals of the Track A
Order will be limited to the issues described in the preceding bullet
points.
On February 21, 2003, a Notice of Claim was filed with the ACC and the
Arizona Attorney General on behalf of Pinnacle West, Pinnacle West Energy and us
to preserve their and our rights relating to the Track A Order. As of April 22,
2003, the Notice of Claim was deemed denied with respect to the ACC and the
Arizona Attorney General, and Pinnacle West, Pinnacle West Energy and we may now
pursue the claim in court.
TRACK B ORDER
On March 14, 2003, the ACC issued the Track B Order, which requires us to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, we will be required to solicit competitive
bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of
energy, or approximately 20% of our total retail energy requirements. The bid
amounts are expected to increase in 2004 and 2005 based largely on growth in our
retail load and our retail energy sales. The Track B Order also confirmed that
it was "not intended to change the current rate base status of [APS'] existing
assets."
The order recognizes our right to reject any bids that are unreasonable,
uneconomical or unreliable. The Track B procurement process will involve the ACC
Staff and an independent monitor. The Track B Order also contains requirements
relating to standards of conduct between us and any of our affiliates that may
participate in the competitive solicitation, requires that we treat bidders in a
non-discriminatory manner and requires us to file a protocol regarding
short-term and emergency procurements. The order permits the provision of
13
corporate oversight, support and governance as long as such activities do not
favor Pinnacle West Energy in the procurement process or provide Pinnacle West
Energy with our confidential bidding information that is not available to other
bidders. The order directs us to evaluate bids on cost, reliability and
reasonableness. The decision requires bidders to allow the ACC to inspect their
plants and requires assurances of appropriate competitive market conduct from
senior officers of such bidders. Following the solicitation, we will prepare a
report evaluating environmental issues relating to the procurement and a series
of workshops on environmental risk management will be commenced thereafter.
We issued requests for proposals in March 2003 and by May 6, 2003, we
entered into contracts to meet all or a portion of our requirements for the
years 2003 through 2006 as follows.
(1) Pinnacle West Energy agreed to provide 1,700 MW in July through
September of 2003 and in June through September of 2004, 2005 and
2006, by means of a unit contingent contract.
(2) PPL EnergyPlus, LLC agreed to provide 112 MW in July through September
of 2003 and 150 MW in June through September of 2004 and 2005, by
means of a unit contingent contract.
(3) Panda Gila River LP agreed to provide 450 MW in October of 2003 and
2004 and May of 2004 and 2005, and 225 MW from November 2003 through
April 2004 and from November 2004 through April 2005, by means of firm
call options.
ACC FINANCING ORDERS
On April 4, 2003, the ACC issued the Financing Order authorizing us to lend
up to $500 million to Pinnacle West Energy, guarantee up to $500 million of
Pinnacle West Energy debt, or a combination of both, not to exceed $500 million
in the aggregate (the "APS Loan"), subject to the following principal
conditions:
o any debt issued by us pursuant to the order must be unsecured;
o the APS Loan must be callable and secured by certain Pinnacle West
Energy assets;
o the APS Loan must bear interest at a rate equal to 264 basis points
above the interest rate on our debt that could be issued and sold on
equivalent terms (including, but not limited to, maturity and
security);
o the 264 basis points referred to in the previous bullet point will be
capitalized as a deferred credit and used to offset retail rates in
the future, with the deferred credit balance bearing an interest rate
of six percent per annum;
14
o the APS Loan must have a maturity date of not more than four years,
unless otherwise ordered by the ACC;
o any demonstrable increase in our cost of capital as a result of the
transaction (such as from a decline in bond rating) will be excluded
from future rate cases;
o we must maintain a common equity ratio of at least forty percent and
may not pay common dividends if such payment would reduce our common
equity ratio below that threshold, unless otherwise waived by the ACC.
The ACC will process any waiver request within sixty days, and for
this sixty-day period this condition will be suspended. However, this
condition, which will continue indefinitely, will not be permanently
waived without an order of the ACC; and
o certain waivers of the ACC's affiliated interest rules previously
granted to us and our affiliates will be temporarily withdrawn and,
during the term of the APS Loan, neither Pinnacle West nor Pinnacle
West Energy may reorganize or restructure, acquire or divest assets,
or form, buy or sell affiliates (each, a "Covered Transaction"), or
pledge or otherwise encumber the Pinnacle West Energy assets without
prior ACC approval, except that the foregoing restrictions will not
apply to the following categories of Covered Transactions:
o Covered Transactions less than $100 million, measured on a
cumulative basis over the calendar year in which the Covered
Transactions are made;
o Covered Transactions by SunCor of less than $300 million through
2005, consistent with SunCor's anticipated accelerated asset
sales activity during those years;
o Covered Transactions related to the payment of ongoing
construction costs for Pinnacle West Energy's (a) West Phoenix
Unit 5, located in Phoenix, with an expected commercial operation
date in mid-2003, and (b) Silverhawk plant, located near Las
Vegas, with an expected commercial operation date in mid-2004;
and
o Covered Transactions related to the sale of 25% of the Silverhawk
plant to SNWA if SNWA exercises its existing purchase option to
do so.
The ACC also ordered the ACC staff to conduct an inquiry into our and our
affiliates' compliance with the retail electric competition and related rules
and decisions.
No party filed an application for reconsideration of the Financing Order.
As a result, the Financing Order is final and not subject to appeal.
On May 12, 2003, we issued $500 million of debt pursuant to the Financing
Order and made a $500 million loan to Pinnacle West Energy. See Note 4.
15
On November 22, 2002, the ACC issued an order (the "Interim Financing
Order") approving our request 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,
subject to certain conditions.
GENERAL RATE CASE AND RETAIL RATE ADJUSTMENT MECHANISMS
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
we will file a general rate case with the ACC. In this rate case, we will update
our cost of service and rate design. In addition, we expect to seek:
o rate base treatment of certain power plants currently owned by
Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
Phoenix Units 4 and 5 and Saguaro Unit 3);
o recovery of the $234 million pretax asset write-off recorded by us as
part of the 1999 Settlement Agreement ($140 million extraordinary
charge recorded on the 1999 Statement of Income); and
o recovery of costs incurred by us in preparation for the previously
required transfer of generation assets to Pinnacle West Energy.
The general rate case will also address the implementation of rate
adjustment mechanisms that were the subject of ACC hearings in April 2003. The
rate adjustment mechanisms, which were authorized as a result of the 1999
Settlement Agreement, would allow us to recover several types of costs, the most
significant of which are power supply costs (fuel and purchased power costs) and
costs associated with complying with the Rules. We assume that the ACC will make
a decision in this general rate case by the end of 2004.
FEDERAL
In July 2002, 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 FERC has adopted a price cap of $250 per MWh for the period
subsequent to October 31, 2002. Sales at prices above the cap must be justified
and are subject to potential refund.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for
Standard Market Design for wholesale electric markets. Voluminous comments and
reply comments were filed on virtually every aspect of the proposed rule. On
April 28, 2003, the FERC issued an additional white paper on the proposed
Standard Market Design. The white paper makes several changes to the proposed
Standard Market Design, including a greater emphasis on flexibility for regional
needs. The FERC invited comments on the white paper, but has not yet set a due
date for filing comments. 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 or any modifications proposed in the comments.
16
GENERAL
The regulatory developments and legal challenges to the Rules discussed in
this Note have raised considerable uncertainty about the status and pace of
retail 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 providing 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 $300 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 on our interest in
the three Palo Verde units, our maximum potential assessment per incident for
all three units is approximately $77 million, with an annual payment limitation
of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
7. Business Segments
We have two principal business segments (determined by services and the
regulatory environment):
o our regulated electricity segment, which consists of regulated
traditional retail and wholesale electricity businesses and related
activities, and includes electricity generation, transmission and
distribution; and
o our marketing and trading segment, which consists of our competitive
energy business activities, including wholesale marketing and trading.
See Note 18 for information about the transfers of the marketing and
trading division and more information regarding our marketing and
trading activities.
