FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 1-8962
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 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 August 12, 2002: 84,776,489
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ALJ - administrative law judge
APS - Arizona Public Service Company, a subsidiary of the Company
APSES - 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 - Emerging Issues Task Force
El Dorado - El Dorado Investment Company, a subsidiary of the Company
ERMC - the Company's Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
GAAP - Generally accepted accounting principles in the United States
ISO - California Independent System Operator
March 2002 10-Q - Pinnacle West Capital Corporation Quarterly Report on Form
10-Q for the fiscal quarter ended March 31, 2002
MW - megawatt, one million watts
MWh - megawatt hour
NAC - Nuclear Assurance Corporation
Native Load - retail and wholesale sales supplied under traditional cost-based
rate regulation
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the
Company
PG&E - PG&E Corp.
PX - California Power Exchange
Rules - ACC retail electric competition rules
SCE - Southern California Edison
SFAS - Statement of Financial Accounting Standards
SNWA - Southern Nevada Water Authority
SPE - special-purpose entity
SunCor - SunCor Development Company, a subsidiary of the Company
System - Non-trading energy related activities
T&D - transmission and distribution
Trading - Energy related activities entered into with the objective of
generating profits on changes in market prices
2001 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the
fiscal year ended December 31, 2001
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 June 30,
---------------------------
2002 2001
----------- -----------
Operating Revenues
Electric retail segment $ 496,840 $ 739,317
Marketing and trading segment 148,946 522,041
Real estate 69,152 32,454
----------- -----------
Total 714,938 1,293,812
----------- -----------
Operating Expenses
Electric retail segment purchased power and fuel 104,590 434,822
Marketing and trading segment purchased power and fuel 129,927 423,935
Operations and maintenance 128,996 132,139
Real estate operations 56,213 32,437
Depreciation and amortization 102,087 106,129
Taxes other than income taxes 27,632 25,462
----------- -----------
Total 549,445 1,154,924
----------- -----------
Operating Income 165,493 138,888
----------- -----------
Other
Other income (Note 16) 7,073 16,016
Other expense (Note 16) (14,766) (12,779)
----------- -----------
Total (7,693) 3,237
----------- -----------
Interest Expense
Interest charges 46,996 43,823
Capitalized interest (14,005) (12,527)
----------- -----------
Total 32,991 31,296
----------- -----------
Income Before Income Taxes 124,809 110,829
Income Taxes 49,444 43,972
----------- -----------
Net Income $ 75,365 $ 66,857
=========== ===========
Weighted-Average Common Shares Outstanding - Basic 84,794 84,744
Weighted-Average Common Shares Outstanding - Diluted 84,926 85,042
Earnings Per Weighted-Average Common Share Outstanding
Net Income - Basic $ 0.89 $ 0.79
Net Income - Diluted 0.89 0.79
Dividends Declared Per Share $ 0.40 $ 0.375
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
Six Months Ended June 30,
--------------------------
2002 2001
----------- -----------
Operating Revenues
Electric retail segment $ 877,079 $ 1,152,124
Marketing and trading segment 348,479 1,015,728
Real estate 110,337 64,789
----------- -----------
Total 1,335,895 2,232,641
----------- -----------
Operating Expenses
Electric retail segment purchased power and fuel 166,122 564,449
Marketing and trading segment purchased power and fuel 289,431 810,732
Operations and maintenance 246,426 257,389
Real estate operations 93,571 63,445
Depreciation and amortization 202,000 210,910
Taxes other than income taxes 54,390 50,765
----------- -----------
Total 1,051,940 1,957,690
----------- -----------
Operating Income 283,955 274,951
----------- -----------
Other
Other income (Note 16) 14,433 19,974
Other expense (Note 16) (21,038) (17,475)
----------- -----------
Total (6,605) 2,499
----------- -----------
Interest Expense
Interest charges 91,684 86,572
Capitalized interest (28,128) (22,954)
----------- -----------
Total 63,556 63,618
----------- -----------
Income Before Income Taxes 213,794 213,832
Income Taxes 84,672 84,770
----------- -----------
Income Before Accounting Change 129,122 129,062
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $1,793 -- (2,755)
----------- -----------
Net Income $ 129,122 $ 126,307
=========== ===========
Weighted-Average Common Shares Outstanding - Basic 84,769 84,736
Weighted-Average Common Shares Outstanding - Diluted 84,910 85,005
Earnings Per Weighted-Average Common Share Outstanding
Income Before Accounting Change - Basic $ 1.52 $ 1.52
Net Income - Basic 1.52 1.49
Income Before Accounting Change - Diluted 1.52 1.52
Net Income - Diluted 1.52 1.49
Dividends Declared Per Share $ 0.80 $ 0.75
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
Twelve Months Ended June 30,
----------------------------
2002 2001
----------- -----------
Operating Revenues
Electric retail segment $ 2,287,043 $ 2,764,355
Marketing and trading segment 1,153,128 1,768,905
Real estate 214,456 144,891
----------- -----------
Total 3,654,627 4,678,151
----------- -----------
Operating Expenses
Electric retail segment purchased power and fuel 762,536 1,387,776
Marketing and trading segment purchased power and fuel 982,054 1,505,521
Operations and maintenance 519,132 489,810
Real estate operations 183,588 130,473
Depreciation and amortization 418,993 430,839
Taxes other than income taxes 104,693 99,543
----------- -----------
Total 2,970,996 4,043,962
----------- -----------
Operating Income 683,631 634,189
----------- -----------
Other
Other income (Note 16) 28,700 32,099
Other expense (Note 16) (43,569) (58,463)
----------- -----------
Total (14,869) (26,364)
----------- -----------
Interest Expense
Interest charges 180,934 171,418
Capitalized interest (53,036) (35,957)
----------- -----------
Total 127,898 135,461
----------- -----------
Income Before Income Taxes 540,864 472,364
Income Taxes 213,437 184,941
----------- -----------
Income Before Accounting Change 327,427 287,423
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefits of $8,099 and $1,793 (12,446) (2,755)
----------- -----------
Net Income $ 314,981 $ 284,668
=========== ===========
Weighted-Average Common Shares Outstanding - Basic 84,734 84,736
Weighted-Average Common Shares Outstanding - Diluted 84,888 85,007
Earnings Per Weighted-Average Common Share Outstanding
Income Before Accounting Change - Basic $ 3.86 $ 3.39
Net Income - Basic 3.72 3.36
Income Before Accounting Change - Diluted 3.86 3.38
Net Income - Diluted 3.71 3.35
Dividends Declared Per Share $ 1.575 $ 1.475
See Notes to Condensed Consolidated Financial Statements.
