Document/Exhibit Description Pages Size
1: 10-Q Quarterly Report for the Qtr Ended 3/31/2003 70 293K
2: EX-10.1 Employment Agreement - Levine 1 7K
3: EX-10.2 3rd Supplemental Indenture Dtd 11/1/02 19 82K
4: EX-10.3 3rd Amend. to Investment Co. Deferred Comp Plan 2 10K
5: EX-12.1 Ratio of Earnings to Fixed Charges 1 7K
6: EX-99.1 William J. Post Section 906 Certification 1 6K
7: EX-99.2 Donald E. Brandt Section 906 Certification 1 6K
8: EX-99.3 Acc Decision No. 65796 Dtd 4/4/03 48 172K
9: EX-99.5 Pinnacle West Risk Factors 6 35K
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 1-8962
PINNACLE WEST CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
Arizona 86-0512431
(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 [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Number of shares of common stock, no par value,
outstanding as of May 9, 2003: 91,254,179
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, a subsidiary of the Company
APS Energy Services - APS Energy Services Company, Inc., a subsidiary of the
Company
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Pinnacle West Capital Corporation
CPUC - California Public Utility Commission
EITF - the FASB's Emerging Issues Task Force
El Dorado - El Dorado Investment Company, a subsidiary of the Company
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 APS' request to
provide financing or credit support to Pinnacle West Energy or the Company
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 APS' request to provide financing or credit support to the Company
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
NAC - NAC International Inc., a subsidiary of El Dorado
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, the Company
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the
Company
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
SNWA - Southern Nevada Water Authority
SPE - special-purpose entity
Standard & Poor's - Standard & Poor's Corporation
SunCor - SunCor Development Company, a subsidiary of the Company
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.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
[Download Table]
Three Months Ended
March 31,
-------------------------
2003 2002
---------- ----------
Operating Revenues
Regulated electricity segment $ 384,960 $ 380,241
Marketing and trading segment 162,743 75,815
Real estate segment 40,688 39,511
Other revenues 15,571 4,277
---------- ----------
Total 603,962 499,844
---------- ----------
Operating Expenses
Regulated electricity segment purchased power and fuel 74,671 61,531
Marketing and trading segment purchased power and fuel 143,645 35,785
Operations and maintenance 133,117 117,430
Real estate operations segment 40,159 36,646
Depreciation and amortization 105,398 99,656
Taxes other than income taxes 28,496 26,758
Other expenses 9,221 3,302
---------- ----------
Total 534,707 381,108
---------- ----------
Operating Income 69,255 118,736
---------- ----------
Other
Other income (Note 16) 5,721 5,161
Other expense (Note 16) (4,197) (5,089)
---------- ----------
Total 1,524 72
---------- ----------
Interest Expense
Interest charges 47,851 44,519
Capitalized interest (9,979) (13,859)
---------- ----------
Total 37,872 30,660
---------- ----------
Income From Continuing Operations Before Income Taxes 32,907 88,148
Income Taxes 12,754 34,897
---------- ----------
Income From Continuing Operations 20,153 53,251
Income From Discontinued Operations
- Net of Income Tax Expense of $3,375 and $332 5,145 506
---------- ----------
Net Income $ 25,298 $ 53,757
========== ==========
Weighted-Average Common Shares Outstanding - Basic 91,256 84,735
Weighted-Average Common Shares Outstanding - Diluted 91,359 84,884
Earnings Per Weighted-Average Common Share Outstanding
Income From Continuing Operations - Basic $ 0.22 $ 0.63
Net Income - Basic 0.28 0.63
Income From Continuing Operations - Diluted 0.22 0.63
Net Income - Diluted 0.28 0.63
Dividends Declared Per Share $ 0.425 $ 0.40
See Notes to Condensed Consolidated Financial Statements.
3
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
[Enlarge/Download Table]
Twelve Months Ended
March 31,
----------------------------
2003 2002
------------ ------------
Operating Revenues
Regulated electricity segment $ 2,017,742 $ 2,529,522
Marketing and trading segment 412,859 468,750
Real estate segment 202,258 176,084
Other revenues 73,231 14,505
------------ ------------
Total 2,706,090 3,188,861
------------ ------------
Operating Expenses
Regulated electricity segment purchased power and fuel 512,683 1,092,767
Marketing and trading segment purchased power and fuel 301,899 218,588
Operations and maintenance 600,225 522,275
Real estate operations segment 189,438 159,100
Depreciation and amortization 429,824 422,778
Taxes other than income taxes 109,690 102,523
Other expenses 110,878 12,717
------------ ------------
Total 2,254,637 2,530,748
------------ ------------
Operating Income 451,453 658,113
------------ ------------
Other
Other income (Note 16) 16,226 27,096
Other expense (Note 16) (33,519) (32,864)
------------ ------------
Total (17,293) (5,768)
------------ ------------
Interest Expense
Interest charges 190,844 177,592
Capitalized interest (39,869) (51,294)
------------ ------------
Total 150,975 126,298
------------ ------------
Income From Continuing Operations Before Income Taxes 283,185 526,047
Income Taxes 110,085 207,634
------------ ------------
Income From Continuing Operations 173,100 318,413
Income From Discontinued Operations
- Net of Income Tax Expense of $8,916 and $332 13,594 506
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $8,099 -- (12,446)
Cumulative Effect of a Change in Accounting for Trading Activities
- Net of Income Tax Benefit of $43,123 (65,745) --
------------ ------------
Net Income $ 120,949 $ 306,473
============ ============
Weighted-Average Common Shares Outstanding - Basic 86,509 84,719
Weighted-Average Common Shares Outstanding - Diluted 86,627 84,910
Earnings Per Weighted-Average Common Share Outstanding
Income From Continuing Operations - Basic $ 2.00 $ 3.76
Net Income - Basic 1.40 3.62
Income From Continuing Operations - Diluted 2.00 3.75
Net Income - Diluted 1.40 3.61
Dividends Declared Per Share $ 1.65 $ 1.55
See Notes to Condensed Consolidated Financial Statements.
4
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
(unaudited)
ASSETS
March 31, December 31,
2003 2002
---------- ----------
Current Assets
Cash and cash equivalents $ 67,289 $ 77,566
Trust fund for bond redemption 87,225 --
Customer and other receivables--net 340,156 373,196
Accrued utility revenues 57,306 72,915
Materials and supplies (at average cost) 91,106 91,652
Fossil fuel (at average cost) 32,922 28,185
Deferred income taxes 4,094 4,094
Assets from risk management and trading activities 106,348 59,162
Real estate assets held for sale -- 46,475
Other current assets 89,428 103,978
---------- ----------
Total current assets 875,874 857,223
---------- ----------
Investments and Other Assets
Real estate investments--net 386,983 382,719
Assets from risk management and trading activities -
long-term 100,209 122,336
Other assets 227,882 229,891
---------- ----------
Total investments and other assets 715,074 734,946
---------- ----------
Property, Plant and Equipment
Plant in service and held for future use 9,179,261 9,058,900
Less accumulated depreciation and amortization 3,344,900 3,474,325
---------- ----------
Total 5,834,361 5,584,575
Construction work in progress 860,190 777,542
Intangible assets, net of accumulated amortization 122,721 109,815
Nuclear fuel, net of accumulated amortization 12,232 7,466
---------- ----------
Net property, plant and equipment 6,829,504 6,479,398
---------- ----------
Deferred Debits
Regulatory assets 219,344 241,045
Other deferred debits 115,125 113,194
---------- ----------
Total deferred debits 334,469 354,239
---------- ----------
Total Assets $8,754,921 $8,425,806
========== ==========
See Notes to Condensed Consolidated Financial Statements.
5
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
(unaudited)
LIABILITIES AND EQUITY
[Enlarge/Download Table]
March 31, December 31,
2003 2002
------------ ------------
Current Liabilities
Accounts payable $ 300,849 $ 354,218
Accrued taxes 108,016 71,107
Accrued interest 42,763 53,018
Short-term borrowings 207,667 102,183
Current maturities of long-term debt 485,794 280,888
Customer deposits 45,893 42,190
Real estate liabilities held for sale -- 29,451
Liabilities from risk management and trading activities 93,074 70,667
Other current liabilities 77,626 63,847
------------ ------------
Total current liabilities 1,361,682 1,067,569
------------ ------------
Long-Term Debt Less Current Maturities 2,644,449 2,869,241
------------ ------------
Deferred Credits and Other
Liabilities from risk management and trading activities -
long-term 52,143 75,642
Deferred income taxes 1,209,950 1,209,074
Unamortized gain - sale of utility plant 58,340 59,484
Pension liability 199,456 183,880
Liability for asset retirement (Note 13) 223,147 --
Other 320,048 274,763
------------ ------------
Total deferred credits and other 2,063,084 1,802,843
------------ ------------
Commitments and Contingencies (Note 12)
Common Stock Equity
Common stock, no par value 1,738,689 1,737,258
Treasury stock (4,236) (4,358)
------------ ------------
Total common stock 1,734,453 1,732,900
------------ ------------
Accumulated other comprehensive loss:
Minimum pension liability adjustment (71,233) (71,264)
Derivative instruments (8,565) (20,020)
------------ ------------
Total accumulated other comprehensive loss (79,798) (91,284)
------------ ------------
Retained earnings 1,031,051 1,044,537
------------ ------------
Total common stock equity 2,685,706 2,686,153
------------ ------------
Total Liabilities and Equity $ 8,754,921 $ 8,425,806
============ ============
See Notes to Condensed Consolidated Financial Statements.