17
Financial data for our business segments follows (dollars in millions):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2003 2002 2003 2002
------ ------ ------ ------
Operating Revenues:
Regulated electricity $ 387 $ 384 $2,063 $2,533
Marketing and trading 92 10 115 313
------ ------ ------ ------
Total $ 479 $ 394 $2,178 $2,846
====== ====== ====== ======
Income Before Accounting Change:
Regulated electricity $ 13 $ 31 $ 179 $ 166
Marketing and trading 3 1 4 82
------ ------ ------ ------
Total $ 16 $ 32 $ 183 $ 248
====== ====== ====== ======
8. Accounting Matters
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This statement amends and
clarifies financial accounting and reporting for derivative instruments and for
hedging activities under SFAS No. 133. The provisions of SFAS No. 149 that
relate to previously issued SFAS No. 133 derivatives implementation guidance
should continue to be applied in accordance with the effective dates of the
original implementation guidance. In general, other provisions are applied
prospectively to contracts entered into or modified after June 30, 2003, and for
hedging relationships designated after June 30, 2003. We are currently
evaluating the impacts of the new standard on our financial statements.
In November 2002, the EITF reached a consensus on EITF 00-21, "Revenue
Arrangements with Multiple Deliverables." EITF 00-21 addresses certain aspects
of the accounting by a vendor for arrangements under which it will perform
multiple revenue-generating activities. EITF 00-21 specifically addresses how to
determine whether an arrangement has identifiable, separable revenue-generating
activities. EITF 00-21 does not address when the criteria for revenue
recognition are met or provide guidance on the appropriate revenue recognition
convention. EITF 00-21 is effective for revenue arrangements entered into after
July 1, 2003. We are currently evaluating the impacts of this new guidance, but
we do not believe it will have a material impact on our financial statements.
In 2001, the American Institute of Certified Public Accountants (AICPA)
issued an exposure draft of a proposed Statement of Position (SOP), "Accounting
for Certain Costs Related to Property, Plant, and Equipment." This proposed SOP
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. In November 2002, the AICPA announced they would
no longer issue general purpose SOPs. In February 2003, the FASB determined that
18
the AICPA should continue their deliberations on certain aspects of the proposed
SOP. We are waiting for further guidance from the FASB and the AICPA on the
timing of the final guidance.
See the following Notes for other new accounting standards:
o Note 9 for a new interpretation (FIN No. 46) related to VIEs;
o Note 10 for a new EITF issue (EITF 02-3) related to accounting for
energy trading contracts;
o Note 13 for a new accounting standard (SFAS No. 143) on asset
retirement obligations;
o Note 15 for a new accounting standard (SFAS No. 148) on stock-based
compensation; and
o Note 17 for a new interpretation (FIN No. 45) on guarantees.
9. Variable Interest Entities
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 requires that we consolidate a VIE if we have a
majority of the risk of loss from the VIE's activities or we are entitled to
receive a majority of the VIE's residual returns or both. A VIE is a
corporation, partnership, trust or any other legal structure that either does
not have equity investors with voting rights or has equity investors that do not
provide sufficient financial resources for the entity to support its activities.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.
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. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to
consolidate the Palo Verde SPEs. However, we continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.
We are exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that we do not consider to be reasonably
likely to occur. Under certain circumstances (for example, the NRC issuing
specified violation orders with respect to Palo Verde or the occurrence of
specified nuclear events), we would be required to assume the debt associated
with the transactions, make specified payments to the equity participants, and
take title to the leased Unit 2 interests, which, if appropriate, may be
required to be written down in value. If such an event had occurred as of March
31, 2003, we would have been required to assume approximately $285 million of
debt and pay the equity participants approximately $200 million.
10. Derivative Instruments and Energy Trading Activities
We are exposed to the impact of market fluctuations in the commodity price
and transportation costs of electricity, natural gas, coal and emissions
allowances. We manage risks associated with these market fluctuations by
utilizing various commodity derivatives, including exchange-traded futures and
19
options and over-the-counter forwards, options and swaps. As part of our 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. In addition, subject to specified risk parameters
monitored by the ERMC, we engage in marketing and trading activities intended to
profit from market price movements.
For the twelve months ended March 31, 2002, we recorded a $12 million after
tax charge in net income and a $8 million after tax credit in common stock
equity (as a component of other comprehensive income (loss)), both as cumulative
effects of a change in accounting for derivatives, as required by SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The charge
primarily resulted from electricity option contracts. The credit resulted from
unrealized gains on cash flow hedges.
We adopted the EITF 02-3 guidance for all contracts in the fourth quarter
of 2002. The impact of this guidance was immaterial to our financial statements.
Our energy trading contracts that are derivatives are accounted for at fair
value under SFAS No. 133. Contracts that do not meet the definition of a
derivative are accounted for on an accrual basis with the associated revenues
and costs recorded at the time the contracted commodities are delivered or
received. Additionally, all gains and losses (realized and unrealized) on energy
trading contracts that qualify as derivatives are included in marketing and
trading segment revenues on the Condensed Statements of Income on a net basis.
Derivative instruments used for non-trading activities are accounted for in
accordance with SFAS No. 133.
EITF 02-3 requires that derivatives held for trading purposes, whether
settled financially or physically, be reported in the income statement on a net
basis. Conversely, all non-trading contracts and derivatives are to be reported
gross on the income statement.
The changes in derivative fair value of our system positions included in
the Condensed Statements of Income for the three and twelve months ended March
31, 2003 and 2002 are comprised of the following (dollars in thousands):
20
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------- --------------------
2003 2002 2003 2002
-------- -------- -------- --------
Gains (losses) on the ineffective portion
of derivatives qualifying for hedge
accounting (a) $ 1,564 $ (111) $ 10,158 $ (3,718)
Losses from the discontinuance of cash flow hedges -- (44) (9,162) (3,561)
Gains (losses) from non-hedge derivatives 5,259 (1,256) (6,130) (7,265)
Prior period mark-to-market losses realized upon
delivery of commodities 10,443 3,813 17,043 23,368
-------- -------- -------- --------
Total pretax gain $ 17,266 $ 2,402 $ 11,909 $ 8,824
======== ======== ======== ========
(a) Time value component of options excluded from assessment of hedge
effectiveness.
As of March 31, 2003, the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is approximately 21 months. During the twelve months ending March 31, 2004, we
estimate that a net loss of $16 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.
The mark-to-market related to our risk management and trading activities
are presented in two categories, consistent with our business segments:
o System - our regulated electricity business segment, which consists of
non-trading derivative instruments that hedge our purchases and sales
of electricity and fuel for our Native Load requirements; and
o Marketing and Trading - our non-regulated, competitive business
segment, which includes both non-trading and trading derivative
instruments.
The following table summarizes our assets and liabilities from risk
management and trading activities at March 31, 2003 and December 31, 2002
(dollars in thousands):
21
March 31, 2003
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
-------- ----------- ----------- ----------- -----------
Mark-to-Market:
Marketing
and Trading $ 5,920 $ 57 $ (1,882) $ (229) $ 3,866
System 82,499 8,205 (86,595) (26,890) (22,781)
Emission
allowances
- at cost -- 20,771 -- -- 20,771
-------- -------- -------- -------- --------
Total $ 88,419 $ 29,033 $(88,477) $(27,119) $ 1,856
======== ======== ======== ======== ========
December 31, 2002
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
-------- ----------- ----------- ----------- -----------
Mark-to-Market:
Marketing
and Trading $ -- $ -- $ -- $ -- $ --
System 39,616 6,971 (59,773) (36,678) (49,864)
Emission
allowances
- at cost -- 24,651 -- -- 24,651
-------- -------- -------- -------- --------
Total $ 39,616 $ 31,622 $(59,773) $(36,678) $(25,213)
======== ======== ======== ======== ========
Cash or collateral required to serve as collateral against our open positions on
energy-related contracts is included in investments and other assets on the
Condensed Balance Sheet. No collateral was provided at March 31, 2003.
Collateral provided was $5 million at December 31, 2002. Collateral held was $3
million at March 31, 2003 and $4 million at December 31, 2002.