-4-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
ASSETS
June 30, December 31,
2002 2001
---------- ----------
(unaudited)
Current Assets
Cash and cash equivalents $ 13,859 $ 28,619
Customer and other receivables--net 347,079 367,241
Accrued utility revenues 110,689 76,131
Materials and supplies (at average cost) 82,300 81,215
Fossil fuel (at average cost) 31,105 27,023
Assets from risk management and trading activities 47,604 66,973
Other current assets 91,160 80,203
---------- ----------
Total current assets 723,796 727,405
---------- ----------
Investments and Other Assets
Real estate investments--net 419,740 418,673
Assets from risk management and trading activities -
long-term 218,910 200,351
Other assets 286,843 320,004
---------- ----------
Total investments and other assets 925,493 939,028
---------- ----------
Property, Plant and Equipment
Plant in service and held for future use 8,236,570 8,030,134
Less accumulated depreciation and amortization 3,387,971 3,290,097
---------- ----------
Total 4,848,599 4,740,037
Construction work in progress 1,225,544 1,032,234
Intangible assets, net of accumulated amortization 99,497 86,782
Nuclear fuel, net of accumulated amortization 51,661 49,282
---------- ----------
Net property, plant and equipment 6,225,301 5,908,335
---------- ----------
Deferred Debits
Regulatory assets 291,473 342,383
Other deferred debits 77,166 64,597
---------- ----------
Total deferred debits 368,639 406,980
---------- ----------
Total Assets $8,243,229 $7,981,748
========== ==========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
LIABILITIES AND EQUITY
June 30, December 31,
2002 2001
----------- -----------
(unaudited)
Current Liabilities
Accounts payable $ 164,293 $ 269,124
Accrued taxes 171,590 96,729
Accrued interest 52,260 48,806
Short-term borrowings 374,266 405,762
Current maturities of long-term debt 1,344 126,140
Customer deposits 35,682 30,232
Deferred income taxes 3,244 3,244
Liabilities from risk management and trading activities 29,077 35,994
Other current liabilities 84,818 74,898
----------- -----------
Total current liabilities 916,574 1,090,929
----------- -----------
Long-Term Debt Less Current Maturities 3,124,231 2,673,078
----------- -----------
Deferred Credits and Other
Liabilities from risk management and trading activities -
long-term 110,627 207,576
Deferred income taxes 1,052,223 1,064,993
Unamortized gain - sale of utility plant 61,772 64,060
Other 387,466 381,789
----------- -----------
Total deferred credits and other 1,612,088 1,718,418
----------- -----------
Commitments and contingencies (Note 12)
Common Stock Equity
Common stock, no par value 1,532,641 1,531,038
Retained earnings 1,094,157 1,032,850
Accumulated other comprehensive loss (36,462) (64,565)
----------- -----------
Total common stock equity 2,590,336 2,499,323
----------- -----------
Total Liabilities and Equity $ 8,243,229 $ 7,981,748
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
Six Months Ended June 30,
-------------------------
2002 2001
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income before accounting change $ 129,122 $ 129,062
Items not requiring cash
Depreciation and amortization 202,000 210,910
Nuclear fuel amortization 15,214 14,178
Deferred income taxes--net (31,071) (24,299)
Change in mark-to-market--trading 4,549 (92,990)
Change in mark-to-market--system (6,321) 8,030
Changes in current assets and liabilities
Customer and other receivables--net 20,162 203,147
Accrued utility revenues (34,558) (30,768)
Materials, supplies and fossil fuel (5,167) (14,090)
Other current assets (10,957) 5,356
Accounts payable (101,416) (183,525)
Accrued taxes 74,861 95,428
Accrued interest 3,454 (5,225)
Other current liabilities 15,370 (63,303)
Increase in real estate investments (547) (25,786)
Increase in regulatory assets (5,992) (7,447)
Change in risk management and trading investments - at cost (53,544) 22,541
Customer advances 1,695 30,232
Change in long term assets (7,046) (15,070)
Change in long term liabilities 3,145 17,022
--------- ---------
Net Cash Flow Provided By Operating Activities 212,953 273,403
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Trust fund for bond redemption -- (72,370)
Capital expenditures (454,080) (427,062)
Capitalized interest (28,128) (22,954)
Other--net 28,633 14,469
--------- ---------
Net Cash Flow Used For Investing Activities (453,575) (507,917)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 606,046 482,500
Short-term borrowings and payments--net (31,496) 219,174
Dividends paid on common stock (67,816) (63,573)
Repayment of long-term debt (282,475) (396,512)
Other--net 1,603 (4,348)
--------- ---------
Net Cash Flow Provided By Financing Activities 225,862 237,241
--------- ---------
Net Cash Flow (14,760) 2,727
Cash and Cash Equivalents at Beginning of Period 28,619 10,363
--------- ---------
Cash and Cash Equivalents at End of Period $ 13,859 $ 13,090
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 57,935 $ 63,653
Income taxes $ 47,274 $ 15,954
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 the
Company and its subsidiaries: APS, Pinnacle West Energy, APSES, SunCor, and El
Dorado. All significant intercompany accounts and transactions have been
eliminated. We have reclassified certain prior year amounts to conform to the
current year presentation.
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 (see Note 10). 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 2001 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. On February 8, 2002, Pinnacle West issued $215 million of 4.5% Notes due
2004. On March 1, 2002, APS issued $375 million, of 6.5% Notes due 2012. On
April 15, 2002, APS redeemed $122 million of its First Mortgage Bonds, 8.75%
Series due 2024. On March 15, 2002, APS redeemed at maturity $125 million of its
First Mortgage Bonds, 8.125% Series due 2002. SunCor's long-term indebtedness
decreased $15 million during the six months ended June 30, 2002. The above items
represent the primary changes in capitalization for the six months ended June
30, 2002.
5. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW. On September 21, 1999, the ACC approved Rules that provide a
framework for the introduction of retail electric competition in Arizona. On
September 23, 1999, the ACC approved a comprehensive settlement agreement among
APS and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, APS is required to transfer all of its competitive electric assets
and services to an unaffiliated party or parties or to a separate corporate
affiliate or affiliates no later than December 31, 2002. Consistent with that
requirement, APS has been addressing the legal and regulatory requirements
necessary to complete the transfer of its generation assets to Pinnacle West
Energy on or before that date.
In January 2002, the ACC opened a "generic" docket to "determine if changed
circumstances require the [ACC] to take another look at electric restructuring
in Arizona." On June 17, 2002, hearings began on various issues ("Track A
-8-
Issues") in the consolidated docket. On July 23, 2002, an ACC ALJ issued a
recommended order on Track A Issues recommending, among other things, that the
ability of APS to transfer its generation assets be stayed until at least July
1, 2004. On August 1, 2002, APS filed exceptions to the recommended order
stating that it is unreasonable and unlawful. The ACC will hold an open meeting
on August 27, 2002 to consider Track A Issues. These matters are discussed in
more detail below.
1999 SETTLEMENT AGREEMENT. The following are the major provisions of the
1999 Settlement Agreement, as approved:
* 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% beginning July 1, 1999 through
July 1, 2003, for a total of 7.5%. The first reduction of
approximately $24 million ($14 million after income taxes) included a
July 1, 1999 retail price decrease of approximately $11 million ($7
million after income taxes) related to a 1996 regulatory agreement.
Based on the price reductions authorized in the 1999 Settlement
Agreement, there were also retail price decreases of approximately $28
million ($17 million after taxes), or 1.5%, effective July 1, 2000;
approximately $27 million ($16 million after taxes), or 1.5%,
effective July 1, 2001; and approximately $28 million ($17 million
after taxes), or 1.5%, effective July 1, 2002. For customers having
loads of three MW or greater, standard-offer rates have been reduced
in varying annual increments that total 5% in the years 1999 through
2002.
* Unbundled rates being charged by 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.
* 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.
* 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.
* 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
-9-
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.
* 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. APS will not be
allowed to recover $183 million net present value of the above
amounts. The 1999 Settlement Agreement provides that APS will have the
opportunity to recover $350 million net present value through a
competitive transition charge that will remain in effect through
December 31, 2004, at which time it will terminate. The costs subject
to recovery under the adjustment clause described above will be
decreased or increased by any over/under-recovery due to sales volume
variances.
* 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,
sixty-seven percent of its costs to accomplish the required transfer
of generation assets to an affiliate. Consistent with that
requirement, APS has been addressing the legal and regulatory
requirements necessary to complete the transfer of its generation
assets to Pinnacle West Energy on or before that date. However, as
noted above and discussed in greater detail below, an ACC ALJ has
recommended that APS' ability to transfer its generation assets be
stayed until at least July 1, 2004.
RETAIL ELECTRIC COMPETITION RULES. The Rules approved by the ACC include
the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by
the ACC, including APS.
* Effective January 1, 2001, retail access became available to all APS
retail electricity customers.
* Electric service providers that get CC&N's from the ACC can supply
only competitive services, including electric generation, but not
electric transmission and distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
noncompetitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
-10-
* 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.
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.
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 APSES, 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. 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 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.
PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. Commencing on the
transfer of the fossil-fueled generating assets and the receipt of certain
regulatory approvals, Pinnacle West Energy expects to sell its power at
-11-
wholesale to Pinnacle West's marketing and trading division, which, in turn, is
expected to sell power to APS and to non-affiliated power purchasers. In a
filing with the ACC on October 18, 2001, APS requested the ACC to:
* grant APS a partial variance from an ACC Rule that would obligate APS
to acquire all of its customers' standard-offer, full-service
generation requirements from the competitive market (with at least 50%
of those requirements coming from a "competitive bidding" process)
starting in 2003; and
* approve as just and reasonable a long-term purchase power agreement
between APS and Pinnacle West.
APS requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load.