6
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
[Enlarge/Download Table]
Three Months Ended
March 31,
------------------------
2003 2002
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 20,153 $ 53,251
Items not requiring cash:
Depreciation and amortization 105,398 99,656
Nuclear fuel amortization 7,726 7,484
Deferred income taxes (9,675) (10,434)
Change in mark-to-market (6,008) (3,090)
Changes in current assets and liabilities:
Customer and other receivables 33,040 53,815
Accrued utility revenues 15,609 12,423
Materials, supplies and fossil fuel (4,191) 476
Other current assets 16,234 (2,937)
Accounts payable (55,049) (117,731)
Accrued taxes 36,909 41,735
Accrued interest (10,255) (6,448)
Other current liabilities 17,482 24,872
Change in real estate investments (4,277) (7,841)
Increase in regulatory assets (2,152) (2,096)
Change in risk management and trading - assets 11,334 (8,862)
Change in risk management and trading - liabilities (12,370) 6,229
Change in customer advances (1,334) (24,767)
Change in pension liability 15,576 7,521
Change in other long-term assets 6,278 (9,710)
Change in other long-term liabilities 1,006 22,275
---------- ----------
Net cash flow provided by operating activities 181,434 135,821
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (174,324) (219,923)
Trust fund for bond redemption (87,225) (121,668)
Proceeds from sale of assets from discontinued operations 25,150 --
Capitalized interest (9,979) (13,859)
Other 8,238 26,706
---------- ----------
Net cash flow used for investing activities (238,140) (328,744)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 18,500 603,430
Short-term borrowings and payments--net 105,484 (253,462)
Dividends paid on common stock (38,783) (33,888)
Repayment of long-term debt (40,325) (133,749)
Other 1,553 2,416
---------- ----------
Net cash flow provided by financing activities 46,429 184,747
---------- ----------
Net Cash Flow (10,277) (8,176)
Cash and Cash Equivalents at Beginning of Period 77,566 28,619
---------- ----------
Cash and Cash Equivalents at End of Period $ 67,289 $ 20,443
========== ==========
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest paid, net of amounts capitalized $ 46,439 $ 35,212
Income taxes paid $ -- $ 30,557
See Notes to Condensed Consolidated Financial Statements.
7
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. The condensed consolidated financial statements include the accounts of
Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy
Services, SunCor and El Dorado (principally NAC). All significant intercompany
accounts and transactions between the consolidated companies have been
eliminated. We have reclassified certain prior year amounts to conform to the
current year presentation (see Notes 10 and 19.)
2. Our unaudited condensed consolidated 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, the cumulative
effect of a change in accounting for trading activities (see Note 10), asset
retirement obligations (see Note 13) and real estate discontinued operations
(see Note 19). We suggest that these condensed consolidated financial statements
and notes to condensed consolidated financial statements be read along with the
consolidated financial statements and notes to consolidated financial statements
included in our 2002 10-K.
3. 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.
4. In March 2003, APS deposited monies with its 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, APS redeemed $33 million of its First
Mortgage Bonds, 8% Series due 2025. APS will redeem $54 million of its First
Mortgage Bonds, 7.25% Series due 2023, on August 1, 2003.
On May 12, 2003, APS issued $500 million of debt as follows: $300 million
aggregate principal amount of its 4.650% Notes due 2015 and $200 million
aggregate principal amount of its 5.625% Notes due 2033. Also on May 12, 2003,
APS made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy
distributed the net proceeds of that loan to us to fund our 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. With Pinnacle West Energy's distribution to us, on May 12, 2003, we
repaid the outstanding balance ($167 million) under a credit facility. We used a
portion of the remaining proceeds to repay our short-term debt, with the balance
being temporarily invested pending the planned optional repayment of our $250
million Floating Rate Notes due 2003.
8
5. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW
On September 10, 2002, the ACC issued the Track A Order, which, among other
things, directed APS not to transfer its 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
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 APS 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 APS 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, APS issued
$500 million of debt pursuant to the Financing Order and made a $500 million
loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds
of that loan to us to fund the repayment of certain of our debt. See Note 4.
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
APS 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 "APS 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 APS has 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.
9
o Unbundled rates being charged by APS 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 APS 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 APS'
cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or judicial
decisions, actions or orders.
o APS 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 "APS General Rate Case and Retail Rate Adjustment
Mechanisms" below.
o APS' 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. APS opened its
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 APS' service area in 1999 and
2000, there are currently no active retail competitors providing
unbundled energy or other utility services to APS' customers. As a
result, we cannot predict when, and the extent to which, additional
competitors will re-enter APS' service territory.
o Prior to the 1999 Settlement Agreement, APS was recovering
substantially all of its regulatory assets through July 1, 2004,
pursuant to a 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that APS has demonstrated that its
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value (in 1999 dollars).
APS will not be allowed to recover $183 million net present value (in
1999 dollars) of the above amounts. The 1999 Settlement Agreement
provides that APS 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
10
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 APS will form, or cause to be formed, a separate corporate affiliate
or affiliates and transfer to such affiliate(s) its 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. APS
will be allowed to defer and later collect, beginning July 1, 2004,
67% of its 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
APS from transferring its generation assets.
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 APS.
o Effective January 1, 2001, retail access became available to all APS
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, APS received a waiver to allow transfer of its
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 APS to transfer its 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, APS 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.
11
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 APS' 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
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, APS is 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 APS 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 APS' 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 APS' current retail rates. In
the event of shortfalls due to unforeseen increases in load demand or generation
or transmission outages, APS may need to purchase additional supplemental power
in the wholesale spot market. Unless APS is able to obtain an adjustment of its
rates under the emergency provisions of the 1999 Settlement Agreement, there can
be no assurance that APS would be able to fully recover the costs of this power.
See "APS 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:
12
o reversed its decision, as reflected in the Rules, to require APS to
transfer its generation assets either to an unrelated third party or
to a separate corporate affiliate; and
o unilaterally modified the 1999 Settlement Agreement, which authorized
APS' transfer of its generating assets, and directed APS to cancel its
activities to transfer its generation assets to Pinnacle West Energy.
On November 15, 2002, APS 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, APS and the ACC staff agreed to principles for
resolving certain issues raised by APS in its appeals of the Track A Order. APS
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:
o The parties agreed that it would be appropriate for the ACC to
consider the following matters in APS' upcoming general rate case,
anticipated to be filed before June 30, 2003:
o the generating assets to be included in APS' 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
APS' rate base;
o the appropriate treatment of the $234 million pretax asset
write-off agreed to by APS as part of the 1999 Settlement
Agreement; and
o the appropriate treatment of costs incurred by APS 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 APS' request to provide $500 million of financing
or credit support to Pinnacle West Energy or the Company, with
appropriate conditions, APS' 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, APS' 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 APS, Pinnacle West and Pinnacle West
Energy to preserve their and our rights relating to the Track A Order. As of
13
April 22, 2003, the Notice of Claim was deemed denied with respect to the ACC
and the Arizona Attorney General, and APS, Pinnacle West and Pinnacle West
Energy may now pursue the claim in court.
TRACK B ORDER
On March 14, 2003, the ACC issued the Track B Order, which requires APS to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, APS 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 APS' total retail energy requirements. The bid
amounts are expected to increase in 2004 and 2005 based largely on growth in
APS' retail load and APS' 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 APS' 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 APS and any affiliate of APS that may
participate in the competitive solicitation, requires that APS treat bidders in
a non-discriminatory manner and requires APS to file a protocol regarding
short-term and emergency procurements. The order permits the provision of
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 confidential APS bidding information that is not available to other
bidders. The order directs APS 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, APS will prepare a
report evaluating environmental issues relating to the procurement and a series
of workshops on environmental risk management will be commenced thereafter.
APS issued requests for proposals in March 2003 and by May 6, 2003, APS
entered into contracts to meet all or a portion of its 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.
14
ACC FINANCING ORDERS
On April 4, 2003, the ACC issued the Financing Order authorizing APS 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 APS 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 APS 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;
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 APS' 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 APS must maintain a common equity ratio of at least forty percent and
may not pay common dividends if such payment would reduce its 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 APS and its 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;
15
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, APS issued $500 million of debt pursuant to the Financing
Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy
distributed the net proceeds of that loan to us to fund the repayment of certain
of our debt. See Note 4.
On November 22, 2002, the ACC issued an order (the "Interim Financing
Order") approving APS' request to permit APS 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.
APS GENERAL RATE CASE AND RETAIL RATE ADJUSTMENT MECHANISMS
As required by the 1999 Settlement Agreement, on or before June 30, 2003,
APS will file a general rate case with the ACC. In this rate case, APS will
update its cost of service and rate design. In addition, APS expects 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 APS as
part of the 1999 Settlement Agreement ($140 million extraordinary
charge recorded on the 1999 Consolidated Statement of Income); and
o recovery of costs incurred by APS 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
16
rate adjustment mechanisms, which were authorized as a result of the 1999
Settlement Agreement, would allow APS 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.
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 APS' service area in 1999 and 2000, there are currently
no active retail competitors providing unbundled energy or other utility
services to APS' customers. As a result, we cannot predict when, and the extent
to which, additional competitors will re-enter APS' 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, APS 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 APS' interest
in the three Palo Verde units, APS' 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
17
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. APS has 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 three principal business segments (determined by products, 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;
o our marketing and trading segment, which consists of our competitive
energy business activities, including wholesale marketing and trading
and APS Energy Services' commodity-related energy services. In early
2003, we moved our marketing and trading division from Pinnacle West
to APS 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 APS'
generating assets to Pinnacle West Energy; and
o our real estate segment, which consists of SunCor's real estate
development and investment activities.