22
11. Comprehensive Income
Components of comprehensive income for the three and twelve months ended
March 31, 2003 and 2002, are as follows (dollars in thousands):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------------ ------------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Net income $ 15,933 $ 31,763 $ 183,513 $ 235,399
--------- --------- --------- ---------
Other comprehensive income (loss):
Minimum pension liability
adjustment, net of tax (112) -- (60,633) (966)
Cumulative effect of a change
in accounting for derivatives,
net of tax -- -- -- 7,801
Unrealized gain (loss) on derivative
instruments, net of tax (a) 8,653 24,766 22,651 (74,260)
Reclassification of realized (gain)
loss to income, net of tax (b) (1,921) 542 (1,427) (9,257)
--------- --------- --------- ---------
Total other comprehensive income (loss) 6,620 25,308 (39,409) (76,682)
--------- --------- --------- ---------
Comprehensive income $ 22,553 $ 57,071 $ 144,104 $ 158,717
========= ========= ========= =========
(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.
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 directed
an ALJ to make findings of fact with respect to: (1) the mitigated price in each
hour of the refund period; (2) the amount of refunds owed by each supplier
according to the methodology established in the order; and (3) the amount
currently owed to each supplier (with separate quantities due from each entity)
by the CAISO, the California Power Exchange, the investor-owned utilities and
the State of California.
We were a seller and a purchaser in the California markets at issue, and to
the extent that refunds are ordered, we should be a recipient as well as a payor
of such amounts. On December 12, 2002, the ALJ issued Proposed Findings of Fact
with respect to the refunds. On March 26, 2003, the FERC adopted the great
majority of the proposed findings, revising only the calculation of natural gas
prices for the final determination of mitigated prices in the California
23
markets. Sellers who may actually have paid more for natural gas than the proxy
prices adopted by the FERC have 40 days in which to submit necessary data to the
FERC, after which a technical conference will be held. Finalization of refund
amounts is expected in mid-2003. Subsequent to the foregoing refund decision by
the FERC, the California parties filed a request for rehearing asking the FERC
to expand the time period and transactions covered by the refund proceeding and
provide for approximately $3 billion in additional refunds relating to sales by
all sellers in the California markets. We do not anticipate material changes in
our exposure and still believe, subject to the finalization of the revised proxy
prices, that we will be entitled to a net refund.
On November 20, 2002, the FERC reopened discovery in these proceedings
pursuant to instructions of the United States Court of Appeals for the Ninth
Circuit that the FERC permit parties to offer additional evidence of potential
market manipulation for the period January 1, 2000 through June 20, 2001.
Parties have submitted additional evidence and proposed findings, which the FERC
continues to consider.
The FERC also ordered an evidentiary proceeding to discuss and evaluate
possible refunds for the Pacific Northwest. The FERC required that the record
establish the volume of the transactions, the identification of the net sellers
and net buyers, the price and terms and conditions of the sales contracts and
the extent of potential refunds. On September 24, 2001, an ALJ concluded that
prices in the Pacific Northwest during the period December 25, 2000 through June
20, 2001 were the result of a number of factors in addition to price signals
from the California markets, including the shortage of supply, excess demand,
drought and increased natural gas prices. Under these circumstances, the ALJ
ultimately concluded that the prices in the Pacific Northwest were not
unreasonable or unjust and refunds should not be ordered in this proceeding. On
December 19, 2002, the FERC opened a new discovery period to permit the parties
to offer additional evidence for the period January 1, 2000 through June 20,
2001. Additional evidence has been submitted and a FERC decision on the newly
submitted evidence is expected soon. Based on public comments from the FERC, it
is anticipated that this case will be sent back to the ALJ for further
proceedings on spot market and balance of month transactions.
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.
On March 26, 2003, FERC made public a Final Report on Price Manipulation in
Western Markets, prepared by its Staff and covering spot markets in the West in
2000 and 2001. The report stated that a significant number of entities who
participated in the California markets during 2000 to 2001 time period,
including us, may potentially have been involved in arbitrage transactions that
allegedly violated certain provisions of the ISO tariff. The report also
recommended that the FERC issue an order to show cause why these transactions
did not violate the ISO tariff with potential disgorgement of any unjust
profits. Although we are still attempting to determine and to review the
transactions at issue, we believe that we were not engaged in any such improper
transactions. Based on the information available, it also appears that such
transactions would not have a material adverse impact on our financial position,
results of operations or liquidity.
24
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.
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 the Company, 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 the 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.
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 other 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 Pinnacle West and 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 our charges under the agreement were fully
in accordance with the terms of the agreement. In addition, in testimony filed
25
with the ACC on March 13, 2002, Citizens acknowledged, based on its review, "if
Citizens filed a complaint with FERC, it probably would lose the central issue
in the contract interpretation dispute." We and Citizens terminated the power
service agreement effective July 15, 2001. In replacement of the power service
agreement, Pinnacle West and Citizens entered into a power sale agreement under
which Pinnacle West will supply Citizens with future 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. Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides accounting requirements for the
recognition and measurement of liabilities associated with the retirement of
tangible long-lived assets. The standard requires that these liabilities be
recognized at fair value as incurred and capitalized as part of the related
tangible long-lived assets. Accretion of the liability due to the passage of
time is an operating expense and the capitalized cost is depreciated over the
useful life of the long-lived asset. Prior to January 1, 2003 we accrued asset
retirement obligations over the life of the related asset through depreciation
expense.
We have asset retirement obligations for our Palo Verde nuclear facilities
and certain other generation, transmission and distribution assets. The Palo
Verde asset retirement obligation primarily relates to final plant
decommissioning. This obligation is based on the NRC's requirements for disposal
of radiated property or plant and agreements we reached with the ACC for final
decommissioning of the plant. The non-nuclear generation asset retirement
obligations primarily relate to requirements for removing portions of those
plants at the end of the plant life or lease term. Some of our transmission and
distribution assets have asset retirement obligations because they are subject
to right of way and easement agreements that require final removal. These
agreements have a history of uninterrupted renewal that we expect will continue
for the foreseeable future. As a result, we cannot reasonably estimate the fair
value of the asset retirement obligation related to such distribution and
transmission assets.
On January 1, 2003, we recorded a liability of $219 million for our asset
retirement obligations, including the accretion impacts; a $67 million increase
in the carrying amount of the associated assets; and a net reduction of $192
million in accumulated depreciation related primarily to the reversal of
previously recorded accumulated decommissioning and other removal costs related
to these obligations. Additionally, we recorded a net regulatory liability of
$40 million for the asset retirement obligations related to our regulated
assets. This regulatory liability represents the difference between the amount
currently being recovered in regulated rates and the amount calculated under
SFAS No. 143. We believe we can recover in regulated rates the transition costs
and ongoing current period costs calculated in accordance with SFAS No. 143. The
adoption of SFAS No. 143 did not have a material impact on our net income for
the quarter ended March 31, 2003.
In accordance with SFAS No. 71, we will continue to accrue for removal
costs for our regulated assets, even if there is no legal obligation for
removal. At March 31, 2003, accumulated depreciation shown on our Condensed
26
Balance Sheets included approximately $360 million of estimated future removal
costs that are not considered legal obligations.
The following schedule shows the change in our asset retirement obligations
during the three-month period ended March 31, 2003 (dollars in millions):
Balance at January 1, 2003 $ 219
Changes attributable to:
Liabilities incurred --
Liabilities settled --
Accretion expense 4
Estimated cash flow revisions --
-----
Balance at March 31, 2003 $ 223
=====
The following schedule shows the change in our pro forma liability for the
periods ended December 31, 2002 and 2001, as if we had recorded an asset
retirement obligation based on the guidance in SFAS No. 143 (dollars in
millions):
2002 2001
----- -----
Balance at beginning of year $ 204 $ 190
Accretion expense 15 14
----- -----
Balance at end of year $ 219 $ 204
===== =====
The pro forma effects on net income for 2002 and 2001 are immaterial.
To fund the costs we expect to incur to decommission the plant, we
established external decommissioning trusts in accordance with NRC regulations.