GENERIC DOCKET. In January 2002, the ACC opened a "generic" docket to
"determine if changed circumstances require the [ACC] to take another look at
electric restructuring in Arizona." In February 2002, the ACC docket relating to
APS' October 2001 filing was consolidated with several other pending ACC
dockets, including the generic docket. On April 19, 2002, APS filed a motion in
the consolidated docket addressing the following issues, among others:
* APS confirmed its position that whether or not the ACC approved the
matters requested in its October 2001 filing, APS would proceed with
the divestiture of its generation assets by the end of 2002, as
legally required.
* APS also advised the ACC that whether or not the ACC approved the
matters requested in its October 2001 filing, APS would implement a
competitive bidding process later in 2002 to the extent legally
required.
* APS noted that Pinnacle West Energy, the affiliate to which APS
intends to transfer the generation assets, had committed to an
investment of approximately $1 billion in generating capacity to meet
APS customer needs in reliance on the 1999 Settlement Agreement. APS
further noted that it had taken numerous actions in reliance on the
1999 Settlement Agreement and the ACC Rules, including writing off
$234 million before income taxes of prudently incurred costs, reducing
retail rates in an ongoing series of rate reductions, and incurring
tens of millions of dollars in expenses related to the expected
generation asset transfer. APS stated that if the ACC elects to
reverse course on retail electric competition or attempts to stay the
transfer of APS' generation assets, the ACC would be legally required
to address just compensation to APS and Pinnacle West Energy, which
would include, at a minimum:
* recognizing the transfer to APS of all assets that Pinnacle West
Energy constructed to meet APS' load-serving requirements, and
-12-
subsequently including such units in APS' rate base in accordance
with traditional rate-of-return regulation;
* reversing APS' $234 million pre-tax write-off and providing for
the recovery of such amounts in future rates; and
* providing for the recovery of all costs incurred as a result of
the transition to competition, including 100 percent of the costs
incurred in preparation for divestiture (and not just the
sixty-seven percent of costs permitted under the 1999 Settlement
Agreement).
* APS recommended that the ACC confirm whether or not Arizona would
proceed with the transition to a competitive electric market, and
proposed a procedural plan in response to issues identified by the ACC
Staff in a previous report.
On April 26, 2002, the ACC issued a procedural order in which the ACC
stayed the previously-scheduled April 29, 2002 hearing on the matters raised in
APS' October 2001 ACC filing (see "Proposed Rule Variance and Purchase Power
Agreement" above). On May 2, 2002, the ACC issued a procedural order stating
that hearings would begin on June 17, 2002 on various issues ("Track A Issues"),
including APS' planned divestiture of generation assets to Pinnacle West Energy
and associated market and affiliate issues.
The procedural order also stated that consideration of the competitive
bidding process (the "Track B Issues") required by the Rules would proceed
concurrently with the Track A Issues. The objectives and process of the Track B
Issues would be determined in one or more meetings of affected parties with a
"target completion date" of October 21, 2002.
On July 11, 2002, APS filed a letter with the ACC discussing the
circumstances under which APS could support a temporary suspension or stay of
certain Arizona electric competition rules. In its letter, APS stated that it
could support a delay of the Rules' mandatory divestiture of generation assets
and competitive procurement requirements if:
* the ACC permits APS to end the "bifurcation" of its generation
resources as between itself and Pinnacle West Energy by authorizing
the acquisition by APS of the Pinnacle West Energy generating
facilities constructed or being constructed to serve APS;
* the ACC provides to APS any additional debt financing authorization
necessary to accomplish this acquisition; and
* while these assets remain at APS serving retail customers, their
inclusion in rates will be subject to ACC review as to their prudence
and as to whether they are "used and useful" just as are APS' existing
generating plants.
On July 23, 2002 an ACC ALJ issued a recommended order on Track A Issues in
the consolidated docket. Among other things, the ALJ recommends that:
-13-
* the ability of APS to transfer its generation assets be stayed until
the ACC determines that the wholesale market is "workably competitive"
and until at least July 1, 2004, at which time the ACC would reassess
the appropriateness and timing of divestiture;
* the current requirement that 100 percent of power purchased for
standard-offer service be acquired from the competitive market, with
at least 50 percent through a competitive bid process, be stayed
indefinitely; and
* upon implementation of the outcome of the competitive bidding process
("Track B Issues"), APS would acquire, at a minimum, any required
power not produced by its owned generation through a competitive
procurement process developed in the Track B proceeding.
In addition, the ALJ recommended that if APS wishes to acquire certain
generation assets from Pinnacle West Energy, as discussed in APS' July 11, 2002
letter to the ACC, APS should file appropriate applications on this matter for
ACC consideration.
The ALJ also recommended that the ACC Staff open a rulemaking to review the
Rules in light of the other decisions in the recommended order and that an
Electric Competition Advisory Group be formed to facilitate communication among
the ACC Staff, stakeholders and market participants.
On August 1, 2002, APS filed exceptions to the recommended order, stating
that the recommended order, if adopted by the ACC, would be unreasonable and
unlawful because, among other reasons:
* the recommended order's prohibition on APS transferring its generation
assets to Pinnacle West Energy would unfairly harm APS and the Company
by bifurcating generation assets between APS and Pinnacle West Energy,
even though those assets are devoted to serving APS customers;
* the recommended order's prohibition on APS transferring its generation
assets to Pinnacle West Energy would constitute a material breach of
the 1999 Settlement Agreement, even though APS has fulfilled its
obligations under the 1999 Settlement Agreement, including writing off
$234 million of otherwise recoverable costs, voluntarily reducing
retail rates by some $600 million (to date), and dismissing with
prejudice its pending litigation against the ACC;
* the recommended order does not discuss less onerous alternatives to
breaching the 1999 Settlement Agreement, such as consideration of the
Purchase Power Agreement proposed by APS in its October 18, 2001
filing with the ACC or the acquisition by APS of certain Pinnacle West
Energy generation assets, as outlined in APS' July 11, 2002 letter to
the ACC;
* the recommended order's finding that APS has wholesale market power in
certain Arizona geographical areas is not supported by the evidence
or, at worst, the ACC should make no finding on the issue of market
power; and
-14-
* the "generic proceedings" giving rise to the recommended order do not
and have not complied with Arizona law as applicable to the amendment
or rescission of the ACC order associated with the 1999 Settlement
Agreement.
The ACC will hold an open meeting on August 27, 2002 to consider Track A
Issues.
Pinnacle West cannot predict the outcome of the consolidated docket or its
effect on the existing Rules or the 1999 Settlement Agreement.
FEDERAL
In June 2001, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The plan, which has a price cap of approximately $90 per MWh,
remains in effect until September 30, 2002. FERC has now adopted a final price
cap of $250 per MWh, which will become effective as of October 1, 2002.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking Standard
Market Design for wholesale electric markets. We are reviewing the proposed
rulemaking and cannot currently predict what, if any, impact there may be to the
Company if the FERC adopts the proposed rule.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.
6. Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $200 million and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, 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 upon 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
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
-15-
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
7. Business Segments
We have two principal business segments (determined by products, services
and the regulatory environment), which consist of our regulated retail
electricity business, regulated traditional wholesale electricity business, and
related activities (electric retail business segment) and our competitive
business activities (marketing and trading business segment). Our electric
retail business segment includes activities related to electricity transmission
and distribution, as well as electricity generation. Our marketing and trading
business segment includes activities related to wholesale marketing and trading
and APSES' competitive energy services. The other amounts include activities
related to SunCor and El Dorado. Certain parent company costs, other than
marketing and trading, are included in our electric retail segment. Financial
data for the business segments follows (dollars in millions):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
----------------- ----------------- -----------------
2002 2001 2002 2001 2002 2001
------- ------- ------- ------- ------- -------
Operating Revenues:
Electric retail $ 497 $ 739 $ 877 $ 1,152 $ 2,287 $ 2,764
Marketing and trading 149 522 349 1,016 1,153 1,769
Other 69 33 110 65 215 145
------- ------- ------- ------- ------- -------
Total $ 715 $ 1,294 $ 1,336 $ 2,233 $ 3,655 $ 4,678
======= ======= ======= ======= ======= =======
Income Before
Accounting Change:
Electric retail $ 61 $ 11 $ 93 $ 14 $ 231 $ 152
Marketing and trading 9 56 29 114 86 143
Other 5 -- 7 1 10 (7)
------- ------- ------- ------- ------- -------
Total $ 75 $ 67 $ 129 $ 129 $ 327 $ 288
======= ======= ======= ======= ======= =======
As of As of
June 30, 2002 December 31, 2001
------------- -----------------
Assets:
Electric retail $7,367 $7,077
Marketing and trading 393 417
Other 483 488
------ ------
Total $8,243 $7,982
====== ======
8. Accounting Matters
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." We have no goodwill recorded and have separately disclosed
other intangible assets in our consolidated balance sheets. This new standard
has no material impact on our financial statements, and the required disclosures
are provided in Note 13.