The amounts in our other segment include activity principally related to
NAC in the periods ended March 31, 2003 (see Note 12), as well as the parent
company and other subsidiaries. Financial data for the Company's business
segments follows (dollars in millions):
18
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------- --------------------
2003 2002 2003 2002
-------- -------- -------- --------
Operating Revenues:
Regulated electricity $ 385 $ 380 $ 2,018 $ 2,530
Marketing and trading 163 76 413 469
Real estate 41 40 202 176
Other 15 4 73 14
-------- -------- -------- --------
Total $ 604 $ 500 $ 2,706 $ 3,189
======== ======== ======== ========
Income From Continuing Operations:
Regulated electricity $ 8 $ 31 $ 147 $ 179
Marketing and trading 8 20 46 133
Real estate (a) 1 1 9 4
Other 3 1 (29) 1
-------- -------- -------- --------
Total $ 20 $ 53 $ 173 $ 317
======== ======== ======== ========
(a) Excludes income from discontinued operations for the three months ended
March 31 of $5 million (after tax) in 2003 and $1 million (after tax) in
2002. Excludes income from discontinued operations for the twelve months
ended March 31 of $14 million (after tax) in 2003 and $1 million (after
tax) in 2002. See Note 19 for further discussion of our real estate
activities.
As of As of
March 31, December 31,
2003 2002
-------- --------
Assets:
Regulated electricity $ 8,033 $ 7,589
Marketing and trading 250 301
Real estate 448 504
Other 24 32
-------- --------
Total $ 8,755 $ 8,426
======== ========
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
19
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
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.
20
In 1986, APS 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.
APS is exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that APS does 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), APS 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, APS 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
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. In 2002, we recorded a $66 million after tax charge in net income as a
cumulative effect adjustment for the previously recorded accumulated unrealized
mark-to-market on energy trading contracts that did not meet the accounting
definition of a derivative. 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 Consolidated
Statements of Income on a net basis. Derivative instruments used for non-trading
activities are accounted for in accordance with SFAS No. 133.
21
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 Consolidated Statements of Income for the three and twelve months
ended March 31, 2003 and 2002 are comprised of the following (dollars in
thousands):
[Enlarge/Download Table]
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) $ 2,778 $ (2,548) $ 16,524 $ (6,155)
Losses from the discontinuance of cash flow hedges -- (44) (8,776) (3,561)
Losses from non-hedge derivatives (106) (855) (3,575) (6,864)
Prior period mark-to-market losses realized upon
delivery of commodities 10,443 3,813 14,635 23,368
---------- ---------- ---------- ----------
Total pretax gain $ 13,115 $ 366 $ 18,808 $ 6,788
========== ========== ========== ==========
(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 six years. During the twelve months ending March 31, 2004, we
estimate that a net loss of $3 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 APS' 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):
22
March 31, 2003
[Download Table]
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
---------- ----------- ----------- ----------- -----------
Mark-to-Market:
Marketing
and Trading $ 23,849 $ 39,743 $ (6,479) $ (1,242) $ 55,871
System 82,499 8,205 (86,595) (26,890) (22,781)
Emission
allowances
- at cost -- 52,261 -- (24,011) 28,250
---------- ---------- ---------- ---------- ----------
Total $ 106,348 $ 100,209 $ (93,074) $ (52,143) $ 61,340
========== ========== ========== ========== ==========
December 31, 2002
[Download Table]
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
---------- ----------- ----------- ----------- -----------
Mark-to-Market:
Marketing
and Trading $ 17,640 $ 51,771 $ (9,848) $ (2,583) $ 56,980
System 41,522 6,971 (60,819) (36,678) (49,004)
Emission
allowances
- at cost -- 63,594 -- (36,381) 27,213
---------- ---------- ---------- ---------- ----------
Total $ 59,162 $ 122,336 $ (70,667) $ (75,642) $ 35,189
========== ========== ========== ========== ==========
Cash or collateral required to serve as collateral against our open
positions on energy-related contracts is included in investments and other
assets and current liabilities on the Condensed Consolidated Balance Sheet. No
collateral was provided at March 31, 2003. Collateral provided was $5 million at
December 31, 2002. Collateral held was $23 million at March 31, 2003 and $22
million at December 31, 2002.
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):
23
[Enlarge/Download Table]
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------------ ------------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Net income $ 25,298 $ 53,757 $ 120,949 $ 306,473
---------- ---------- ---------- ----------
Other comprehensive income (loss):
Minimum pension liability adjustment, net
of tax 31 -- (70,267) (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) 15,806 26,826 32,920 (72,200)
Reclassification of realized (gain) loss to
income, net of tax (b) (4,351) 990 (5,702) (8,809)
---------- ---------- ---------- ----------
Total other comprehensive income (loss) 11,486 27,816 (43,049) (74,174)
---------- ---------- ---------- ----------
Comprehensive income $ 36,784 $ 81,573 $ 77,900 $ 232,299
========== ========== ========== ==========
(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.
APS was a seller and a purchaser in the California markets at issue, and to
the extent that refunds are ordered, APS 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
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
24
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. APS does not anticipate material changes
in its exposure and still believes, subject to the finalization of the revised
proxy prices, that it 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 APS, 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 APS is still attempting to determine and to review the
transactions at issue, it believes that it was 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.
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.
25
We are closely monitoring developments in the California energy market and
the potential impact of these developments on us and our subsidiaries. Based on
our evaluations, we previously reserved $10 million before income taxes for our
credit exposure related to the California energy situation, $5 million of which
was recorded in the fourth quarter of 2000 and $5 million of which was recorded
in the first quarter of 2001. Our evaluations took into consideration our range
of exposure of approximately zero to $38 million before income taxes and review
of likely recovery rates in bankruptcy situations.
In the second quarter of 2002, PG&E filed its Modified Second Amended
Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization.
Both plans generally indicated that PG&E would, at the close of bankruptcy
proceedings, be able to pay in full all outstanding, undisputed debts. As a
result of these developments, the probable range of our total exposure now is
approximately zero to $27 million before income taxes, and our best estimate of
the probable loss is now approximately $6 million before income taxes.
Consequently, we reversed $4 million of the $10 million reserve in the second
quarter of 2002. We cannot predict with certainty, however, the impact that any
future resolution or attempted resolution, of the California energy market
situation may have on us, our subsidiaries or the regional energy market in
general.
CALIFORNIA ENERGY MARKET LITIGATION On March 19, 2002, the State of
California filed a complaint with the FERC alleging that wholesale sellers of
power and energy, including 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 APS, attempting
to expand those matters to such other participants. APS has not yet filed a
responsive pleading in the matter, but APS believes the claims by Reliant and
Duke as they relate to APS are without merit.
APS was 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 APS 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 us, as well as the California Department of Water
26
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 APS 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 APS that it believes APS overcharged Citizens by over $50 million under
a power service agreement. APS believes its charges under the agreement were
fully in accordance with the terms of the agreement. In addition, in testimony
filed with the ACC on March 13, 2002, Citizens acknowledged, based on its
review, "if Citizens filed a complaint with FERC, it probably would lose the
central issue in the contract interpretation dispute." APS and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, the Company and Citizens entered into a power
sale agreement under which the Company 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.
EL DORADO'S INVESTMENT IN NAC
Through our unregulated wholly-owned subsidiary, El Dorado, we own a
majority interest in NAC, a company that develops, markets and contracts for the
manufacture of cask designs for spent nuclear fuel storage and transportation.
Prior to the third quarter of 2002, our investment in NAC was accounted for
under the equity method and our share of NAC's earnings and losses was recorded
in other income or expense in our Condensed Consolidated Statements of Income.
Beginning in the third quarter of 2002, we fully consolidated NAC's financial
statements after acquiring a controlling interest in NAC as a result of
increased voting representation on NAC's Board of Directors. During the second
and third quarters of 2002, we recorded cumulative losses of approximately $21
million before tax ($13 million after tax, $0.15 per share) related to NAC,
primarily as a result of expected losses under contracts with two customers,
including a contract between NAC and Maine Yankee Atomic Power Company (Maine
Yankee).
On January 15, 2003, Maine Yankee notified NAC of its intention to
terminate its contract with NAC. We recorded additional NAC losses of
approximately $38 million before tax ($23 million after tax, or $0.27 per share)
in the fourth quarter of 2002, the substantial majority of which relate to the
termination of the Maine Yankee contract. As a result, in 2002, we recorded NAC
losses of approximately $59 million before tax ($35 million after tax, or $0.42
per share).
On March 4, 2003, Maine Yankee filed suit against Pinnacle West, NAC and a
surety company in federal court in Portland, Maine. MAINE YANKEE
27
ATOMIC POWER COMPANY V. UNITED STATES FIRE INSURANCE COMPANY, Civil Action
Docket No. 03-58-PC, United States District Court, District of Maine. The
lawsuit and a related arbitration proceeding initiated by NAC were dismissed in
April 2003 as part of a settlement among the parties. We reversed $5 million of
loss reserves in the first quarter of 2003 related to NAC's contract settlement.
We believe we have reserved our exposure with respect to NAC's contracts in all
material respects and, as a result, we consider these charges non-recurring. We
do not expect material losses for the year 2003 related to NAC.
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.
APS has asset retirement obligations for its 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 APS 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, APS cannot reasonably estimate the fair
value of the asset retirement obligation related to such distribution and
transmission assets. The asset retirement obligations associated with our
non-regulated assets are immaterial.
On January 1, 2003, APS recorded a liability of $219 million for its 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, APS recorded a net regulatory liability of
$40 million for the asset retirement obligations related to its 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. APS believes it 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, APS will continue to accrue for removal
costs for its regulated assets, even if there is no legal obligation for
removal. At March 31, 2003, accumulated depreciation shown on our Condensed
Consolidated Balance Sheets included approximately $360 million of estimated
future removal costs that are not considered legal obligations.
28
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 APS expects to incur to decommission the plant, APS
established external decommissioning trusts in accordance with NRC regulations.