We invest the trust funds primarily in fixed income securities and domestic
stock and classify them as available for sale. The following table shows the
cost and fair value of our nuclear decommissioning trust fund assets which are
reported in investments and other assets on the Condensed Balance Sheets at
March 31, 2003 and December 31, 2002 (dollars in millions):
March 31, December 31,
2003 2002
----- -----
Trust fund assets - at cost
Fixed income securities $ 115 $ 113
Domestic stock 70 68
----- -----
Total $ 185 $ 181
===== =====
Trust fund assets - at fair value
Fixed income securities $ 124 $ 117
Domestic stock 80 77
----- -----
Total $ 204 $ 194
===== =====
27
14. Intangible Assets
The Company's gross intangible assets (which are primarily software) were
$218 million at March 31, 2003 and $193 million at December 31, 2002. The
related accumulated amortization was $107 million at March 31, 2003 and $100
million at December 31, 2002. Amortization expense for the three months ended
March 31 was $6 million in 2003 and $4 million in 2002. Amortization expense for
the twelve months ended March 31 was $20 million in 2003 and 2002. Estimated
amortization expense on existing intangible assets over the next five years is
$24 million in 2003, $23 million in 2004, $22 million in 2005, $20 million in
2006 and $14 million in 2007.
15. Stock-Based Compensation
In 2002, we began applying the fair value method of accounting for
stock-based compensation, as provided for in SFAS No. 123, "Accounting for
Stock-Based Compensation." In accordance with the transition requirements of
SFAS No. 123, as amended by SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure," we applied the fair value method
prospectively, beginning with 2002 stock grants. In prior years, we recognized
stock compensation expense based on the intrinsic value method allowed in
Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued
to Employees."
The following chart compares our net income and stock compensation expense
to what those items would have been if we had recorded stock compensation
expense based on the fair value method for all stock grants through March 31,
2003 (dollars in thousands):
Three Months Ended Twelve Months Ended
March 31, March 31,
--------------------- ---------------------
2003 2002 2003 2002
-------- -------- -------- --------
Net Income:
As reported $ 15,933 $ 31,763 $183,513 $235,399
Pro forma (fair value method) 15,744 31,507 182,618 233,956
Stock compensation expense (net of tax):
As reported 96 -- 296 --
Pro forma (fair value method) 189 256 895 1,443
16. Other Income and Other Expense
The following table provides detail of other income and other expense for
the three and twelve months ended March 31, 2003 and 2002 (dollars in
thousands):
28
Three Months Ended Twelve Months Ended
March 31, March 31,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
Other income:
Environmental insurance recovery $ -- $ -- $ -- $ 12,350
Investment gains - net 904 1,787 -- --
Interest income 433 944 2,944 5,616
Miscellaneous 452 421 1,725 2,878
-------- -------- -------- --------
Total other income $ 1,789 $ 3,152 $ 4,669 $ 20,844
======== ======== ======== ========
Other expense:
Investment losses - net $ -- $ -- $ (2,013) $ (1,713)
Non-operating costs (a) (2,607) (3,454) (15,577) (14,212)
Miscellaneous (235) (357) (1,662) (2,755)
-------- -------- -------- --------
Total other expense $ (2,842) $ (3,811) $(19,252) $(18,680)
======== ======== ======== ========
(a) As defined by the FERC, includes below-the-line non-operating utility costs
(primarily community relations and environmental compliance).
17. Guarantees
On January 1, 2003 we adopted FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." FIN No. 45 elaborates on the disclosures to be made by
a guarantor in its financial statements about its obligations under certain
guarantees. It also clarifies that a guarantor is required to recognize, at
inception of a guarantee, a liability for the fair value of the obligation
undertaken in issuing the guarantee. The disclosure provisions are effective for
the year ended December 31, 2002. The initial recognition and measurement
provisions of FIN No. 45 are effective on a prospective basis to guarantees
issued or modified after December 31, 2002. We had no guarantees outstanding at
March 31, 2003.
We have entered into various agreements that require letters of credit for
financial assurance purposes. At March 31, 2003, approximately $200 million of
letters of credit were outstanding to support existing pollution control bonds
of approximately $200 million. The letters of credit are available to fund the
payment of principal and interest of such debt obligations. These letters of
credit have expiration dates in 2003. We have also entered into approximately
$113 million of letters of credit to support certain equity lessors in the Palo
Verde sale-leaseback transactions. These letters of credit expire in 2005.
Additionally, we have approximately $5 million of letters of credit related to
counterparty collateral requirements and approximately $5 million of letters of
credit related to workers' compensation expiring in 2003. We intend to provide
from either existing or new facilities for the extension, renewal or
substitution of the letters of credit to the extent required.
In conjunction with our financing agreements, including our sale-leaseback
transactions, we generally provide indemnifications relating to liabilities
arising from or related to the agreements, except with certain limited
exceptions depending on the particular agreement. We have also provided
indemnifications to the equity participants and other parties in the Palo Verde
sale-leaseback transactions with respect to certain tax matters. Generally, a
maximum obligation is not explicitly stated in the indemnification and
therefore, the overall maximum amount of the obligation under such
29
indemnifications cannot be reasonably estimated. Based on historical experience
and evaluation of the specific indemnities, we do not believe that any material
loss related to such indemnifications is likely and therefore no related
liability has been recorded.
18. Related Party Transactions
During 2001, we transferred most of our marketing and trading activities to
Pinnacle West. In the first quarter of 2003, Pinnacle West moved the marketing
and trading division back to us for future marketing and trading activities
(existing wholesale contracts will remain at Pinnacle West) as a result of the
ACC's Track A Order prohibiting the previously required transfer of our
generating assets to Pinnacle West Energy (see Note 5). 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 Statements of
Income and Condensed Balance Sheets related to transactions with affiliated
companies (dollars in millions):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2003 2002 2003 2002
------ ------ ------ ------
Electric operating revenues:
Pinnacle West -
marketing and trading $ 1 $ 17 $ 69 $ 67
APS Energy Services 1 -- 1 10
------ ------ ------ ------
Total $ 2 $ 17 $ 70 $ 77
====== ====== ====== ======
Purchased power and fuel costs:
Pinnacle West -
marketing and trading $ -- $ 6 $ 129 $ 44
Pinnacle West Energy(a) 14 -- 14 14
APS Energy Services 1 -- 1 --
------ ------ ------ ------
Total $ 15 $ 6 $ 144 $ 58
====== ====== ====== ======
(a) Includes a credit of $6 million related to mark-to-market on an
intercompany contract in both the three and twelve months ended March 31,
2003, which is expected to be realized in the second quarter of 2003.
30
As of As of
March 31, 2003 December 31, 2002
-------------- -----------------
Net intercompany
receivables/(payables):
Pinnacle West - marketing
and trading $ 72 $ 135
Pinnacle West 22 (1)
Pinnacle West Energy (17) (1)
----- -----
Total $ 77 $ 133
===== =====
Electric revenues include sales of electricity to affiliated companies at
contract prices. Purchased power includes purchases of electricity from
affiliated companies at contract prices. Intercompany receivables primarily
include the amounts related to the transfer of marketing and trading activities
discussed above and intercompany sales of electricity. Intercompany payables
primarily include amounts related to the purchase of electricity. Intercompany
receivables and payables are generally settled on a current basis in cash.
31
ARIZONA PUBLIC SERVICE COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
INTRODUCTION
In this Item, we explain the results of operations, general financial
condition and outlook including:
o the changes in our earnings for the three and twelve months ended
March 31, 2003 and 2002;
o our capital needs, liquidity and capital resources;
o our business outlook and major factors that affect our financial
outlook (see Note 5 and "Business Outlook" below); and
o our management of market risks.
We suggest this section be read along with the 2002 10-K. Throughout this
Item, 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 either retail or 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 delivered through a distribution system that
we own. We also generate, sell and deliver electricity to wholesale customers in
the western United States. Our marketing and trading division sells, in the
wholesale market, our and Pinnacle West Energy's generation output that is not
needed for our Native Load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. We do not distribute any
products. Pinnacle West owns all of our outstanding common stock.
BUSINESS SEGMENTS
We have two principal business segments (determined by services and the
regulatory environment):
o our regulated electricity segment, which consists of regulated
traditional retail and wholesale electricity businesses and related
activities, and includes electricity generation, transmission and
distribution; and
o our marketing and trading segment, which consists of our competitive
energy business activities, including wholesale marketing and trading.
See Note 18 for information about the transfers of the marketing and
32
trading division and more information regarding our marketing and
trading activities.