-16-
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions for the disposal of
a segment of a business. This standard did not impact our financial statements
at adoption.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which we will adopt January 1, 2003. The standard
requires the fair value of asset retirement obligations to be recorded as a
liability, along with an offsetting plant asset, when the obligation is
incurred. Accretion of the liability due to the passage of time will be an
operating expense and the capitalized cost will be depreciated over the useful
life of the long-lived asset.
We have not yet determined the impact of the new standard on our financial
statements. We determined that we have asset retirement obligations for our
nuclear facilities (nuclear decommissioning) and certain other fossil
generation, transmission, and distribution assets. Upon adoption, we will record
the retirement obligations and the related plant assets and accumulated
depreciation. The impact of these adjustments will likely be different than the
removal costs currently reflected in our financial statements for assets that
have an asset retirement obligation. For our non-regulated operations, the
impact of adopting this new standard will be reflected in earnings as a
cumulative effect of a change in accounting principle. We are currently
evaluating our ability to recover the transition costs and ongoing current
period costs of SFAS No. 143 in rates for our regulated operations. If such
costs are expected to be recoverable in rates, we would recognize a regulatory
asset or regulatory liability upon the adoption of SFAS No. 143 rather than a
cumulative effect adjustment to earnings.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" which supersedes previous guidance for reporting gains and losses
from extinguishment of debt and accounting for leases, among other things. The
portion of the statement relating to the early extinguishment of debt is
effective for us beginning in 2003. We do not believe the adoption of this
statement will have a material impact on our financial statements.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." The standard requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The guidance should be applied prospectively to exit or disposal activities
initiated after December 31, 2002.
In 2001, the American Institute of Certified Public Accountants issued an
exposure draft of a proposed Statement of Position, "Accounting for Certain
Costs Related to Property, Plant, and Equipment." This proposed Statement of
Position, which would be effective for us in 2004, would create a project
timeline framework for capitalizing costs related to property, plant and
equipment construction. It would require that property, plant and equipment
assets be accounted for at the component level, and require administrative and
general costs incurred in support of capital projects to be expensed in the
current period. The American Institute of Certified Public Accountants plans to
issue the final Statement of Position in the fourth quarter of 2002.
-17-
In June 2002, the FASB's EITF finalized certain guidance related to energy
trading activities in EITF 02-3 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities." The new guidance, which is effective
July 1, 2002, requires that all energy trading activities within the scope of
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities," be presented on a net basis in revenues and that prior
period amounts should be restated to conform to the consensus. We will make this
presentation change in the third quarter of 2002. The impact on our marketing
and trading segment would result in equivalent decreases in revenues and
purchased power (gross margin would not be affected) for the three, six, and
twelve-month periods ended June 30, 2002 and 2001 as follows (dollars in
millions before income taxes):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
-------- -------- --------
2002 $ 99 $ 223 $ 869
2001 $ 288 $ 524 $ 999
Effective in the third quarter of 2002, we will record stock option expense
on our consolidated income statement in accordance with SFAS No. 123,
"Accounting For Stock-Based Compensation." We will utilize the transition
adjustment as provided in SFAS No. 123 and prospectively apply SFAS No. 123 to
2002 stock grants and future stock grants. The cumulative effect of adopting
this standard will be less than $1 million in 2002.
9. Off-Balance Sheet Financing
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. In July 2002, the
FASB issued an exposure draft related to SPEs. It is expected that the FASB will
issue final guidance on accounting for SPEs later this year with an immediate
effective date for newly-created entities and for all other entities as of the
beginning of the first fiscal period beginning April 1, 2003. We are currently
evaluating the impacts of the exposure draft and we may be required to
consolidate the Palo Verde SPEs in our financial statements. If consolidation
were required, the assets and liabilities of the SPEs that relate to the
sale-leaseback transactions would be reflected on our condensed consolidated
balance sheet at fair value. We are also evaluating the impact of including the
related fair value of assets and liabilities. The secured lease obligation bonds
that are not reflected on our condensed consolidated balance sheet at June 30,
2002 are approximately $285 million. The rating agencies have already considered
this debt when evaluating our credit ratings. This is our only significant
off-balance sheet financing activity.
-18-
10. Derivative Instruments
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We employ established procedures to manage risks associated with these market
fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity. In addition, subject
to specified risk parameters established by our Board of Directors and monitored
by our ERMC, we engage in trading activities intended to profit from market
price movements.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. We use cash flow hedges to limit our exposure to cash flow variability
on forecasted transactions. Hedge effectiveness is related to the degree to
which the derivative contract and the hedged item are correlated. It is measured
based on the relative changes in fair value between the derivative contract and
the hedged item over time. We exclude the time value of certain options from our
assessment of hedge effectiveness. Any change in the fair value resulting from
ineffectiveness is recognized immediately in net income.
On January 1, 2001, we recorded a $3 million after-tax loss in net income
and a $65 million after-tax gain in equity (as a component of other
comprehensive income), both as a cumulative effect of a change in accounting
principle. The gain resulted from unrealized gains on cash flow hedges.
In June 2001, the FASB issued new guidance related to electricity
contracts. The effective date of this new guidance was July 1, 2001. As of July
1, 2001, we recorded an additional $12 million after-tax loss in net income and
an additional $8 million after-tax gain in equity (as a component of other
comprehensive income), as a result of adopting the new guidance related to
electricity contracts. The loss resulted primarily from electricity options
contracts. The gain resulted from unrealized gains on cash flow hedges. The
impact of the new guidance is reflected in net income and other comprehensive
income as a cumulative effect of a change in accounting principle.
In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance was April 1, 2002. The impact of this
guidance was immaterial to our financial statements.
-19-
The change in derivative fair value included in the condensed consolidated
statements of income for the three, six and twelve months ended June 30, 2002
and 2001 are comprised of the following (dollars in thousands):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
-------------------- -------------------- --------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Gains (losses) on the ineffective
portion of derivatives
qualifying for hedge
accounting $ 4,471 $ (1,419) $ 1,923 $ (6,184) $ (263) $ (6,184)
Losses from the discontinuance of
cash flow hedges (724) (8,325) (1,624) (8,324) (2,824) (8,324)
Prior period mark-to-
market losses realized upon
delivery of commodities 2,209 85 6,022 6,478 25,491 6,478
-------- -------- -------- -------- -------- --------
Total pretax gain (loss) $ 5,956 $ (9,659) $ 6,321 $ (8,030) $ 22,404 $ (8,030)
======== ======== ======== ======== ======== ========
As of June 30, 2002, the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is thirty months. During the twelve months ending June 30, 2003, we estimate
that a net loss of $14 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 following table summarizes our assets and liabilities from risk
management and trading activities related to trading and system (retail and
traditional wholesale activities) as of June 30, 2002 (dollars in thousands):
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
------ ----------- ----------- ----------- -----------
Mark-to-
market:
Trading $ 32,815 $ 118,873 $ (5,770) $ (12,541) $ 133,377
System 14,789 2,259 (23,307) (46,996) (53,255)
Cost-emission
allowances and
other -- 97,778(a) -- (51,090) 46,688
--------- --------- --------- --------- ---------
Total $ 47,604 $ 218,910 $ (29,077) $(110,627) $ 126,810
========= ========= ========= ========= =========
(a) Includes $19 million required to serve as collateral against our open
positions on energy-related contracts.