APS invests the trust funds primarily in fixed income securities and domestic
stock and classifies them as available for sale. The following table shows the
cost and fair value of APS' nuclear decommissioning trust fund assets which are
reported in investments and other assets on the Condensed Consolidated 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
====== ======
29
14. Intangible Assets
The Company's gross intangible assets (which are primarily software) were
$233 million at March 31, 2003 and $214 million at December 31, 2002. The
related accumulated amortization was $110 million at March 31, 2003 and $104
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 $23 million in 2003 and $21 million in
2002. Estimated amortization expense on existing intangible assets over the next
five years is $27 million in 2003, $26 million in 2004, $25 million in 2005, $22
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, stock compensation expense and
earnings per share 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, except per share amounts):
Three Months Ended Twelve Months Ended
March 31, March 31,
-------------------- --------------------
2003 2002 2003 2002
-------- -------- -------- --------
Net Income:
As reported $ 25,298 $ 53,757 $120,949 $306,473
Pro forma (fair value method) 24,998 53,385 119,626 304,382
Stock compensation expense
(net of tax):
As reported 152 -- 452 --
Pro forma (fair value method) 300 372 1,323 2,091
Earnings per share - basic:
As reported $ 0.28 $ 0.63 $ 1.40 $ 3.62
Pro forma (fair value method) $ 0.27 $ 0.63 $ 1.38 $ 3.59
Earnings per share - diluted:
As reported $ 0.28 $ 0.63 $ 1.40 $ 3.61
Pro forma (fair value method) $ 0.27 $ 0.63 $ 1.38 $ 3.58
30
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):
[Enlarge/Download Table]
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------------ ------------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Other income:
Environmental insurance recovery $ -- $ -- $ -- $ 12,350
Investment gains - net 1,279 2,039 -- --
Interest income 713 1,178 3,957 7,371
SunCor joint venture earnings 3,244 916 9,605 3,423
Miscellaneous 485 1,028 2,664 3,952
---------- ---------- ---------- ----------
Total other income $ 5,721 $ 5,161 $ 16,226 $ 27,096
========== ========== ========== ==========
Other expense:
Investment losses - net (a) $ -- $ -- $ (11,198) $ (4,138)
Non-operating costs - SunCor -- -- -- (7,000)
Non-operating costs (b) (3,538) (3,882) (19,086) (16,362)
Miscellaneous (659) (1,207) (3,235) (5,364)
---------- ---------- ---------- ----------
Total other expense $ (4,197) $ (5,089) $ (33,519) $ (32,864)
========== ========== ========== ==========
(a) Primarily related to El Dorado's investment in NAC in 2002 (see Note 12).
(b) 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 have issued parental guarantees and letters of credit and obtained
surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees
related to Pinnacle West Energy primarily consist of equipment and performance
guarantees related to our generation construction program, transmission service
guarantees for West Phoenix Units 4 and 5 and long-term service agreement
guarantees for new power plants. Our credit support instruments enable APS
Energy Services to provide commodity energy and energy-related products and
enable El Dorado to support the activities of NAC. SunCor has a debt guarantee
on behalf of an affiliated joint venture. Non-performance or payment under the
31
original contract by our unregulated subsidiaries would require us to perform
under the guarantee or surety bond. No liability is currently recorded on the
Condensed Consolidated Balance Sheets related to Pinnacle West's guarantees on
behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or
collateral provisions to allow us to recover amounts paid under the guarantee.
The amounts and approximate terms of our guarantees and surety bonds for each
subsidiary at March 31, 2003 are as follows (dollars in millions):
[Enlarge/Download Table]
Guarantees Surety Bonds Letters of Credit
-------------------- -------------------- --------------------
Term Term Term
Amount (in years) Amount (in years) Amount (in years)
------ ---------- ------ ---------- ------ ----------
Parental:
Pinnacle West Energy $106 1 to 2 $ -- -- $ 37 1 to 2
APS Energy Services 82 less than 2 49 less than 1 -- --
El Dorado (all NAC) 44 1 to 3 -- -- 5 1
SunCor guarantees 33 1 -- -- -- --
---- ---- ----
Total $265 $ 49 $ 42
==== ==== ====
At March 31, 2003, we had entered into approximately $37 million of letters
of credit which support various construction agreements. These letters of credit
expire in 2003 and 2004. 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.
APS has 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. APS has 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, APS has 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. APS intends 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. APS has 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
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.
32
18. Earnings Per Share
The following table presents earnings per weighted average common share
outstanding for the three and twelve months ended March 31, 2003 and 2002:
Three Months Ended Twelve Months Ended
March 31, March 31,
---------------- -----------------
2003 2002 2003 2002
------ ------ ------ ------
Basic earnings per share:
Income from continuing operations $ 0.22 $ 0.63 $ 2.00 $ 3.76
Income from discontinued operations 0.06 -- 0.16 --
Cumulative effect of change in
accounting for derivatives -- -- -- (0.14)
Cumulative effect of change in
accounting for trading activities -- -- (0.76) --
------ ------ ------ ------
Earnings per share - basic $ 0.28 $ 0.63 $ 1.40 $ 3.62
====== ====== ====== ======
Diluted earnings per share:
Income from continuing operations $ 0.22 $ 0.63 $ 2.00 $ 3.75
Income from discontinued operations 0.06 -- 0.16 --
Cumulative effect of change in
accounting for derivatives -- -- -- (0.14)
Cumulative effect of change in
accounting for trading activities -- -- (0.76) --
------ ------ ------ ------
Earnings per share - diluted $ 0.28 $ 0.63 $ 1.40 $ 3.61
====== ====== ====== ======
The following table reconciles average common shares outstanding - basic to
average common shares outstanding - diluted that are used in the earnings per
share calculation in the Condensed Consolidated Statements of Income for the
three and twelve months ended March 31, 2003 and 2002 (in thousands):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2003 2002 2003 2002
------ ------ ------ ------
Average common shares
outstanding - basic 91,256 84,735 86,509 84,719
Dilutive shares 103 149 118 191
------ ------ ------ ------
Average common shares
outstanding - diluted 91,359 84,884 86,627 84,910
====== ====== ====== ======
Options to purchase 2,245,211 shares for the three month period ended March
31, 2003 and 1,991,119 shares for the twelve month period ended March 31, 2003
were outstanding but were not included in the computation of earnings per share
because the options' exercise prices were greater than the average market price
of the common shares. Options to purchase shares of common stock that were not
included in the computation of diluted earnings per share were 1,075,100 shares
33
for the three months ended March 31, 2002 and 635,761 shares for the twelve
months ended March 31, 2002.
19. Real Estate Activities - Discontinued Operations
On January 1, 2002 we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." Among other things, SFAS No. 144 prescribes
accounting for discontinued operations and defines certain real estate
activities as discontinued operations.
In the first quarter of 2003, SunCor sold its water utility company, which
resulted in an after tax gain of $5 million ($8 million pretax). The gain on the
sale and operating income in the current and prior periods are classified as
discontinued operations in our Condensed Consolidated Statements of Income.
In the second quarter of 2002, SunCor sold a retail center, but maintained
a significant continuing involvement through a management contract. In the first
quarter of 2003, this management contract was canceled. As a result, the gain on
the 2002 sale and the operating income related to this property have been
reclassified as discontinued operations. The income from discontinued operations
of $14 million (after income taxes) in the twelve months ended March 31, 2003
primarily reflects this sale and the sale of the water utility company.
The following chart provides a summary of the real estate segment's
earnings (after income taxes) for the three and twelve months ended March 31,
2003 and 2002 (dollars in millions):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2003 2002 2003 2002
------ ------ ------ ------
Income from continuing operations $ 1 $ 1 $ 9 $ 4
Income from discontinued operations 5 1 14 1
------ ------ ------ ------
Net income $ 6 $ 2 $ 23 $ 5
====== ====== ====== ======
34
PINNACLE WEST CAPITAL CORPORATION
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 for Pinnacle West and our subsidiaries: APS, Pinnacle West
Energy, APS Energy Services, SunCor and El Dorado, 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 Consolidated
Financial Statements in this report. These Notes add further details to the
discussion. Operating statistics for the three and twelve months ended March 31,
2003 and 2002 are available on our website (www.pinnaclewest.com) and in our
Current Report on Form 8-K dated March 31, 2003.
OVERVIEW OF OUR BUSINESS
The Company owns all of the outstanding common stock of APS. APS is 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 owned by APS. APS also
generates, sells and delivers electricity to wholesale customers in the western
United States. APS does not distribute any products. The marketing and trading
segment sells, in the wholesale market, APS and Pinnacle West Energy generation
output that is not needed for APS' Native Load, which includes loads for retail
customers and traditional cost-of-service wholesale customers.
Our other major subsidiaries are:
o Pinnacle West Energy, through which we conduct our competitive
electricity generation operations;
o APS Energy Services, which provides competitive commodity-related
energy services (such as direct access commodity contracts, energy
procurement and energy supply consultation) and energy-related
products and services (such as energy master planning, energy use
consultation and facility audits, cogeneration analysis and
installation and project management) to commercial, industrial and
institutional retail customers in the western United States;
35
o SunCor, a developer of residential, commercial and industrial real
estate projects in Arizona, New Mexico and Utah; and
o El Dorado, which owns a majority interest in NAC (specializing in
spent nuclear fuel technology) and holds miscellaneous small
investments, including interests in Arizona community-based ventures.
EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT
We have three principal business segments (determined by products, 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;
o our marketing and trading segment, which consists of our competitive
energy business activities, including wholesale marketing and trading
and APS Energy Services' commodity-related energy services; and
o our real estate segment, which consists of SunCor's real estate
development and investment activities.
