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