-20-
11. Comprehensive Income
Components of comprehensive income for the three, six and twelve months
ended June 30, 2002 and 2001, are as follows (dollars in thousands):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
---------------------- ---------------------- ----------------------
2002 2001 2002 2001 2002 2001
--------- --------- --------- --------- --------- ---------
Net income $ 75,365 $ 66,857 $ 129,122 $ 126,307 $ 314,981 $ 284,668
--------- --------- --------- --------- --------- ---------
Other comprehensive income
(loss):
Minimum pension liability,
net of tax (1,835) -- (1,835) -- (2,801) --
Cumulative effect of change
in accounting for
derivatives, net of tax -- -- -- 64,700 7,801 64,700
Unrealized gains (losses)
on derivative
instruments, net of tax(a) 1,386 (87,475) 24,758 (94,134) 14,108 (94,134)
Reclassification of net
realized (gains) losses
to income, net of tax (b) 736 (1,862) 5,180 (22,478) (3,659) (22,478)
--------- --------- --------- --------- --------- ---------
Total other comprehensive
income (loss) 287 (89,337) 28,103 (51,912) 15,449 (51,912)
--------- --------- --------- --------- --------- ---------
Comprehensive income (loss) $ 75,652 $ (22,480) $ 157,225 $ 74,395 $ 330,430 $ 232,756
========= ========= ========= ========= ========= =========
(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 contracts that delivered during the period.
-21-
12. Commitments and Contingencies
California Energy Market Issues and Refunds in the Pacific Northwest
In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC also
ordered an evidentiary proceeding to discuss and evaluate possible refunds for
the Pacific Northwest. The administrative law judge at the FERC in charge of
that evidentiary proceeding made an initial finding that no refunds were
appropriate. The Pacific Northwest issues will now be addressed by the FERC
Commissioners. Although the FERC has not yet made a final ruling in the Pacific
Northwest matter or calculated the specific refund amounts due in California, we
do not expect that the resolution of these issues, as to the amounts alleged in
the proceedings, will have a material adverse impact on our financial position,
results of operations or liquidity.
SCE and PG&E have publicly disclosed that their liquidity has been
materially and adversely affected because of, among other things, their
inability to pass on to ratepayers the prices each has paid for energy and
ancillary services procured through the PX and the ISO. PG&E filed for
bankruptcy protection in 2001.
We are closely monitoring developments in the California energy market and
the potential impact of these developments on us and our subsidiaries. We have
evaluated, among other things, SCE's role as a Palo Verde and Four Corners
participant; APS' transactions with the PX and the ISO; contractual
relationships with SCE and PG&E; APSES' retail transactions involving SCE and
PG&E; and marketing and trading exposures. 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. After review with legal counsel and
review of bond pricing, the $10 million reserve was our best estimate of our
losses.
In the first quarter of 2002, SCE paid all of its outstanding debts to
APSES. 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 Pinnacle West, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the
-22-
present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET. AL., Docket
No. EL02-71-000. The complaint requests the FERC to require the wholesale
sellers to refund any rates that are "found to exceed just and reasonable
levels." This complaint has been dismissed by FERC. 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 California 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 California 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. 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 Resources, based upon an alleged
conflict of interest arising from the activities of a consultant for Edison
International who also negotiated long-term contracts for the California
Department of Water Resources. MCCLINTOCK, ET AL. V. YUDHRAJA, Superior Court in
and for the County of Los Angeles, Case No. GC 029447. The California Attorney
General has indicated that an investigation by his office did not find evidence
of improper conduct by the consultant. We believe the claims against us in the
lawsuits mentioned in this paragraph are without merit and will have no material
adverse impact on our financial position, results of operations or liquidity.
Power Service Agreement
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised APS that it believes APS has overcharged Citizens by over $50 million
under a power service agreement. APS believes that 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 that,
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 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.
-23-
13. Intangible Assets
On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." The Company's gross intangible assets (which are primarily
software) were $196 million at June 30, 2002 and $175 million at December 31,
2001. The related accumulated amortization was $97 million at June 30, 2002 and
$88 million at December 31, 2001. Amortization expense for the three-month
period ended June 30 was $5 million in 2002 and 2001. Amortization expense for
the six-month period ended June 30 was $9 million in 2002 and $11 million in
2001. Amortization expense for the twelve-month period ended June 30 was $21
million in 2002 and 2001. Estimated amortization expense on existing intangible
assets over the next five years is $17 million in 2002, $16 million in 2003, $15
million in 2004, $13 million in 2005 and $11 million in 2006.
14. El Dorado Investment in Nuclear Assurance Corporation
El Dorado has an equity interest in NAC. NAC develops, markets and
contracts for the manufacture of spent nuclear fuel storage and transportation
cask designs. El Dorado's investment in NAC is accounted for under the equity
method and El Dorado's share of earnings and losses through June 2002 were
recorded in other income or expense in the condensed consolidated income
statement. Beginning in the third quarter of 2002, El Dorado will fully
consolidate NAC's financial statements because it now has a controlling interest
in NAC. As of December 31, 2001, NAC's total assets were approximately $34
million. NAC's total revenues were $74 million and its pretax net loss was $13
million for the year ended December 31, 2001. In addition, on June 26, 2002, NAC
entered into a Convertible Promissory Note with El Dorado in the amount of $30
million at a rate of LIBOR plus 4.75% per annum. There was $5 million
outstanding as of June 30, 2002. Pinnacle West provides guarantees for credit
support related to NAC in the cumulative amount of $51 million, $8 million of
which relates to NAC debt that is expected to be repaid in August 2002 with
borrowings under the El Dorado Convertible Promissory Note.
-24-
15. Earnings Per Share
The following table presents earnings per weighted average common share
outstanding (EPS):
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
------------- ------------- --------------
2002 2001 2002 2001 2002 2001
----- ----- ----- ----- ----- -----
Basic EPS:
Income before accounting change $0.89 $0.79 $1.52 $1.52 $3.86 $3.39
Cumulative effect of change in
accounting -- -- -- (0.03) (0.14) (0.03)
----- ----- ----- ----- ----- -----
Earnings per share - basic $0.89 $0.79 $1.52 $1.49 $3.72 $3.36
===== ===== ===== ===== ===== =====
Diluted EPS:
Income before accounting change $0.89 $0.79 $1.52 $1.52 $3.86 $3.38
Cumulative effect of change in
accounting -- -- -- (0.03) (0.15) (0.03)
----- ----- ----- ----- ----- -----
Earnings per share - diluted $0.89 $0.79 $1.52 $1.49 $3.71 $3.35
===== ===== ===== ===== ===== =====
The following table reconciles average common shares outstanding - basic to
average common shares outstanding - diluted that are used in the EPS calculation
to the condensed consolidated income statement (in thousands):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
--------------- --------------- ---------------
2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------
Average common shares
outstanding -
basic 84,794 84,744 84,769 84,736 84,734 84,736
Dilutive stock options 132 298 141 269 154 271
------ ------ ------ ------ ------ ------
Average common
shares outstanding -
diluted 84,926 85,042 84,910 85,005 84,888 85,007
====== ====== ====== ====== ====== ======
-25-
16. Other Income and Other Expense
The following table provides detail of other income and other expense for
the three, six and twelve months ended June 30, 2002 and 2001 (dollars in
thousands):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
-------------------- -------------------- --------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Other income:
Environmental insurance
recovery $ -- $ 10,947 $ -- $ 10,947 $ 1,402 $ 10,947
APSES non-commodity revenues 2,881 1,252 7,157 2,620 15,974 5,552
Interest income 693 2,170 1,886 3,150 6,306 8,568
Suncor joint venture earnings 2,446 1,301 3,399 2,481 1,768 3,576
Miscellaneous 1,053 346 1,991 776 3,250 3,456
-------- -------- -------- -------- -------- --------
Total other income $ 7,073 $ 16,016 $ 14,433 $ 19,974 $ 28,700 $ 32,099
======== ======== ======== ======== ======== ========
Other expense:
Investment losses - net (a) $ (6,075) $ (2,946) $ (4,359) $ (2,003) $ (5,269) $(27,971)
APSES non-commodity expenses (1,669) (133) (4,969) (918) (14,097) (1,469)
Non-operating costs - Suncor -- (4,500) -- (4,500) (2,500) (4,500)
Non-operating costs (b) (6,156) (2,995) (9,163) (6,749) (20,537) (16,480)
Miscellaneous (866) (2,205) (2,547) (3,305) (1,166) (8,043)
-------- -------- -------- -------- -------- --------
Total other expense $(14,766) $(12,779) $(21,038) $(17,475) $(43,569) $(58,463)
======== ======== ======== ======== ======== ========
(a) Primarily related to El Dorado's investments.
(b) Primarily below the line utility costs.