The following tables summarize net income and segment details for the three
and twelve months ended March 31, 2003 and the comparable prior periods for
Pinnacle West and each of our subsidiaries (dollars in millions):
[Enlarge/Download Table]
Regulated Marketing and
Total Electricity Trading Real Estate (a) Other
THREE MONTHS ENDED ---------------- ---------------- ---------------- ---------------- ----------------
MARCH 31, 2003 2002 2003 2002 2003 2002 2003 2002 2003 2002
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Arizona Public Service (b)(c) $ 16 $ 32 $ 13 $ 31 $ 3 $ 1 $ -- $ -- $ -- $ --
Pinnacle West Energy (b) 5 1 6 1 (1) -- -- -- -- --
APS Energy Services (d) 8 2 -- -- 6 1 -- -- 2 1
SunCor 1 1 -- -- -- -- 1 1 -- --
El Dorado (d) 3 -- -- -- -- -- -- -- 3 --
Parent company (c) (13) 17 (11) (1) -- 18 -- -- (2) --
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Income from continuing
operations 20 53 8 31 8 20 1 1 3 1
Income from discontinued
operations - net of tax 5 1 -- -- -- -- 5 1 -- --
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Net income $ 25 $ 54 $ 8 $ 31 $ 8 $ 20 $ 6 $ 2 $ 3 $ 1
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
36
[Enlarge/Download Table]
Regulated Marketing and
Total Electricity Trading Real Estate (a) Other
TWELVE MONTHS ENDED ---------------- ---------------- ---------------- ---------------- ----------------
MARCH 31, 2003 2002 2003 2002 2003 2002 2003 2002 2003 2002
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Arizona Public Service (b)(c) $ 183 $ 248 $ 179 $ 166 $ 4 $ 82 $ -- $ -- $ -- $ --
Pinnacle West Energy (b)(f) (14) 19 (16) 19 2 -- -- -- -- --
APS Energy Services (d) 34 -- -- -- 28 (2) -- -- 6 2
SunCor 9 4 -- -- -- -- 9 4 -- --
El Dorado (d) (52) -- -- -- -- -- -- -- (52) --
Parent company (c) 13 46 (16) (6) 12 53 -- -- 17 (1)
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Income from continuing
operations 173 317 147 179 46 133 9 4 (29) 1
Income from discontinued
operations - net of tax 14 1 -- -- -- -- 14 1 -- --
Cumulative effect of
change in accounting -
net of tax (g) (h) (66) (12) -- -- (66) (12) -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Net income (loss) $ 121 $ 306 $ 147 $ 179 $ (20) $ 121 $ 23 $ 5 $ (29) $ 1
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
(a) See "Real Estate Activities" discussion below and Note 19.
(b) Consistent with APS' October 2001 ACC filing, APS entered into agreements
with its 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 APS' 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.
(c) In early 2003, we moved our marketing and trading division from Pinnacle
West to APS 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 APS' generating
assets to Pinnacle West Energy.
(d) APS Energy Services' net income prior to 2003 and El Dorado's net income
are primarily reported before income taxes. The income tax expense or
benefit for these subsidiaries was recorded at the parent company.
(e) Primarily includes activities related to El Dorado in the twelve months
ended March 31, 2003, principally El Dorado's investment in NAC. For the
twelve months ended March 31, 2003, we recorded a pretax loss of $55
million related to NAC contracts with two customers. See Note 12.
(f) In the fourth quarter of 2002, Pinnacle West Energy recorded a charge
related to the cancellation of Redhawk Units 3 and 4 of approximately $30
million after income taxes ($49 million pretax).
(g) We recorded a $66 million after tax charge as of October 1, 2002 for the
cumulative effect of a change in accounting for trading activities, for the
early adoption of EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities."
37
(h) APS 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. Our real estate segment gross
margin refers to real estate revenues less real estate operations costs of
SunCor. Other gross margin refers to other operating revenues less other
operating expenses, which includes El Dorado's investment in NAC, which we began
consolidating in our financial statements in July 2002. Other gross margin also
includes amounts related to APS Energy Services' energy consulting services.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2003 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 2002
Our consolidated net income for the three months ended March 31, 2003 was
$25 million compared with $54 million for the prior year. Included in 2003
income is $5 million of after tax income related primarily to SunCor's sale of
its water utility company accounted for as discontinued operations in our real
estate segment (see "Real Estate Activities" below).
Our income from continuing operations for the three months ended March 31,
2003 was $20 million compared with $53 million for the comparable period in the
prior year. The period-to-period decrease of $33 million was primarily due to:
o lower earnings contributions from our marketing and trading
activities, reflecting lower liquidity and higher price volatility in
the wholesale power markets in the western United States, partially
offset by lower mark-to-market reversals due to the adoption of EITF
02-3 ($17 million, after tax);
o higher depreciation, operations and maintenance, and interest expenses
related to new power plants in service ($10 million, after tax);
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 cost for plant outages,
partially offset by retail customer growth, ($5 million, after tax);
and
o other miscellaneous factors ($2 million, after tax).
38
The above decreases were partially offset by:
o higher competitive retail sales in California by APS Energy Services
($5 million, after tax); and
o the settlement of an NAC contract dispute involving Maine Yankee
Atomic Power Company (see Note 12) ($3 million, after tax).
For additional details, see the following discussion.
39
The major factors that increased (decreased) income from continuing
operations were as follows (dollars in millions):
[Enlarge/Download Table]
Increase
(Decrease)
----------
Regulated electricity segment gross margin:
Increased purchased power and fuel costs due to higher hedged gas
and power prices $ (8)
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 8
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 (8)
--------
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 1
Lower realized wholesale margins net of related mark-to-market
reversals due to lower prices, partially offset by higher volumes (12)
More competitive retail sales in California by APS Energy Services 8
Lower mark-to-market reversals due to the adoption of EITF 02-3 8
Lower mark-to-market gains for future delivery due to lower market
liquidity and higher price volatility (26)
--------
Net decrease in marketing and trading segment gross margin (21)
--------
Net decrease in regulated electricity and marketing and trading segments'
gross margins (29)
Lower real estate segment gross margin primarily due to lower land sales
(See "Real Estate Activities" below and Note 19) (2)
Higher other gross margin primarily due to NAC's settlement of a contract
dispute (see Note 12) 5
Higher operations and maintenance expense related to increased operating
costs related to the timing of power plant overhauls, increased pension
and other postretirement benefit costs and new power plants in service (16)
Higher depreciation primarily related to new power plants and increased
plant balances, partially offset by lower regulatory asset amortization (6)
Higher net interest expense primarily due to higher debt balances and lower
capitalized interest (7)
--------
Net decrease in income from continuing operations before income (55)
taxes
Lower income taxes primarily due to lower income 22
--------
Net decrease in income from continuing operations $ (33)
========
40
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $5 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 increased revenues related to retail load hedge management wholesale
sales, primarily as a result of higher prices ($3 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 ($3 million, net increase).
Regulated electricity segment purchased power and fuel costs were $13
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 costs related to retail load hedge management wholesale
sales, primarily as a result of higher prices ($3 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 ($3 million, net increase).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $87 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 ($36 million);
o higher realized wholesale revenues net of related mark-to-market
reversals primarily due to higher volumes ($41 million);
o increased revenues from higher competitive retail sales in California
by APS Energy Services ($30 million);
o higher revenues related to the adoption of EITF 02-3 ($8 million); and
o lower mark-to-market gains for future delivery primarily as a result
of lower market liquidity and higher price volatility ($28 million).
41
Marketing and trading segment purchased power and fuel costs were $108
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 ($35 million);
o increased purchased power costs related to other realized marketing
activities in the current period primarily due to higher volumes and
higher prices ($53 million);
o increased purchased power costs related to higher competitive retail
sales in California by APS Energy Services ($22 million); and
o change in mark-to-market fuel costs for future delivery ($2 million
decrease).
OTHER INCOME STATEMENT ITEMS
The decrease in real estate segment gross margin of $2 million was
primarily due to lower land sales. In addition, as discussed in "Real Estate
Activities" below and Note 19, SunCor had an $8 million ($5 million after tax)
gain on the sale of its water utility company which was reported as income from
discontinued operations in the three months ended March 31, 2003.
The increase in other gross margin of $5 million was primarily due to NAC's
settlement of a contract dispute involving Maine Yankee Atomic Power Company.
See Note 12.
The increase in operations and maintenance expense of $16 million was due
to increased operating costs related to the timing of power plant overhauls,
increased pension and other postretirement benefit costs, new power plants in
service and other costs.
The increase in depreciation and amortization expense of $6 million
primarily related to increased plant balances and new power plants, partially
offset by lower regulatory asset amortization.
Net interest expense increased $7 million primarily because of higher debt
balances related to our generation construction program and lower capitalized
interest on our generation construction program due to completion of Redhawk
Units 1 and 2 in mid-2002.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2003 COMPARED WITH
TWELVE-MONTH PERIOD ENDED MARCH 31, 2002
Our consolidated net income for the twelve months ended March 31, 2003 was
$121 million compared with $306 million for the prior year. Included in the 2003
period was a $66 million after tax charge for the cumulative effect of a change
in accounting for trading activities for the early adoption of EITF 02-3 on
October 1, 2002 and $14 million of after tax income related to certain
discontinued operations in our real estate segment (see "Real Estate Activities"
below). 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.
42
Our income from continuing operations for the twelve months ended March 31,
2003 was $173 million compared with $317 million for the prior year. The
period-to-period decrease of $144 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, partially
offset by lower mark-to-market reversals due to the adoption of EITF
02-3 ($104 million, after tax);
o losses related to our investment in NAC ($32 million, after tax);
o higher operations and maintenance expenses related to the Redhawk
Units 3 and 4 cancellation charge and 2002 severance costs, partially
offset by lower generation reliability costs ($32 million, after tax);
o higher depreciation, operations and maintenance, and interest expenses
related to new power plants in service ($27 million, after tax);
o higher pension and other postretirement benefit costs ($7 million,
after tax); and
o miscellaneous factors, net ($4 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,
partially offset by the effects of milder weather and retail
electricity price decreases ($41 million, after tax); and
o higher competitive retail sales in California by APS Energy Services
($21 million, after tax).
For additional details, see the following discussion.
