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)
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)
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
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)
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):
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
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
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
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):
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):
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
trad