-26-
PINNACLE WEST CAPITAL CORPORATION
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
INTRODUCTION
In this section, 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:
* the changes in our earnings for the three, six and twelve months ended
June 30, 2002 and 2001;
* the effects of regulatory agreements and developments on our results
and outlook;
* our capital needs, liquidity and capital resources;
* our business outlook; and
* our management of market risks.
We suggest this section be read along with the 2001 10-K. Throughout this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, we refer to specific "Notes" in the Notes to Condensed Consolidated
Financial Statements in this report. These Notes add further details to the
discussion. Operating statistics for the periods ended June 30, 2002 and June
30, 2001 are available on our website (www.pinnaclewest.com) and in our Current
Report on Form 8-K dated June 30, 2002.
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 provided through a distribution system owned by APS. APS also
generates and, through our marketing and trading division, sells and delivers
electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* APSES, which provides 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;
* SunCor, a developer of residential, commercial, and industrial real
estate projects in Arizona, New Mexico, and Utah;
* Pinnacle West Energy, through which we conduct our unregulated
electricity generation operations; and
-27-
* El Dorado, an investment firm.
Pinnacle West's marketing and trading division sells in the wholesale
market, the APS and Pinnacle West Energy generation production output that is
not needed for APS' Native Load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. Subject to specified risk
parameters established by our Board of Directors, the marketing and trading
division also engages in activities to hedge purchases and sales of electricity,
fuels, and emissions allowances and credits and to profit from market price
movements. We explain in detail the historical and prospective contribution of
marketing and trading activities to our financial results. APS completed the
transition of marketing and trading activities to the parent company as of the
end of 2001.
APS is required to transfer its competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, APS has been addressing the legal and regulatory
requirements necessary to complete the transfer of its generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail in Note
5, on July 23, 2002, an ACC ALJ issued a recommended order recommending, among
other things, that the ability of APS to transfer its generation assets be
stayed until at least July 1, 2004.
EARNINGS CONTRIBUTIONS BY SUBSIDIARY
The following table summarizes net income for the three, six and twelve
months ended June 30, 2002 and the comparable prior-year periods for Pinnacle
West and each of our subsidiaries (dollars in millions, unaudited):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
-------------- -------------- --------------
2002 2001 2002 2001 2002 2001
----- ----- ----- ----- ----- -----
APS $ 64 $ 70 $ 96 $ 134 $ 243 $ 312
APSES - pre tax 11 -- 13 (7) 11 (17)
SunCor 8 -- 10 -- 13 6
Pinnacle West Energy 1 1 2 1 19 --
El Dorado (3) -- (3) -- (3) (14)
Parent company (a) (6) (4) 11 1 44 1
----- ----- ----- ----- ----- -----
Income before accounting change 75 67 129 129 327 288
Cumulative effect of change
in accounting - net of
income taxes -- -- -- (3) (12) (3)
----- ----- ----- ----- ----- -----
Net income $ 75 $ 67 $ 129 $ 126 $ 315 $ 285
===== ===== ===== ===== ===== =====
(a) These amounts primarily include marketing and trading activities. APS
amounts also included some marketing and trading activities in 2001,
although APS completed the transition of such activities to the parent
company as of the end of 2001.
-28-
BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and the regulatory environment), which consist of our regulated retail
electricity business, regulated traditional wholesale electricity business, and
related activities (electric retail business segment) and our competitive
business activities (marketing and trading business segment). Our electric
retail business segment includes activities related to electricity transmission
and distribution, as well as electricity generation. Our marketing and trading
business segment includes activities related to wholesale marketing and trading
and APSES' competitive energy services. The other amounts include activities
related to SunCor and El Dorado. The parent company, other than marketing and
trading, is included in our electric retail segment.
The following table summarizes net income by business segment for the
three, six and twelve months ended June 30, 2002 and the comparable prior year
periods (dollars in millions, unaudited):
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
------------- ------------- --------------
2002 2001 2002 2001 2002 2001
----- ----- ----- ----- ----- -----
Electric retail $ 61 $ 11 $ 93 $ 14 $ 231 $ 152
Marketing and trading 9 56 29 114 86 143
Other 5 -- 7 1 10 (7)
----- ----- ----- ----- ----- -----
Income before accounting
change 75 67 129 129 327 288
Cumulative effect of change
in accounting - net of
income taxes -- -- -- (3) (12) (3)
----- ----- ----- ----- ----- -----
Net income $ 75 $ 67 $ 129 $ 126 $ 315 $ 285
===== ===== ===== ===== ===== =====
We recorded the cumulative effects of a change in accounting for
derivatives related to our adoption in 2001 of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities."
EARNINGS VARIANCE EXPLANATIONS
Throughout these explanations, we refer to "gross margin." With respect to
our electric retail segment and marketing and trading segment, gross margin
refers to electric operating revenues less purchased power and fuel costs. Real
estate gross margin refers to real estate revenues less real estate operations
costs.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED JUNE 30, 2002 COMPARED WITH
THREE-MONTH PERIOD ENDED JUNE 30, 2001
Our consolidated net income for the three months ended June 30, 2002 was
$75 million compared with $67 million for the same period in the prior year. The
period-to-period increase was primarily the result of increased earnings
contributions from our regulated retail electricity and real estate operations
-29-
that were partially offset by lower earnings contributions from our marketing
and trading activities. The retail comparison was favorably impacted by lower
replacement costs for power plant outages, lower costs for purchased power and
gas related to lower market prices, customer growth and higher average usage per
customer, partially offset by the effects of milder weather. The real estate
results benefited primarily from more sales activities. The comparison for
marketing and trading activities reflects lower volumes and prices in the
wholesale power markets in the western United States.
-30-
The major factors that increased (decreased) net income were as follows (dollars
in millions):
Increase
(Decrease)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages $ 58
Lower purchased power and fuel costs related to lower prices,
net of hedge management sales 46
Effects of milder weather on retail sales (16)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 12
Retail price reductions effective July 1, 2001 (7)
Miscellaneous factors - net (5)
----
Net increase in electric retail segment gross margin 88
----
Marketing and trading segment gross margin:
Decrease in generation sales other than native load due to lower
market prices and resulting lower sales volumes (26)
Decrease in other realized marketing and trading in the current
period primarily due to lower unit margins on increased
volumes (6)(a)
Change in prior period mark-to-market gains on contracts delivered
during the current period (b) (14)(a)
Lower mark-to-market gains for future period deliveries (b) (33)
----
Net decrease in marketing and trading gross margin (79)
----
Total increase in the electric retail and the marketing and trading
segments' gross margins 9
Higher real estate gross margin primarily due to increased sales
activities 13
Lower operations and maintenance expense primarily related to lower
generation reliability costs partially offset by higher other costs 3
Lower depreciation and amortization expense primarily related to lower
regulatory asset amortization 4
Lower other income (9)
Miscellaneous items, net (6)
----
Increase in income before income taxes 14
Higher income taxes primarily due to higher pretax income (6)
----
Increase in net income $ 8
====
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) recognized for the current period decreased $20
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is
economically hedged with a portfolio of forward purchases that protects the
economic value of the sales transactions.
-31-
Electric Retail Segment Gross Margin
Revenues related to our regulated retail and wholesale electricity
businesses were $242 million lower in the three-month period ended June 30,
2002, compared to the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($54 million);
* decreased revenues related to retail load hedge management wholesale
sales, as a result of lower sales volumes and lower prices ($171
million);
* decreased retail revenues related to milder weather ($26 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($21 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($7 million); and
* other miscellaneous factors ($5 million net decrease).
Electric retail segment purchased power and fuel costs were $330 million
lower in the three-month period ended June 30, 2002, compared to the same period
in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($54 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power ($217 million);
* decreased costs related to the effects of milder weather on retail
sales ($10 million);
* increased costs related to retail sales growth excluding weather
effects ($9 million); and
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($58 million).
Marketing and Trading Segment Gross Margin
Marketing and trading segment revenues were $373 million lower in the
three-month period ended June 30, 2002, compared to the same period in the prior
year as a result of:
* decreased revenues from generation sales other than native load due to
lower market prices and resulting lower sales volumes ($49 million);
* decreased realized revenues from other realized marketing and trading
in the current period primarily due to lower prices ($277 million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to higher volumes being delivered ($13
million decrease); and
* lower mark-to-market gains for future period deliveries primarily as a
result of lower market liquidity and lower price volatility, resulting
in lower volumes ($34 million).