The following table summarizes net income by business segment for the three
and twelve months ended March 31, 2003 and the comparable prior year periods
(dollars in millions):
Three Months Ended Twelve Months Ended
March 31, March 31,
--------------- ---------------
2003 2002 2003 2002
----- ----- ----- -----
Regulated electricity (a) $ 13 $ 31 $ 179 $ 166
Marketing and trading 3 1 4 82
----- ----- ----- -----
Income before accounting
change 16 32 183 248
Cumulative effect of change
in accounting - net of tax (b) -- -- -- (12)
----- ----- ----- -----
Net income $ 16 $ 32 $ 183 $ 236
===== ===== ===== =====
(a) Consistent with our October 2001 ACC filing, we entered into agreements
with our affiliates to buy power through June 2003. The agreements reflect
a price based on the fully-dispatchable dedication of the Pinnacle West
Energy generating assets to our Native Load customers. See "Track B Order"
in Note 5 for information about our competitive solicitation process for
certain estimated capacity and energy requirements beginning July 1, 2003.
(b) We recorded a $12 million after tax charge in June 2001 for the cumulative
effect of a change in accounting for derivatives related to the adoption of
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities."
RESULTS OF OPERATIONS
GENERAL
Throughout the following explanations of our results of operations, we
refer to "gross margin." With respect to our regulated electricity segment and
our marketing and trading segment, gross margin refers to electric operating
revenues less purchased power and fuel costs.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2003 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 2002
Our net income for the three months ended March 31, 2003 was $16 million
compared with $32 million for the prior year. The period-to-period decrease of
$16 million was primarily due to:
33
o higher operating costs primarily related to the timing of power plant
overhauls and higher pension and other postretirement benefit costs
($7 million, after tax);
o decreased earnings contributions from our regulated electricity
activities, reflecting retail electricity price decreases, the effects
of milder weather and higher replacement power costs for plant
outages, partially offset by retail customer growth, ($11 million,
after tax); and
o other miscellaneous factors ($1 million, after tax).
The above decreases were partially offset by higher earnings contributions
from our marketing and trading activities, reflecting increases in generation
sales other than Native Load ($3 million, after tax).
For additional details, see the following discussion.
34
The major factors that increased (decreased) net income were as follows
(dollars in millions):
Increase
(Decrease)
----------
Regulated electricity segment gross margin:
Increased purchased power and fuel costs due to higher hedged gas
and power prices $ (28)
Higher retail sales volumes due to customer growth, excluding
weather effects 7
Change in mark-to-market for hedged natural gas and purchased
power costs for future delivery 18
Effects of milder weather on retail sales (6)
Retail electricity price reductions effective July 1, 2002 (5)
Higher replacement power costs from plant outages due to higher
market prices and more unplanned outages (4)
------
Net decrease in regulated electricity segment gross margin (18)
------
Marketing and trading segment gross margin:
Increase in generation sales other than Native Load due to
higher sales volumes, partially offset by lower unit margins 5
Lower realized wholesale margins net of related mark-to-market
reversals due to lower prices, partially offset by higher volumes 1
Lower mark-to-market gains for future delivery due to lower market
liquidity and higher price volatility (1)
------
Net increase in marketing and trading segment gross margin 5
------
Net decrease in regulated electricity and marketing and trading segments'
gross margins (13)
Higher operations and maintenance expense related to increased operating
costs related to the timing of power plant overhauls and increased
pension and other postretirement benefit costs (13)
------
Net decrease in income before income taxes (26)
Lower income taxes primarily due to lower income 10
------
Net decrease in net income $ (16)
======
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $3 million higher in the three months
ended March 31, 2003, compared with the same period in the prior year as a
result of:
o increased revenues related to traditional wholesale sales as a result
of higher sales volumes and higher prices ($1 million);
o decreased retail revenues related to milder weather ($11 million);
o increased retail revenues related to customer growth, excluding
weather effects ($14 million);
o decreased retail revenues related to a reduction in retail electricity
prices ($5 million); and
o other miscellaneous factors ($4 million, net increase).
35
Regulated electricity segment purchased power and fuel costs were $21
million higher in the three months ended March 31, 2003, compared with the same
period in the prior year as a result of:
o increased costs related to traditional wholesale sales as a result of
higher sales volumes and higher prices ($1 million);
o increased purchased power and fuel costs due to higher hedged gas and
power prices, net of mark-to-market reversals ($10 million);
o decreased costs related to the effects of milder weather on retail
sales ($5 million);
o increased costs related to retail sales growth, excluding weather
effects ($7 million);
o increased replacement power costs for power plant outages due to
higher market prices and more unplanned outages ($4 million); and
o other miscellaneous factors ($4 million, net increase).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $81 million higher in the three
months ended March 31, 2003, compared with the same period in the prior year as
a result of:
o increased revenues from generation sales other than Native Load
primarily due to higher prices and higher sales volumes ($37 million);
o higher realized wholesale revenues net of related mark-to-market
reversals primarily due to higher volumes ($46 million); and
o lower mark-to-market gains for future delivery primarily as a result
of lower market liquidity and higher price volatility ($2 million).
Marketing and trading segment purchased power and fuel costs were $76
million higher in the three months ended March 31, 2003, compared to the same
period in the prior year as a result of:
o increased fuel costs related to generation sales other than Native
Load primarily because of higher natural gas prices and higher sales
volumes ($32 million);
o increased purchased power costs related to other realized marketing
activities in the current period primarily due to higher volumes and
higher prices ($45 million);
o change in mark-to-market fuel costs for future delivery ($1 million
decrease).
OTHER INCOME STATEMENT ITEMS
The increase in operations and maintenance expense of $13 million was due
to increased operating costs related to the timing of power plant overhauls,
increased pension and other postretirement benefit costs and other costs.
36
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2003 COMPARED WITH
TWELVE-MONTH PERIOD ENDED MARCH 31, 2002
Our net income for the twelve months ended March 31, 2003 was $183 million
compared with $236 million for the prior year. Included in the 2002 period was a
$12 million after tax charge for the cumulative effect of a change in accounting
for derivatives, as required by SFAS No. 133.
Our income before accounting change for the twelve months ended March 31,
2003 was $183 million compared with $248 million for the prior year. The
period-to-period decrease of $65 million was primarily due to:
o lower earnings contributions from our marketing and trading
activities, reflecting lower liquidity and lower price volatility in
the wholesale power markets in the western United States ($77 million,
after tax);
o higher operations and maintenance expenses primarily related to the
2002 severance costs and higher benefit costs ($29 million, after
tax);
o lower other income primarily due to an insurance recovery of
environmental remediation costs in 2002 ($10 million, after tax);
o higher property taxes due to higher plant balances ($4 million, after
tax); and
o higher interest expense primarily due to higher debt balances ($3
million, after tax).
The above decreases were partially offset by:
o increased earnings contributions from our regulated electricity
activities, reflecting lower replacement power costs for power plant
outages, retail customer growth and higher average usage per customer
and lower purchased power costs related to the 2001 generation
reliability program (the addition of generating capability to enhance
reliability for the summer of 2001), partially offset by the effects
of milder weather, and retail electricity price decreases ($48
million, after tax); and
o lower depreciation and amortization expense primarily related to lower
regulatory asset amortization, in accordance with the 1999 Settlement
Agreement ($10 million, after tax).
For additional details, see the following discussion.