43
The major factors that increased (decreased) income from continuing
operations were as follows (dollars in millions):
[Enlarge/Download Table]
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)
2001 charges related to purchase power contracts with Enron 13
Increased purchased power and fuel costs due to higher hedged gas
and power prices (4)
Change in mark-to-market for hedged natural gas and purchased
power costs for future delivery 15
Miscellaneous factors, net (6)
--------
Net increase in regulated electricity segment gross margin 68
--------
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 (19)
Lower realized wholesale margins net of related mark-to-market
reversals due to lower prices, partially offset by higher volumes (68)
More competitive retail sales in California by APS Energy Services 35
Lower mark-to-market reversals due to the adoption of EITF 02-3 16
Lower mark-to-market gains for future delivery due to lower market
liquidity and lower price volatility (103)
--------
Net decrease in marketing and trading segment gross margin (139)
--------
Net decrease in regulated electricity and marketing and trading segments'
gross margins (71)
Lower real estate segment gross margin primarily due to commercial and
property management sales, partially offset by higher home and land sales
(see "Real Estate Activities" below and Note 19) (4)
Lower other gross margin primarily related to NAC losses (see Note 12) (40)
Higher operations and maintenance expense related primarily to a $47 million
write-off of Redhawk Units 3 and 4 and 2002 severance costs of
approximately $36 million, partially offset by lower generation
reliability costs (78)
Higher depreciation primarily related to increased plant balances and new
power plants, partially offset by lower regulatory asset amortization (7)
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 (11)
Higher net interest expense primarily due to higher debt balances and lower
capitalized interest (25)
Miscellaneous factors, net 1
--------
Net decrease in income from continuing operations before income
taxes (242)
Lower income taxes primarily due to lower income 98
--------
Net decrease in income from continuing operations $ (144)
========
44
REGULATED ELECTRICITY SEGMENT GROSS MARGIN
Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $512 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
($449 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 ($1 million net decrease).
Regulated electricity segment purchased power and fuel costs were $580
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
($445 million);
o charges in 2001 related to purchased power contracts with Enron and
its affiliates ($13 million net decrease);
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); and
o miscellaneous factors ($5 million net increase).
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $56 million lower in the twelve
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 sales volumes, partially offset by lower
market prices ($17 million);
45
o lower realized wholesale revenues net of related mark-to-market
reversals primarily due to lower prices partially offset by higher
volumes ($112 million);
o increased revenues from higher competitive retail sales in California
by APS Energy Services ($124 million);
o higher revenues related to the adoption of EITF 02-3 ($16 million);
and
o lower mark-to-market gains for future delivery primarily as a result
of lower market liquidity and lower price volatility ($101 million).
Marketing and trading segment purchased power and fuel costs were $83
million higher 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 ($36 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 ($44 million);
o increased purchased power costs related to higher competitive retail
sales in California by APS Energy Services ($89 million); and
o change in mark-to-market fuel costs for future delivery ($2 million
increase).
OTHER INCOME STATEMENT ITEMS
The decrease in real estate segment gross margin of $4 million was
primarily due to lower commercial and property management sales partially offset
by higher home and land sales activities. In addition, as discussed in "Real
Estate Activities" below and Note 19, SunCor had a $23 million ($14 million
after tax) gain on the sale of its water utility company and a retail center
which was reported as income from discontinued operations in the twelve months
ended March 31, 2003.
The decrease in other gross margin of $40 million was primarily due to
losses on El Dorado's investment in NAC. Losses for the twelve month period
ended March 31, 2003 totaled approximately $55 million on a pretax basis and
were primarily related to NAC contracts with two customers ($47 million was
recorded in other gross margin and $8 million was recorded in other expense). We
reversed $5 million of loss reserves in the first quarter of 2003 related to
NAC's contract settlement. We believe we have reserved our exposure with respect
to these contracts in all material respects and, as a result, we consider these
charges to be non-recurring. See Note 12.
The increase in operations and maintenance expense of $78 million was due
to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4,
severance costs of $36 million related to a 2002 voluntary workforce reduction,
increased pension and other postretirement benefit costs of $12 million and
other costs of $13 million, partially offset by lower costs related to
generation reliability, plant outages and maintenance costs of $30 million.
46
The increase in depreciation and amortization expense of $7 million
primarily related to increased plant balances and new power plants, partially
offset by lower regulatory amortization.
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 $11 million primarily due to an insurance recovery
recorded in 2001 related to environmental remediation costs and other costs.
Net interest expense increased $25 million primarily because of higher debt
balances related to our generation construction program and lower capitalized
interest on our generation construction program due to completion of Redhawk
Units 1 and 2 in mid-2002.
REAL ESTATE ACTIVITIES
As discussed in our 2002 10-K, we have undertaken an aggressive effort to
accelerate asset sales activities to approximately double SunCor's annual
earnings in 2003 to 2005 compared with the $19 million in earnings recorded in
2002.
Certain components of SunCor's real estate sales activities, which are
included in the real estate segment, may be required to be reported as
discontinued operations on our Consolidated Statements of Income in accordance
with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Among other things, SFAS No. 144 prescribes accounting for discontinued
operations and defines certain real estate activities as discontinued
operations. We adopted SFAS No. 144 effective January 1, 2002 and determined
that activities that would have required discontinued operations reporting in
2002, 2001 and 2000 were immaterial. We currently estimate that 20% to 40% of
SunCor's net income in 2003 will be reported in discontinued operations;
however, this ultimately depends on the specific properties sold.
In the first quarter of 2003, SunCor sold its water utility company, which
resulted in an after tax gain of $5 million ($8 million pretax). The gain on the
sale and operating income in the current and prior periods are classified as
discontinued operations on our Condensed Consolidated Statements of Income.
In the second quarter of 2002, SunCor sold a retail center, but maintained
a significant continuing involvement through a management contract. In the first
quarter of 2003, this management contract was canceled. As a result, the gain on
the 2002 sale and the operating income related to this property have been
reclassified as discontinued operations. The income from discontinued operations
of $14 million (after income taxes) in the twelve months ended March 31, 2003
primarily reflects this sale and the sale of the water utility company.
The following chart provides a summary of SunCor's earnings (after income
taxes) for the three and twelve months ended March 31, 2003 and the comparable
prior periods (dollars in millions):
47
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2003 2002 2003 2002
------ ------ ------ ------
Income from continuing
operations $ 1 $ 1 $ 9 $ 4
Income from discontinued
operations 5 1 14 1
------ ------ ------ ------
Net income $ 6 $ 2 $ 23 $ 5
====== ====== ====== ======
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
------ ------ ------ ------
APS
Delivery $ 73 $ 273 $ 275 $ 329
Generation (a) 35 123 99 164
Other 1 5 5 5
------ ------ ------ ------
Subtotal 109 401 379 498
Pinnacle West Energy (a) (b) 61 268 31 20
SunCor (c) 15 64 23 20
Other (d) 5 17 13 14
------ ------ ------ ------
Total $ 190 $ 750 $ 446 $ 552
====== ====== ====== ======
(a) As discussed in Note 5 under "APS General Rate Case and Retail Rate
Adjustment Mechanisms," as part of its 2003 general rate case, APS intends
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).
(b) See "Capital Resources and Cash Requirements - Pinnacle West Energy" below
for further discussion of Pinnacle West Energy's generation construction
program. These amounts do not include an expected reimbursement in 2004 by
SNWA of about $100 million, assuming SNWA exercises its option to purchase
a 25% interest in the Silverhawk project at that time.
(c) Consists primarily of capital expenditures for land development and retail
and office building construction reflected in the "Change in real estate
investments" in the Condensed Consolidated Statements of Cash Flows.
(d) Primarily related to the parent company and APS Energy Services.
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
48
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, APS began several major transmission projects in 2001.
These projects are periodic in nature and are driven by strong regional customer
growth. APS expects to spend about $105 million on major transmission projects
during the 2003 to 2005 time frame, and these amounts are included in
"APS-Delivery" in the table above.
Generation capital expenditures are comprised of various improvements for
APS' 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.
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):
49
[Enlarge/Download Table]
Actual
--------
Three
Months Estimated
Ended ---------------------------------------------------------------
March 31, There-
2003 2003 2004 2005 2006 2007 after
-------- -------- -------- -------- -------- -------- --------
Long-term debt payments:
APS $ -- $ -- $ 205 $ 400 $ 84 $ -- $ 1,518
Pinnacle West -- 275 215 -- 300 -- --
SunCor 33 -- 106 -- 3 -- 2
El Dorado -- 1 1 1 -- -- --
-------- -------- -------- -------- -------- -------- --------
Total long-term debt payments 33 276 527 401 387 -- 1,520
Capital lease payments 1 5 5 4 3 3 6
Operating lease payments 5 70 66 64 63 63 478
Purchase power and fuel commitments 64 202 85 28 31 17 162
-------- -------- -------- -------- -------- -------- --------
Total contractual commitments $ 103 $ 553 $ 683 $ 497 $ 484 $ 83 $ 2,166
======== ======== ======== ======== ======== ======== ========
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, APS 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.
APS is exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that APS does 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), APS 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, APS would have been required to assume
approximately $285 million of debt and pay the equity participants approximately
$200 million.
50
GUARANTEES
We and certain of our subsidiaries have issued guarantees and letters of
credit in support of our unregulated businesses. We have also obtained surety
bonds on behalf of APS Energy Services. We have not recorded any liability on
our Condensed Consolidated Balance Sheets with respect to these obligations. See
Note 17 for additional information regarding guarantees.
CREDIT RATINGS
The ratings of securities of Pinnacle West and APS 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 Pinnacle West's or APS' securities and
serve to increase those companies' cost of and access to capital. All of
Pinnacle West's and APS' credit ratings remain investment grade.
Moody's Standard & Poor's Fitch
------- ----------------- -----
PINNACLE WEST
Senior unsecured Baa2 BBB- BBB
Commercial paper P-2 A-2 F-2
APS
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
Pinnacle West's and APS' significant debt covenants related to their
respective financing arrangements include a debt-to-total-capitalization ratio
and an interest coverage test. Pinnacle West and APS are in compliance with such
covenants and each anticipates it will continue to meet all the significant
covenant requirement levels. The ratio of debt to total capitalization cannot
exceed 65% for both the Company and APS. At March 31, 2003, the ratios are
approximately 55% and 49% for the parent company and APS, respectively. The
provisions regarding interest coverage require a minimum cash coverage of two
times the interest requirements for both the Company and APS. The coverages are
approximately 4 times for the parent company, 5 times for the APS bank
agreements and 14 times for the APS mortgage indenture. Failure to comply with
51
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.