-32-
Marketing and trading segment purchased power and fuel costs were $294
million lower in the three-month period ended June 30, 2002, compared to the
same period in the prior year as a result of:
* decreased fuel costs related to generation sales other than native
load primarily because of lower sales volumes and lower natural gas
prices ($23 million); and
* decreased purchased power costs related to other realized marketing
and trading in the current period primarily due to lower prices ($271
million).
The increase in real estate gross margin of $13 million was primarily due
to increased sales activities.
The decrease in operations and maintenance expense of $3 million was due to
lower costs related to generation reliability, plant outages and maintenance
costs. Operations and maintenance expense was also lower as a result of the
reversal of $4 million of a $10 million reserve for the California energy
situation. These factors were partially offset with increased employee and other
costs. See Note 12 for a discussion of California energy market issues.
The decrease in depreciation and amortization expense of $4 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 regulatory settlement, partially offset by increased depreciation on
higher plant balances.
Other income decreased $9 million primarily due to an insurance recovery
recorded in the prior period related to environmental remediation costs.
OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 2002 COMPARED WITH SIX-MONTH
PERIOD ENDED JUNE 30, 2001
Our consolidated net income for the six months ended June 30, 2002 was $129
million compared with $126 million for the same period in the prior year. We
recognized a $3 million after-tax loss in the six months ended June 30, 2001 as
a cumulative effect of a change in accounting for derivatives, as required by
SFAS No.133.
Our income before accounting change for the six months ended June 30, 2002
and 2001 was $129 million in both periods. The period-to-period activity was the
result of increased earnings contributions from our regulated retail electricity
and real estate operations that were partially offset by lower earnings
contributions from our marketing and trading activities. The retail comparison
was favorably impacted by lower replacement costs for power plant outages, lower
costs for purchased power and gas related to lower market prices, customer
growth and higher average usage per customer, partially offset by the effects of
milder weather and a retail electricity price decrease. The real estate results
benefited primarily from more sales activities. The comparison for marketing and
trading activities reflects lower volumes and prices in the wholesale power
markets in the western United States.
-33-
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages $ 108
Lower purchased power and fuel costs related to lower prices,
net of hedge management sales 36
Effects of milder weather on retail sales (22)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 17
Retail price reductions effective July 1, 2001 (13)
Miscellaneous factors - net (3)
-----
Net increase in electric retail segment gross margin 123
-----
Marketing and trading segment gross margin:
Decrease in generation sales other than native load due to lower
market prices and resulting lower sales volumes (71)
Increase in other realized marketing and trading in the current
period primarily due to higher unit margins on increased
volumes 31(a)
Change in prior period mark-to-market gains on contracts
delivered during the current period (b) (45)(a)
Lower mark-to-market gains for future period deliveries (b) (61)
-----
Net decrease in marketing and trading gross margin (146)
-----
Total decrease in the electric retail and the marketing and trading
segments' gross margins (23)
Higher real estate gross margin primarily due to increased sales
activities 15
Lower operations and maintenance expense primarily related to lower
generation reliability costs partially offset by higher other costs 11
Lower depreciation and amortization primarily due to lower regulatory
asset amortization 9
Lower other income (6)
Miscellaneous items, net (6)
-----
Change in income before income taxes --
Change in income taxes --
-----
Change in income before accounting change $ --
=====
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) recognized for the current period decreased $14
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is
economically hedged with a portfolio of forward purchases that protects the
economic value of the sales transactions.
-34-
Electric Retail Segment Gross Margin
Revenues related to our regulated retail and wholesale electricity
businesses were $275 million lower in the six-month period ended June 30, 2002,
compared to the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($79 million);
* decreased revenues related to retail load hedge management wholesale
sales, as a result of lower sales volumes and lower prices ($174
million);
* decreased retail revenues related to milder weather ($35 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($29 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($13 million); and
* other miscellaneous factors ($3 million net decrease).
Electric retail segment purchased power and fuel costs were $398 million
lower in the six-month period ended June 30, 2002, compared to the same period
in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($79 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power ($210 million);
* decreased costs related to the effects of milder weather on retail
sales ($13 million);
* increased costs related to retail sales growth, excluding weather
effects ($12 million); and
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($108 million).
Marketing and Trading Segment Gross Margin
Marketing and trading segment revenues were $667 million lower in the
six-month period ended June 30, 2002, compared to the same period in the prior
year as a result of:
* decreased revenues from generation sales other than native load due to
lower market prices and resulting lower sales volumes ($128 million);
* decreased revenues from other realized marketing and trading in the
current period primarily due to lower prices ($441 million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to higher volumes being delivered ($37
million decrease); and
* lower mark-to-market gains for future period deliveries primarily as a
result of lower market liquidity and lower price volatility, resulting
in lower volumes ($61 million).
-35-
Marketing and trading segment purchased power and fuel costs were $521
million lower in the six-month period ended June 30, 2002, compared to the same
period in the prior year as a result of:
* decreased fuel costs related to generation sales other than native
load primarily because of lower sales volumes and lower natural gas
prices ($57 million);
* decreased purchased power costs related to other realized marketing
and trading in the current period primarily due to lower prices ($472
million); and
* change in prior period mark-to-market fuel costs for current period
deliveries ($8 million net increase).
The increase in real estate gross margin of $15 million was primarily due
to increased sales activities.
The decrease in operations and maintenance expense of $11 million was
primarily due to lower costs related to generation reliability, plant outages
and maintenance costs. Operation and maintenance expense was also lower as a
result of the reversal of $4 million of a $10 million reserve recorded in the
prior period for the California energy situation. These decreases were partially
offset by increased employee benefit and other costs. See Note 12 for a
discussion of California energy market issues.
The decrease in depreciation and amortization expense of $9 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 regulatory settlement, partially offset by increased depreciation on
higher plant balances.
Other income decreased $6 million primarily due to an insurance recovery
recorded in the prior period related to environmental remediation costs,
partially offset by higher miscellaneous non-operating revenues in the current
period.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 2002 COMPARED WITH
TWELVE-MONTH PERIOD ENDED JUNE 30, 2001
Our consolidated net income for the twelve months ended June 30, 2002 was
$315 million compared with $285 million for the same period in the prior year.
We recognized a $12 million after-tax loss in the twelve months ended June 30,
2002 and a $3 million after-tax loss in the twelve months ended June 30, 2001 as
cumulative effects of a change in accounting for derivatives, as required by
SFAS No.133.
Our income before accounting change for the twelve months ended June 30,
2002 was $327 million compared with $288 million for the same period a year
earlier. The period-to-period comparison benefited from increased earnings
contributions from our regulated retail electricity and real estate operations
that were partially offset by lower earnings contributions from our marketing
and trading activities and higher operations and maintenance expenses. The
retail comparison was favorably impacted by lower replacement costs for power
plant outages, lower costs for purchased power and gas related to lower market
prices, customer growth and higher average usage per customer, partially offset
by the effects of milder weather and a retail electricity price decrease. The
real estate results benefited primarily from more sales activities. The
comparison for marketing and trading activities reflects lower volumes and
prices in the wholesale power markets in the western United States.
-36-
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages $ 126
Lower purchased power and fuel costs related to lower prices,
net of hedge management sales 33
Effects of milder weather on retail sales (9)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 27
Retail price reductions effective July 1, 2001 (28)
Miscellaneous factors - net (1)
-----
Net increase in electric retail segment gross margin 148
-----
Marketing and trading segment gross margin:
Decrease in generation sales other than native load due to lower
market prices and resulting lower sales volumes (112)
Increase in other realized marketing and trading in the current
period primarily due to higher unit margins on increased
volumes 72(a)
Change in prior period mark-to-market gains on contracts
delivered during the current period (b) (88)(a)
Higher mark-to-market gains for future period deliveries (b) 36
-----
Net decrease in marketing and trading gross margin (92)
-----
Total increase in the electric retail and the marketing and trading
segments' gross margins 56
Higher real estate gross margin primarily due to increased sales
activities 16
Higher operations and maintenance expense primarily related to higher
generation
reliability costs partially offset by lower other costs (29)
Lower depreciation and amortization primarily due to lower regulatory
asset amortization 12
Lower other income (3)
Lower other expense 15
Lower net interest expense primarily due to higher capitalized interest 7
Miscellaneous items, net (6)
-----
Increase in income before income taxes 68
Higher income taxes primarily due to higher income (29)
-----
Increase in income before accounting change $ 39
=====
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) recognized for the current period decreased $16
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is
economically hedged with a portfolio of forward purchases that protects the
economic value of the sales transactions.