37
The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
Increase
(Decrease)
----------
Regulated electricity segment gross margin:
Lower replacement power costs from plant outages due to lower
market prices and fewer unplanned outages $ 74
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 43
Effects of milder weather on retail sales (40)
Retail electricity price reductions effective July 1, 2001 and July 1,
2002 (27)
Change in mark-to-market for hedged natural gas and purchased
power costs for future delivery 15
Changes related to purchased power contracts with Enron and its
affiliates in fourth quarter 2001 13
Increased purchased power and fuel costs due to higher hedged gas
and power prices (24)
Lower purchased power and fuel costs related to the 2001 reliability
program 30
Miscellaneous factors, net (5)
------
Net increase in regulated electricity segment gross margin 79
------
Marketing and trading segment gross margin:
Decrease in generation sales other than Native Load due to
lower market prices, partially offset by higher sales volumes (25)
Lower realized wholesale margins net of related mark-to-market
reversals due to lower prices, partially offset by higher volumes (24)
Lower mark-to-market gains for future delivery due to lower market
liquidity and lower price volatility (79)
------
Net decrease in marketing and trading segment gross margin (128)
------
Net decrease in regulated electricity and marketing and trading segments'
gross margins (49)
Higher operations and maintenance expense related primarily to 2002
severance costs of approximately $34 million, partially offset by lower
generation reliability costs (48)
Lower depreciation primarily related to lower regulatory asset amortization 17
Higher taxes other than income taxes due to increased property taxes on
higher property balances (7)
Lower other income primarily due to a 2001 insurance recovery of
environmental remediation costs (16)
Higher net interest expense primarily due to higher debt balances and lower
capitalized interest (6)
Other miscellaneous factors, net (1)
------
Net decrease in income before income taxes (110)
Lower income taxes primarily due to lower income 45
------
Net decrease in income before accounting change $ (65)
======
38
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $470 million lower in the twelve months
ended March 31, 2003, compared with the same period in the prior year as a
result of:
o decreased revenues related to traditional wholesale sales as a result
of lower prices and lower sales volumes ($39 million);
o decreased revenues related to retail load hedge management wholesale
sales, primarily as a result of lower prices and lower sales volumes
($421 million);
o decreased retail revenues related to milder weather ($63 million);
o increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($67 million);
o decreased retail revenues related to reductions in retail electricity
prices ($27 million); and
o other miscellaneous factors ($13 million, net increase).
Regulated electricity segment purchased power and fuel costs were $549
million lower in the twelve months ended March 31, 2003, compared with the same
period in the prior year as a result of:
o decreased costs related to traditional wholesale sales as a result of
lower prices and lower sales volumes ($39 million);
o decreased costs related to retail load hedge management wholesale
sales, primarily as a result of lower prices and lower sales volumes,
partially offset by higher hedged purchased power and fuel costs ($397
million);
o decrease in mark-to-market for hedged natural gas and purchased power
costs for future delivery ($15 million);
o decreased costs related to the effects of milder weather on retail
sales ($23 million);
o increased costs related to retail sales growth, excluding weather
effects ($24 million);
o decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($74 million);
o charges in 2001 related to purchased power contracts with Enron and
its affiliates ($13 million, net decrease);
o lower purchased power costs related to 2001 generation reliability
program ($30 million); and
o miscellaneous factors ($18 million, net increase).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $198 million lower in the
twelve months ended March 31, 2003, compared with the same period in the prior
year as a result of:
39
o decreased revenues from generation sales other than Native Load
primarily due to higher sales volumes, partially offset by lower
market prices ($11 million);
o lower realized wholesale revenues net of related mark-to-market
reversals primarily due to lower prices partially offset by higher
volumes ($111 million); and
o lower mark-to-market gains for future delivery primarily as a result
of lower market liquidity and lower price volatility ($76 million).
Marketing and trading segment purchased power and fuel costs were $70
million lower in the twelve months ended March 31, 2003, compared to the same
period in the prior year as a result of:
o increased fuel costs related to generation sales other than Native
Load primarily because of higher sales volumes ($14 million);
o decreased purchased power costs related to other realized marketing
activities in the current period primarily due to lower prices
partially offset by higher volumes ($87 million); and
o change in mark-to-market fuel costs for future delivery ($3 million
increase).
OTHER INCOME STATEMENT ITEMS
The increase in operations and maintenance expense of $48 million was due
to severance costs of $34 million related to a 2002 voluntary workforce
reduction, increased pension and other postretirement benefit costs of $9
million and other costs of $5 million.
The decrease in depreciation and amortization expense of $17 million
primarily related to lower regulatory amortization, in accordance with the 1999
Settlement Agreement.
The increase in taxes other than income taxes of $7 million is primarily
due to increased property taxes on higher property balances.
Other income decreased $16 million primarily due to an insurance recovery
recorded in 2001 related to environmental remediation costs and other costs.
Net interest expense increased $6 million primarily because of higher debt
balances.
40
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the
three months ended March 31, 2003 and estimated capital expenditures for the
next three years (dollars in millions):
Three Months Estimated
Ended March 31, ------------------------------
2003 2003 2004 2005
---- ---- ---- ----
Delivery $ 73 $273 $275 $329
Generation (a) 35 123 99 164
Other 1 5 5 5
---- ---- ---- ----
Total $109 $401 $379 $498
==== ==== ==== ====
(a) As discussed in Note 5 under "General Rate Case and Retail Rate Adjustment
Mechanisms," as part of our 2003 general rate case, we intend to seek rate
base treatment of certain power plants in Arizona currently owned by
Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix
Units 4 and 5 and Saguaro Unit 3).
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 $105 million on major transmission projects
during the 2003 to 2005 time frame, and these amounts are included in "Delivery"
in the table above.
Generation capital expenditures are comprised of various improvements for
our existing fossil and nuclear plants and the replacement of Palo Verde 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. Generation also contains
nuclear fuel expenditures of approximately $30 million annually for 2003 to
2005.
Replacement of the steam generators in Palo Verde Unit 2 is presently
scheduled for completion during the fall outage of 2003. The Palo Verde owners
have approved the manufacture of two additional sets of steam generators. We
expect that these generators will be installed in Units 1 and 3 in the 2005 to
2007 time frame. Our portion of steam generator expenditures for Units 1, 2 and
3 is approximately $145 million, which will be spent from 2003 through 2008. In
2003 through 2005, $94 million of the costs are included in the generation
capital expenditures table above and would be funded with internally-generated
cash or external financings.
41
CAPITAL RESOURCES AND CASH REQUIREMENTS
CONTRACTUAL OBLIGATIONS The following table summarizes actual contractual
requirements for the three months ended March 31, 2003 and estimated contractual
commitments for the next five years and thereafter (dollars in millions):
Actual
------
Three
Months Estimated
Ended -------------------------------------------------------------
March 31, There-
2003 2003 2004 2005 2006 2007 after
------ ------ ------ ------ ------ ------ ------
Long-term debt payments $ -- $ -- $ 205 $ 400 $ 84 $ -- $1,518
Capital lease payments 1 4 3 3 3 2 5
Operating lease payments 2 59 59 59 59 59 456
Purchase power and fuel commitments 53 164 85 28 31 17 162
------ ------ ------ ------ ------ ------ ------
Total contractual commitments $ 56 $ 227 $ 352 $ 490 $ 177 $ 78 $2,141
====== ====== ====== ====== ====== ====== ======
OFF-BALANCE SHEET ARRANGEMENTS
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 requires that we consolidate a VIE if we have a
majority of the risk of loss from the VIE's activities or we are entitled to
receive a majority of the VIE's residual returns or both. A VIE is a
corporation, partnership, trust or any other legal structure that either does
not have equity investors with voting rights or has equity investors that do not
provide sufficient financial resources for the entity to support its activities.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.
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. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to
consolidate the Palo Verde SPEs. However, we continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.
We are exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that we do not consider to be reasonably
likely to occur. Under certain circumstances (for example, the NRC issuing
specified violation orders with respect to Palo Verde or the occurrence of
specified nuclear events), we would be required to assume the debt associated
with the transactions, make specified payments to the equity participants and
take title to the leased Unit 2 interests, which, if appropriate, may be
required to be written down in value. If such an event had occurred as of March
31, 2003, we would have been required to assume approximately $285 million of
debt and pay the equity participants approximately $200 million.
42
CREDIT RATINGS
The ratings of our securities as of May 12, 2003 are shown below and are
considered to be "investment-grade" ratings. The ratings reflect the respective
views of the rating agencies, from which 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. The ratings may be revised or withdrawn
entirely by the rating agencies, if, in their respective judgments,
circumstances so warrant. Any downward revision or withdrawal may adversely
affect the market price of our securities and serve to increase our cost of and
access to capital. All of our credit ratings remain investment grade.
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
OUTLOOK Stable Stable Negative (a)
(a) This rating affects all of the above debt ratings with the exception of our
commercial paper rating.