Neither Pinnacle West's nor APS' financing agreements 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, Pinnacle West and/or APS may be subject to increased
interest costs under certain financing agreements.
All of Pinnacle West's bank agreements contain cross-default provisions
that would result in defaults and the potential acceleration of payment under
these agreements if Pinnacle West or APS were to default under other agreements.
All of APS' bank agreements contain cross-default provisions that would result
in defaults and the potential acceleration of payment under these bank
agreements if APS were to default under other agreements. Pinnacle West's and
APS' 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.
PINNACLE WEST (PARENT COMPANY)
Our primary cash needs are for dividends to our shareholders; equity
infusions into our subsidiaries, primarily Pinnacle West Energy; and interest
payments and optional and mandatory repayments of principal on our long-term
debt (see the table above for our contractual requirements, including our debt
repayment obligations, but excluding optional repayments). The level of our
common dividends and future dividend growth will be dependent on a number of
factors including, but not limited to, payout ratio trends, free cash flow and
financial market conditions.
Our primary sources of cash are dividends from APS, external financings and
cash distributions from our other subsidiaries, primarily SunCor. For the years
2000 through 2002, total dividends from APS were $510 million and total
distributions from SunCor were $33 million. We expect SunCor to make cash
distributions to the parent company of $80 to $100 million annually in 2003
through 2005 due to anticipated accelerated asset sales activity.
On November 22, 2002, the ACC issued the Interim Financing Order, which
permits APS 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.
On April 4, 2003, the ACC issued the Financing Order, which permits APS 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, APS issued $500 million of debt as follows: $300 million
aggregate principal amount of its 4.650% Notes due 2015 and $200 million
aggregate principal amount of its 5.625% Notes due 2033. Also on May 12, 2003,
APS made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy
distributed the net proceeds of that loan to us to fund our 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. With Pinnacle West Energy's distribution to us, on May 12, 2003, we
repaid the outstanding balance ($167 million) under a credit facility. We used a
portion of the remaining proceeds to repay our short-term debt, with the balance
being temporarily invested pending the planned optional repayment of our $250
million Floating Rate Notes due 2003.
52
As part of a multi-employer pension plan sponsored by Pinnacle West, we
contribute 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 our pension obligation. We
elected to contribute cash to our pension plan in each of the last five years;
our minimum required contributions during each of those years was zero.
Specifically, we contributed $27 million for 2002, $24 million for 2001, $44
million for 2000, $25 million for 1999 and $14 million for 1998. APS and other
subsidiaries fund their share of the pension contribution, of which APS
represents approximately 90% of the total funding amounts described above. The
assets in the plan are mostly domestic common stocks, bonds and real estate. We
currently forecast 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.
APS
APS' capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. See "Business Outlook -
Regulatory Matters" below and Notes 4 and 5 for discussion of the $500 million
financing arrangement between APS and Pinnacle West Energy authorized by the ACC
pursuant to the Financing Order and APS' related issuance of $500 million of
debt. See "Pinnacle West (Parent Company)" above and Note 5 for discussion of a
$125 million interim financing arrangement between APS and Pinnacle West.
APS pays for its capital requirements with cash from operations and, to the
extent necessary, external financings. APS has historically paid for its
dividends to Pinnacle West with cash from operations.
In March 2003, APS deposited monies with its 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, APS redeemed $33 million of its First
Mortgage Bonds, 8% Series due 2025. APS will redeem $54 million of its First
Mortgage Bonds, 7.25% Series due 2023, on August 1, 2003.
Although provisions in APS' first mortgage bond indenture, articles of
incorporation and ACC financing orders establish maximum amounts of additional
first mortgage bonds, debt and preferred stock that APS may issue, APS does not
expect any of these provisions to limit its ability to meet its capital
requirements.
53
PINNACLE WEST ENERGY
The costs of Pinnacle West Energy's construction of generating capacity
from 2000 through 2004 are expected to be about $1.4 billion. This does not
reflect an expected reimbursement in 2004 by SNWA of about $100 million of
Pinnacle West Energy's cumulative capital expenditures in the Silverhawk
project, assuming SNWA exercises its option to purchase a 25% interest in the
project. Pinnacle West Energy is currently funding its capital requirements
through capital infusions from Pinnacle West, which finances those infusions
through debt and equity financings and internally-generated cash. See the
capital expenditures table above for actual capital expenditures in the three
months ended March 31, 2003 and projected capital expenditures for the next
three years.
Pinnacle West Energy's generation construction plan is as follows:
o A 650 MW combined cycle expansion of the West Phoenix Power Plant in
Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation in
June 2001. The 530 MW West Phoenix Unit 5 is expected to begin
commercial operation in mid-2003.
o Development of the 570 MW Silverhawk combined-cycle plant 20 miles
north of Las Vegas, Nevada. Construction of the plant began in August
2002, with an expected commercial operation date of mid-2004. Pinnacle
West Energy has signed an agreement with Las Vegas-based SNWA under
which SNWA has an option to purchase a 25% interest in the project for
approximately $100 million.
o A Pinnacle West Energy affiliate is exploring the possibility of
creating an underground natural gas storage facility on Company-owned
land west of Phoenix. An analysis to determine the feasibility of the
project is in progress.
See Notes 4 and 5 and "Pinnacle West (Parent Company)" above for a
discussion of the $500 million financing arrangement between APS and Pinnacle
West Energy authorized by the ACC pursuant to the Financing Order.
OTHER SUBSIDIARIES
During the past three years, SunCor funded its cash requirements with cash
from operations and its own external financings. SunCor's capital needs consist
primarily of capital expenditures for land development and retail and office
building construction. See the capital expenditures table above for actual
capital expenditures in the three months ended March 31, 2003 and projected
capital expenditures for the next three years. SunCor expects to fund its
capital requirements with cash from operations and external financings.
We expect SunCor to make cash distributions to the parent company of $80 to
$100 million annually in 2003 through 2005 due to anticipated accelerated asset
sales activity. See "Real Estate Activities" above and Note 19.
54
El Dorado funded its cash requirements during the past three years,
primarily for NAC in 2002, with cash infused by the parent company and with cash
from operations. El Dorado expects minimal capital requirements over the next
three years.
APS Energy Services' cash requirements during the past three years were
funded with cash infusions from the parent company. APS Energy Services' capital
expenditures and other cash requirements are increasingly funded by operations,
with some funding from cash infused by Pinnacle West. See the capital
expenditures table above regarding APS Energy Services' actual capital
expenditures for the three months ended March 31, 2003 and projected capital
expenditures for the next three years.
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 10-K except for the 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 APS' upcoming general rate case.
55
WHOLESALE POWER MARKET CONDITIONS
The marketing and trading division, which we moved to APS 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 APS'
transfer of generating assets to Pinnacle West Energy, focuses primarily on
managing APS' purchased power and fuel risks in connection with its 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.
GENERATION CONSTRUCTION PLAN
See "Liquidity and Capital Resources - Pinnacle West Energy" for
information regarding Pinnacle West Energy's generation construction plan. The
planned additional generation is expected to increase revenues, fuel expenses,
operating expenses and financing costs.
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. Competitive sales of energy and
energy-related products and services are made by APS Energy Services in western
states that have opened to competitive supply.
CUSTOMER GROWTH Customer growth in APS' 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
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, APS
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
56
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 $36
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. West Phoenix Unit 4 was placed in service in June 2001.
Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in
July 2002. West Phoenix Unit 5 is expected to be on line in mid-2003 and
Silverhawk is expected to be in service in mid-2004. 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. The average property tax rate for APS, which currently owns
the majority of our property, was 9.7% of assessed value for 2002 and 9.3% for
2001. We expect property taxes to increase primarily due to our generation
construction program and 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. As noted above, we have placed new power plants
in commercial operation in 2001 and 2002 and we expect to bring additional
plants on-line in 2003 and 2004. 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 APS' service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to APS' customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter APS' service territory.
SUBSIDIARIES In the case of SunCor, we are undertaking an aggressive effort
to accelerate asset sales activities to approximately double SunCor's annual
earnings in 2003 to 2005 compared to the $19 million in earnings recorded in
2002. A portion of these sales have been, and additional amounts may be required
to be, reported as discontinued operations on the Condensed Consolidated
Statements of Income. See "Real Estate Activities" above and Note 19 for further
discussion.
57
The annual earnings contribution from APS Energy Services is expected to be
positive over the next several years due primarily to a number of retail
electricity contracts in California. APS Energy Services' had pretax earnings of
$28 million in 2002.
El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. In addition, we do not expect material losses for the
year 2003 related to NAC.
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 99.4, 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; the successful
completion of our generation construction program; regulatory issues associated
with generation construction, such as permitting and licensing; 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; the strength of the real estate market in SunCor's
market areas, which include Arizona, New Mexico and Utah; and other
uncertainties, all of which are difficult to predict and many of which are
beyond our control.
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 our pension plans.
58
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 Consolidated 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
Consolidated 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.
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.
59
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):
[Download Table]
Three Months Ended Three Months Ended
March 31, 2003 March 31, 2002
---------------------- ----------------------
Marketing Marketing
System and Trading System and Trading
-------- ----------- -------- -----------
Mark-to-market of net
positions at beginning
of period $ (49) $ 57 $ (107) $ 138
Change in mark-to-market
gains (losses) for future
period deliveries 5 (8) (1) 25
Changes in cash flow hedges
recorded in OCI 13 13 44 --
Ineffective portion of changes
in fair value recorded in
earnings 2 1 (2) --
Mark-to-market losses/(gains)
realized during the period 6 (7) 5 (22)
-------- -------- -------- --------
Mark-to-market of net
positions at end of period $ (23) $ 56 $ (61) $ 141
======== ======== ======== ========
The Company no longer reports non-derivative energy contracts or physical
inventories at fair value. Since July 1, 2002, the Company has not recognized a
dealer profit or unrealized gain or loss at the inception of a derivative unless
the fair value of that instrument (in its entirety) is evidenced by quoted
market prices or current market transactions. Prior to the change in our policy,
we recorded net gains at inception of $8 million in the three months ended March
31, 2002. These amounts included a reasonable marketing margin. No net gains at
inception were recorded in the three months ended March 31, 2003.