DEBT PROVISIONS
Our significant debt covenants include a debt-to-total-capitalization ratio
and an interest coverage test. We are in compliance with such covenants and
anticipate that we will continue to meet all the significant covenant
requirement levels. The ratio of debt to total capitalization cannot exceed 65%.
At March 31, 2003, our ratio was approximately 49%. The provisions regarding
interest coverage require a minimum cash coverage of two times the interest
requirements. The coverage is approximately 5 times for our bank agreements and
14 times for our mortgage indenture. 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.
All of our bank agreements contain cross-default provisions that would
result in defaults and the potential acceleration of payment under these
agreements if we were to default under other 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 financial condition or
financial prospects.
43
CAPITAL REQUIREMENTS AND RESOURCES
Our capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. On April 4, 2003, the ACC
issued the Financing Order, which permits us to lend up to $500 million to
Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt,
or a combination of both, not to exceed $500 million in the aggregate. See "ACC
Financing Orders" in Note 5 for additional information. On May 12, 2003, we
issued $500 million of debt as follows: $300 million aggregate principal amount
of our 4.650% Notes due 2015 and $200 million aggregate principal amount of our
5.625% Notes due 2033. Also on May 12, 2003, we made a $500 million loan to
Pinnacle West Energy, and Pinnacle West Energy distributed the net proceeds of
that loan to Pinnacle West to fund Pinnacle West's repayment of a portion of the
debt incurred to finance the construction of the following Pinnacle West Energy
power plants: Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and Saguaro
Unit 3. See "ACC Financing Orders" in Note 5 for additional information.
On November 22, 2002, the ACC issued the Interim Financing Order, which
permits 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, subject to certain conditions.
As of March 31, 2003, there were no borrowings outstanding under this financing
arrangement.
We pay for our capital requirements with cash from operations and, to the
extent necessary, external financings. We have historically paid for our
dividends to Pinnacle West with cash from operations.
In March 2003, we deposited monies with our first mortgage bond trustee to
redeem the entire $33 million of outstanding First Mortgage Bonds, 8% Series due
2025, and the entire $54 million of outstanding First Mortgage Bonds, 7.25%
Series due 2023. On April 7, 2003, we redeemed $33 million of our First Mortgage
Bonds, 8% Series due 2025. We will redeem $54 million of our First Mortgage
Bonds, 7.25% Series due 2023, on August 1, 2003.
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.
We are part of a multi-employer pension plan sponsored by Pinnacle West.
Pinnacle West contributes at least the minimum amount required under IRS
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 elected to contribute cash to the pension plan
in each of the last five years; the minimum required contributions during each
of those years was zero. Specifically, Pinnacle West contributed $27 million for
2002, $24 million for 2001, $44 million for 2000, $25 million for 1999 and $14
million for 1998. We fund our share of the pension contribution. 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 forecasts a pension contribution in 2003 of approximately $50 million,
all or part of which may be required. If the fund performance continues to
decline as a result of a continued decline in equity markets, larger
contributions may be required in future years.
44
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 impacts of
regulatory accounting and the determination of the appropriate accounting for
our pension and other postretirement benefits, derivatives and mark-to-market
accounting. There have been no changes to our critical accounting policies since
our 2002 10K except for discussion contained herein related to SFAS No. 143 (see
Note 13). See "Critical Accounting Policies" in Item 7 of the 2002 10-K for
further details about our critical accounting policies.
BUSINESS OUTLOOK
In this section we discuss a number of factors affecting our business
outlook.
REGULATORY MATTERS
See "Electric Industry Restructuring - State" in Note 5 for a discussion of
ACC regulatory matters, including the implementation of the Track B competitive
procurement process and our upcoming general rate case.
WHOLESALE POWER MARKET CONDITIONS
The marketing and trading division, which Pinnacle West moved to us in
early 2003 for future marketing and trading activities (existing wholesale
contracts will remain at Pinnacle West) as a result of the ACC's Track A Order
prohibiting our transfer of generating assets to Pinnacle West Energy, focuses
primarily on managing our purchased power and fuel risks in connection with our
costs of serving retail customer demand. Additionally, the marketing and trading
division, subject to specified parameters, markets, hedges and trades in
electricity, fuels, and emission allowances and credits. Our future earnings
will be affected by the strength or weakness of the wholesale power market.
FACTORS AFFECTING OPERATING REVENUES
GENERAL 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 Customer growth in our service territory averaged about
3.6% a year for the three years 2000 through 2002; we currently expect customer
growth to average about 3.5% per year from 2003 to 2005. We currently estimate
that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in
45
2003 through 2005, before the retail effects of weather variations. The customer
and sales growth referred to in this paragraph applies to energy delivery
customers.
RETAIL RATE REDUCTIONS. As part of the 1999 Settlement Agreement, we agreed
to a series of annual retail electricity price reductions of 1.5% on July 1 for
each of the years 1999 to 2003 for a total of 7.5%. The final price reduction is
to be implemented July 1, 2003. See "1999 Settlement Agreement" in Note 5 for
further information.
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
PURCHASED POWER AND FUEL COSTS Purchased power and fuel costs are impacted
by our electricity sales volumes, existing contracts for purchased power and
generation fuel, 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 Operations and maintenance expenses are
expected to be affected by sales mix and volumes, power plant additions and
operations, inflation, outages, higher trending pension and other postretirement
benefit costs and other factors. In July 2002, we implemented a voluntary
workforce reduction as part of our cost reduction program. We recorded $34
million before taxes in voluntary severance costs in the second half of 2002.
DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization
expenses are expected to be affected by net additions to existing utility plant
and other property, changes in regulatory asset amortization and our generation
construction program. The regulatory assets to be recovered under the 1999
Settlement Agreement are currently being amortized as follows (dollars in
millions):
1999 2000 2001 2002 2003 2004 TOTAL
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $686
PROPERTY TAXES 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 9.7% of assessed value for
2002 and 9.3% for 2001. We expect property taxes to increase primarily due to
our additions to existing facilities.
INTEREST EXPENSE 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 capital
requirements and 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. Interest expense is also affected by interest
rates on variable-rate debt and interest rates on the refinancing of the
Company's future liquidity needs.
RETAIL COMPETITION The regulatory developments and legal challenges to the
Rules discussed in Note 5 have raised considerable uncertainty about the status
and pace of retail electric competition in Arizona. Although some very limited
retail competition existed in our service area in 1999 and 2000, there are
46
currently no active retail competitors providing 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.
GENERAL 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.
RISK FACTORS
Exhibit 99.3, which is hereby incorporated by reference, contains a
discussion of risk factors involving the Company.
FORWARD-LOOKING STATEMENTS
This document 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 law.
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 and decisions impacting wholesale
competition; the outcome of regulatory and legislative proceedings relating to
the restructuring; state and federal regulatory and legislative decisions and
actions, including price caps and other market constraints imposed by the FERC;
regional economic and market conditions, including the California energy
situation and completion of generation and transmission construction in the
region, which could affect customer growth and the cost of power supplies; the
cost of debt and equity capital and access to capital markets; weather
variations affecting local and regional customer energy usage; the effect of
conservation programs on energy usage; power plant performance; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); our ability to manage our marketing and trading activities
and the use of derivative contracts in our business; technological developments
in the electric industry; the performance of the stock market, which affects the
amount of our required contributions to our pension plan and nuclear
decommissioning trust funds; and other uncertainties, all of which are difficult
to predict and many of which are beyond our control.
47
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in interest
rates, commodity prices and investments held by the nuclear decommissioning
trust fund and the pension plans.
COMMODITY PRICE RISK
We are exposed to the impact of market fluctuations in the commodity price
and transportation costs of electricity, natural gas, coal and emissions
allowances. We 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. The ERMC, consisting
of senior officers, oversees company-wide energy risk management activities and
monitors the results of marketing and trading activities to ensure compliance
with our stated energy risk management and trading policies. As part of our 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. In addition, subject to specified risk parameters
monitored by the ERMC, we engage in marketing and trading activities intended to
profit from market price movements.
We adopted the EITF 02-3 guidance for all contracts in the fourth quarter
of 2002. Our energy trading contracts that are derivatives are accounted for at
fair value under SFAS No. 133. Contracts that do not meet the definition of a
derivative are accounted for on an accrual basis with the associated revenues
and costs recorded at the time the contracted commodities are delivered or
received. Additionally, all gains and losses (realized and unrealized) on energy
trading contracts that qualify as derivatives are included in marketing and
trading segment revenues on the Condensed Statements of Income on a net basis.
Derivative instruments used for non-trading activities are accounted for in
accordance with SFAS No. 133. See Note 10 for details on the change in
accounting for energy trading contracts.
Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the Condensed Balance
Sheets. For non-trading derivative instruments that qualify for hedge accounting
treatment, changes in the fair value of the effective portion are recognized in
common stock equity (as a component of accumulated other comprehensive income
(loss)). Non-trading derivatives, or any portion thereof, that are not effective
hedges are adjusted to fair value through income. Gains and losses related to
non-trading derivatives that qualify as cash flow hedges of expected
transactions are recognized in revenue or purchased power and fuel expense as an
offset to the related item being hedged when the underlying hedged physical
transaction impacts earnings. If it becomes probable that a forecasted
transaction will not occur, we discontinue the use of hedge accounting and
recognize in income the unrealized gains and losses that were previously
recorded in other comprehensive income (loss). In the event a non-trading
derivative is terminated or settled, the unrealized gains and losses remain in
other comprehensive income (loss) and are recognized in income when the
underlying transaction impacts earnings.
48
Derivatives associated with trading activities are adjusted to fair value
through income. Derivative commodity contracts for the physical delivery of
purchase and sale quantities transacted in the normal course of business are
exempt from the requirements of SFAS No. 133 under the normal purchase and sales
exception and are not reflected on the balance sheet at fair value. Most of our
non-trading electricity purchase and sales agreements qualify as normal
purchases and sales and are exempted from recognition in the financial
statements until the electricity is delivered.
Our assets and liabilities from risk management and trading activities are
presented in two categories consistent with our business segments:
o System - our regulated electricity business segment, which consists of
non-trading derivative instruments that hedge our purchases and sales
of electricity and fuel for our Native Load requirements; and
o Marketing and Trading - our non-regulated, competitive business
segment, which includes both non-trading and trading derivative
instruments.
The following tables show the changes in mark-to-market of our system and
marketing and trading derivative positions for the three months ended March 31,
2003 and 2002 (dollars in millions):
Three Months Ended Three Months Ended
March 31, 2003 March 31, 2002
------------------- -------------------
Marketing Marketing
and and
System Trading System Trading
------ ------- ------ -------
Mark-to-market of net
positions at beginning
of period $ (50) $ -- $(107) $ --
Change in mark-to-market
gains (losses) for future
period deliveries 5 4 (1) --
Changes in cash flow hedges
recorded in OCI 14 -- 41 --
Ineffective portion of changes
in fair value recorded in
earnings 2 -- -- --
Mark-to-market losses
realized during the period 6 -- 3 --
----- ----- ----- -----
Mark-to-market of net
positions at end of period $ (23) $ 4 $ (64) $ --
===== ===== ===== =====
As of March 31, 2003, 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 $22
million, compared to a $24 million decrease that would have been realized as of
March 31, 2002. A hypothetical favorable price movement of 10% would have
increased the fair market value of these contracts by approximately $23 million,
compared to a $26 million increase that would have been realized as of March 31,
2002. These contracts are hedges of our forecasted purchases of natural gas. The
49
impact of these hypothetical price movements would substantially offset the
impact that these same price movements would have on the physical exposures
being hedged.
CREDIT RISK
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 related to our counterparties. Despite the fact that the
great majority of trading counterparties are rated as investment grade by the
credit rating agencies, there is still a possibility that one or more of these
companies could default, resulting in a material impact on earnings for a given
period. Counterparties in the portfolio consist principally of major energy
companies, municipalities and local distribution companies. We maintain credit
policies that we believe minimize overall credit risk to within acceptable
limits. Determination of the credit quality of our counterparties is based upon
a number of factors, including credit ratings and our evaluation of their
financial condition. In many contracts, we employ collateral requirements and
standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Valuation adjustments are
established representing our estimated credit losses on our overall exposure to
counterparties. See "Critical Accounting Policies - Mark-to-Market Accounting"
in Item 7 of our 2002 10-K for more discussion on our valuation methods.
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 Senior Vice President and Chief Financial Officer, 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 Senior Vice President and Chief
Financial Officer, 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 controls subsequent to the date of
the evaluation, including any corrective actions with regard to significant
deficiencies and internal weaknesses.
50
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.
REGULATORY MATTERS
See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of
this report for a discussion of regulatory developments.
ENVIRONMENTAL MATTERS
The EPA had previously advised us that the EPA considers us to be a
"potentially responsible party" in the Indian Bend Wash Superfund Site, South
Area. See "Environmental Matters - Superfund" in Part I, Item 1 of the 2002
10-K. We, the EPA, the United States Department of Justice, the Attorney General
for the State of Arizona, and ADEQ have reached an agreement (in the form of a
Consent Decree) to settle this matter. UNITED STATES OF AMERICA AND STATE OF
ARIZONA, EX REL. V. ARIZONA PUBLIC SERVICE COMPANY, Civil Action No.
CIV03-767PHXPGR, In the United States District Court for the District of
Arizona. Under the terms of the proposed Consent Decree, we will pay $2.72
million. Following the expiration of a thirty (30) day comment period, the
Department of Justice will move for the Consent Decree to be approved by the
Court, if appropriate in light of any public comment.
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 E. Brandt, the Registrant's
principal financial officer, pursuant to Section
906 of the Sarbanes-Oxley Act of 2002
99.3 APS Risk Factors
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:
51
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 5-15-03
Agreement dated March 2003 Form
February 27, 2003 10-Q Report
between APS and
James M. Levine
10.2 Third Supplemental 10.2 to Pinnacle West 1-8962 5-15-03
Indenture dated as of March 2003 Form 10-Q
November 1, 2002 Report
10.3 Third Amendment to 10.3 to Pinnacle West 1-8962 5-15-03
the Pinnacle West March 2003 Form 10-Q
Capital Corporation, Report
Arizona Public Service
Company, SunCor
Development Company
and El Dorado
Investment Company
Deferred Compensation
Plan
99.1 ACC Decision 65796 99.3 to Pinnacle West 1-8962 5-15-03
dated April 4, 2003 March 2003 Form 10-Q
(Financing Order)
(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.
52
(b) Reports on Form 8-K
During the quarter ended March 31, 2003, and the period from April 1
through May 14, 2003, we filed the following reports on Form 8-K:
Report dated January 15, 2003 regarding NAC losses and Pinnacle West's
earnings outlook.
Report dated January 30, 2003 regarding an ACC ALJ's recommended Track B
order.
Report dated February 24, 2003 regarding reclassifications of revenue and
costs and other income and expenses from electricity trading activities to a net
basis of reporting.
Report dated February 27, 2003 regarding the ACC Track B decision.
Report dated March 11, 2003 regarding an ACC ALJ's recommended approval,
subject to certain conditions, of APS' financing application.
Report dated March 27, 2003 regarding ACC approval of the financing
application.
Report dated May 6, 2003 regarding the Track B Order and asset retirement
obligations.
Report dated May 7, 2003 comprised of Exhibits to Registration Statement
No. 333-90824 relating to the issuance of $300 million of 4.650% Notes due 2015
and $200 million of 5.625% Notes due 2033.
Report dated May 13, 2003 comprised of slides presented at Pinnacle West
analyst meetings.
53
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Dated: May 14, 2003 By: Donald E. Brandt
------------------------------------
Donald E. Brandt
Senior Vice President and
Chief Financial Officer
(Principal Financial 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 officer 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;
54
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
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 officer 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 officer 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: May 14, 2003.
Jack E. Davis
--------------------------------------------
Jack E. Davis
Title: President and Chief Executive Officer
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
CERTIFICATIONS
I, Donald E. Brandt, 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;
55
4. The registrant's other certifying officer 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
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 officer 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 officer 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: May 14, 2003.
Donald E. Brandt
--------------------------------------------
Donald E. Brandt
Title: Senior Vice President and Chief
Financial Officer
56