The tables below show the maturities of our system and marketing and
trading derivative positions at March 31, 2003 by the type of valuation that is
performed to calculate the fair value of the contract (dollars in millions). See
"Critical Accounting Policies - Mark-to-Market Accounting" in Item 7 of our 2002
10-K for more discussion on our valuation methods.
60
[Enlarge/Download Table]
SYSTEM
Total
Years fair
Source of Fair Value 2003 2004 2005 2006 2007 thereafter value
-------------------- -------- -------- -------- -------- -------- ---------- --------
Prices actively
quoted $ -- $ (11) $ -- $ -- $ -- $ -- $ (11)
Prices provided by
other external
sources (3) (9) -- -- -- -- (12)
Prices based on
models and other
valuation methods -- -- -- -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Total by maturity $ (3) $ (20) $ -- $ -- $ -- $ -- $ (23)
======== ======== ======== ======== ======== ======== ========
MARKETING AND TRADING
[Enlarge/Download Table]
Total
Years fair
Source of Fair Value 2003 2004 2005 2006 2007 thereafter value
-------------------- -------- -------- -------- -------- -------- ---------- --------
Prices actively
quoted $ 19 $ 4 $ 6 $ 4 $ 3 $ 7 $ 43
Prices provided by
other external
sources (4) 11 4 (4) -- -- 7
Prices based on
models
and other valuation
methods (3) 2 1 8 3 (5) 6
-------- -------- -------- -------- -------- -------- --------
Total by maturity $ 12 $ 17 $ 11 $ 8 $ 6 $ 2 $ 56
======== ======== ======== ======== ======== ======== ========
The table below shows the impact hypothetical price movements of 10% would
have on the market value of our risk management and trading assets and
liabilities included on the Condensed Consolidated Balance Sheets at March 31,
2003 and 2002 (dollars in millions).
61
[Download Table]
March 31, 2003 March 31, 2002
Gain (Loss) Gain (Loss)
---------------------- ----------------------
Price Up Price Down Price Up Price Down
Commodity 10% 10% 10% 10%
--------- -------- ---------- -------- ----------
Mark-to-market changes
reported in earnings (a):
Electricity $ -- $ 1 $ (2) $ 2
Natural gas (3) 3 (1) 1
Other 1 -- 1 (1)
Mark-to-market changes
reported in OCI (b):
Electricity 32 (32) -- --
Natural gas 23 (22) 26 (24)
------- ------- ------- -------
Total $ 53 $ (50) $ 24 $ (22)
======= ======= ======= =======
(a) These contracts are structured sales activities hedged with a portfolio of
forward purchases that protects the economic value of the sales
transactions.
(b) These contracts are hedges of our forecasted purchases of natural gas and
electricity. The 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 have risk management and trading contracts with many
counterparties, including two counterparties for which a worst case exposure
represents approximately 40% of our $207 million of risk management and trading
assets as of March 31, 2003. Our risk management process assesses and monitors
the financial exposure of these and all other counterparties. Despite the fact
that the great majority of trading counterparties are rated as investment grade
by the credit rating agencies, including the counterparties noted above, there
is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated 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.
62
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 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 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.
63
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Note 12 of Notes to Condensed Consolidated Financial Statements in Part
1, Item 1 of this report for a discussion of the settlement of the NAC
litigation.
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 and its
subsidiaries.
REGULATORY MATTERS
See Note 5 of Notes to Condensed Consolidated Financial Statements in Part
I, Item 1 of this report for a discussion of regulatory developments.
ENVIRONMENTAL MATTERS
The EPA had previously advised APS that the EPA considers APS 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. APS, 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, APS 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.
64
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
10.1 Employment Agreement dated February 27, 2003 between
APS and James M. Levine
10.2 Third Supplemental Indenture dated as of November 1,
2002
10.3 Third Amendment to the Pinnacle West Capital
Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company
Deferred Compensation Plan
12.1 Ratio of Earnings to Fixed Charges
99.1 Certification of William J. Post, 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 ACC Decision No. 65796 dated April 4, 2003 (Financing
Order)
99.4 Pinnacle West Risk Factors
65
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:
[Enlarge/Download Table]
Originally Filed Date
Exhibit No. Description as Exhibit: File No.(a) Effective
----------- ----------- ----------- ----------- ---------
3.1 Articles of Incorporation 19.1 to the Company's 1-8962 11-14-88
restated as of July 29, September 30, 1988
1988 Form 10-Q Report
----------
(a) Reports filed under File No. 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
[Download Table]
3.2 Bylaws, amended as of 3.1 to the Company's 1-8962 11-14-02
September 18, 2002 September 30, 2002
Form 10-Q Report
(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 December 31, 2002 regarding an ACC ALJ's recommended Track B
order and exhibits comprised of financial information and earnings variance
explanations.
Report dated January 15, 2003 regarding NAC losses and Pinnacle West's
earnings outlook.
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 March 31, 2003 containing exhibits comprised of financial
information, earnings variance explanations and an earnings news release.
Report dated May 6, 2003 regarding the Track B Order and asset retirement
obligations.
Report dated May 13, 2003 comprised of slides presented at analyst
meetings.
66
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PINNACLE WEST CAPITAL CORPORATION
(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, William J. Post, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Pinnacle West Capital
Corporation;
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:
67
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.
William J. Post
----------------------------------------
William J. Post
Title: Chairman of the Board 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 Pinnacle West Capital
Corporation;
68
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;
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
69
Dates Referenced Herein and Documents Incorporated by Reference
| Referenced-On Page |
|---|
| This ‘10-Q’ Filing | | Date | | First | | Last | | | Other Filings |
|---|
| |  |
| | 5/31/08 | | 28 |
| | 12/31/04 | | 11 | | | | | 10-K, 11-K, 8-K, U-3A-2 |
| | 7/1/04 | | 11 | | 13 | | | 4 |
| | 3/31/04 | | 23 | | | | | 10-Q, 8-K |
| | 1/1/04 | | 11 |
| | 8/1/03 | | 9 | | 54 |
| | 7/1/03 | | 10 | | 57 | | | 4, 4/A |
| | 6/30/03 | | 10 | | 21 | | | 10-Q, 11-K, 4, 8-K |
| Filed as of: | | 5/15/03 |
| Filed on: | | 5/14/03 | | 67 | | 70 |
| | 5/13/03 | | 67 | | | | | 8-K |
| | 5/12/03 | | 9 | | 53 |
| | 5/9/03 | | 1 |
| | 5/6/03 | | 15 | | 67 | | | 4, 8-K |
| | 4/28/03 | | 18 | | | | | 4 |
| | 4/22/03 | | 15 |
| | 4/7/03 | | 9 | | 54 |
| | 4/4/03 | | 2 | | 66 |
| For Period End: | | 3/31/03 | | 1 | | 67 | | | 10-K, 8-K |
| | 3/27/03 | | 67 | | | | | 8-K |
| | 3/26/03 | | 25 | | 26 |
| | 3/14/03 | | 3 | | 15 |
| | 3/11/03 | | 67 | | | | | 8-K |
| | 3/4/03 | | 28 |
| | 2/27/03 | | 66 | | 67 | | | 8-K |
| | 2/21/03 | | 14 |
| | 2/1/03 | | 21 | | 51 |
| | 1/31/03 | | 21 | | 51 |
| | 1/15/03 | | 28 | | 67 | | | 8-K |
| | 1/1/03 | | 29 | | 32 |
| | 12/31/02 | | 3 | | 67 | | | 10-K, 11-K, 5, 8-K, U-3A-2 |
| | 12/19/02 | | 26 | | | | | 424B2 |
| | 12/13/02 | | 14 |
| | 12/12/02 | | 25 |
| | 11/22/02 | | 2 | | 53 | | | 3, 8-K |
| | 11/20/02 | | 26 |
| | 11/15/02 | | 14 | | | | | 8-K |
| | 11/1/02 | | 66 |
| | 10/31/02 | | 18 |
| | 10/1/02 | | 38 | | 43 |
| | 9/30/02 | | 67 | | | | | 10-Q, 8-K |
| | 9/18/02 | | 67 |
| | 9/10/02 | | 3 | | 13 | | | 8-K |
| | 7/31/02 | | 18 |
| | 7/1/02 | | 10 | | 61 | | | 11-K, 4, 4/A |
| | 3/31/02 | | 22 | | 63 | | | 10-Q, 8-K |
| | 3/19/02 | | 27 |
| | 3/13/02 | | 28 |
| | 1/1/02 | | 35 | | 48 |
| | 12/31/01 | | 30 | | | | | 10-K405, 11-K, 4, U-3A-2 |
| | 9/24/01 | | 26 |
| | 7/15/01 | | 28 |
| | 7/1/01 | | 10 | | 45 |
| | 6/20/01 | | 26 | | | | | 3 |
| | 6/1/01 | | 28 |
| | 3/7/01 | | 28 |
| | 1/1/01 | | 11 | | 12 |
| | 12/25/00 | | 26 |
| | 11/27/00 | | 13 | | | | | 8-K |
| | 7/1/00 | | 10 |
| | 1/1/00 | | 11 | | 26 |
| | 9/24/99 | | 11 |
| | 7/1/99 | | 10 | | 11 |
| List all Filings |
4 Subsequent Filings that Reference this Filing
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