-37-
Electric Retail Segment Gross Margin
Revenues related to our regulated retail and wholesale electricity
businesses were $477 million lower in the twelve-month period ended June 30,
2002, compared to the same period in the prior year as a result of:
* decreased revenues related to traditional wholesale sales as a result
of lower sales volumes and lower prices ($177 million);
* decreased revenues related to wholesale sales, as a result of lower
sales volumes and lower prices ($301 million);
* decreased retail revenues related to milder weather ($14 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($44 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($28 million); and
* other miscellaneous factors ($1 million net decrease).
Electric retail segment purchased power and fuel costs were $625 million
lower in the twelve-month period ended June 30, 2002, compared to the same
period in the prior year as a result of:
* decreased costs related to traditional wholesale sales as a result of
lower sales volumes and lower prices ($177 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power prices ($331 million);
* decreased costs related to the effects of milder weather on retail
sales ($5 million);
* increased costs related to retail sales growth, excluding weather
effects ($17 million);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($126 million); and
* miscellaneous factors ($3 million net decrease).
Marketing and Trading Segment Gross Margin
Marketing and trading segment revenues were $616 million lower in the
twelve-month period ended June 30, 2002, compared to the same period in the
prior year as a result of:
* decreased revenues from generation sales other than native load due to
lower market prices and resulting lower sales volumes ($212 million);
* decreased revenues from other realized marketing and trading in the
current period primarily due to lower prices ($359 million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to higher volumes being delivered ($80
million decrease); and
-38-
* higher mark-to-market gains for future period deliveries primarily as
a result of greater market liquidity and greater price volatility,
resulting in higher volumes ($35 million).
Marketing and trading segment purchased power and fuel costs were $524
million lower in the twelve-month period ended June 30, 2002, compared to the
same period in the prior year as a result of:
* decreased fuel costs related to generation sales other than native
load primarily because of lower sales volumes and lower natural gas
prices ($100 million);
* decreased purchased power costs related to other realized marketing
and trading in the current period primarily due to lower prices ($431
million);
* change in prior period mark-to-market fuel costs for current period
deliveries related to accounting for derivatives ($8 million
increase); and
* other miscellaneous factors ($1 million decrease).
The increase in real estate gross margin of $16 million was primarily due
to increased sales activities.
The increase in operations and maintenance expense of $29 million was
primarily due to higher costs related to generation reliability, plant outages
and maintenance costs. Operations and maintenance expense was also higher due to
increased employee benefit and other costs. These factors were partially offset
as a result of the reversal of $4 million of a $10 million reserve recorded in
the prior period for the California energy situation. See Note 12 for a
discussion of California energy market issues.
The decrease in depreciation and amortization expenses of $12 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 regulatory settlement, partially offset by increased depreciation on
higher plant balances.
Other income decreased $3 million primarily due to the effects of an
insurance recovery recorded in the prior period related to environmental
remediation costs, partially offset by higher miscellaneous non-operating
revenues in the current period.
Other expense decreased $15 million primarily due to lower losses recorded
on El Dorado's investment in the current period, partially offset by higher
miscellaneous non-operating expenses in the current period.
Net interest expense decreased $7 million primarily because of the increase
in capitalized interest on our generation expansion program and the effects of
lower interest rates. These reductions in net interest expense more than offset
the increase in interest expense on higher debt balances primarily related to
our generation expansion program.
-39-
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the six
months ended June 30, 2002 and estimated capital expenditures for the next three
years (dollars in millions):
Six Months
Ended Estimated
June 30, ----------------------------
2002 2002 2003 2004
------ ------ ------ ------
APS
Delivery $ 182 $ 347 $ 270 $ 267
Existing generation (a) 70 149 -- --
------ ------ ------ ------
Subtotal 252 496 270 267
------ ------ ------ ------
Pinnacle West Energy (b)
Generation expansion 197 411 257 109(e)
Existing generation (a) -- -- 116 89
------ ------ ------ ------
Subtotal 197 411 373 198
------ ------ ------ ------
SunCor (c) 39 79 48 52
Other (d) 16 38 22 21
------ ------ ------ ------
Total $ 504 $1,024 $ 713 $ 538
====== ====== ====== ======
(a) Pursuant to the 1999 Settlement Agreement, APS is required to transfer its
competitive electric assets and services no later than December 31, 2002.
As we discuss in greater detail in Note 5, on July 23, 2002, an ACC ALJ
issued a recommended order recommending, among other things, that the
ability of APS to transfer its generation assets be stayed until at least
July 1, 2004.
(b) See further discussion below of Pinnacle West Energy's generation expansion
program and "Capital Resources and Cash Requirements - Pinnacle West
Energy" below.
(c) Consists primarily of capital expenditures for land development and retail
and office building construction and is included in the "Increase in real
estate investments" in the condensed consolidated statements of cash flows.
(d) Primarily Pinnacle West and APSES.
(e) This amount does not include an expected reimbursement by SNWA of
approximately $100 million of these costs in 2004 in exchange for SNWA's
option to purchase a 25% interest in the Silverhawk project at that time.
Several years ago APS and the other Palo Verde participants decided to
replace Unit 2 steam generators, which replacement is presently scheduled to be
completed in the fall of 2003. APS and the other Palo Verde participants are
currently considering issues related to replacement of the steam generators in
Units 1 and 3. Although a final determination of whether Units 1 and 3 will
require steam generator replacement to operate over their current full licensed
lives has not yet been made, APS and the other participants have approved
-40-
fabrication of one set of spare steam generators. APS' portion of this
expenditure is approximately $27 million, which will be spent from 2002 to 2005.
The capital expenditure table above includes $21 million of the costs in 2002
through 2004. If the Palo Verde participants decide to proceed with steam
generator replacement at both Units 1 and 3, we have estimated that our portion
of the fabrication and installation costs and associated power uprate
modifications would be approximately $130 million over the next seven years,
which would be funded with internally-generated cash or external financings.
Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants. Examples of the types
of projects included in this category are additions, upgrades and capital
replacements of various power plant equipment such as turbines, boilers, and
environmental equipment. The existing generation also contains nuclear fuel
expenditures of approximately $30 million annually in 2002, 2003, and 2004.
Delivery capital expenditures are comprised of T&D infrastructure additions
and upgrades, capital replacements, new customer construction, and related
information systems and facility costs. Examples of the types of projects
included in the forecast include T&D lines and substations, line extensions to
new residential and commercial developments, and upgrades to customer
information systems. In addition, we began several major transmission projects
in 2001. These projects are periodic in nature and are driven by strong regional
customer growth. We expect to spend about $150 million on major transmission
projects during the 2002-2004 time frame.
CAPITAL RESOURCES AND CASH REQUIREMENTS
The following table summarizes actual cash commitments for the six months
ended June 30, 2002 and estimated commitments for the next five years and
thereafter (dollars in millions):
Six Estimated
Months Years Ended December 31,
Ended ---------------------------------------------------
June 30, There
2002 2002 2003 2004 2005 2006 -after
------ ------ ------ ------ ------ ------ ------
Long-term debt payments
APS $ 247 $ 247 $ -- $ 205 $ 400 $ 84 $1,518
Pinnacle West -- 1 276 216 -- 300 --
SunCor 15 15 38 76 -- 3 16
------ ------ ------ ------ ------ ------ ------
Total long-term debt payments 262 263 314 497 400 387 1,534
Operating leases payments 43 68 66 65 64 63 550
Fuel and purchase power commitments 102 318 132 83 65 68 170
------ ------ ------ ------ ------ ------ ------
Total cash commitments (a) $ 407 $ 649 $ 512 $ 645 $ 529 $ 518 $2,254
====== ====== ====== ====== ====== ====== ======
(a) Total cash commitments are approximately $5.1 billion. The total net
present value of these cash commitments is $2.9 billion.
-41-
Our significant debt covenants related to our financing arrangements
include a debt to total capitalization ratio and interest coverage test. We are
in compliance with such convenants and we anticipate that we will continue to
meet all the significant covenant requirement levels. The repercussions of not
meeting the covenants would result in an event of default which, generally
speaking, would require the immediate repayment of the debt subject to the
covenants. All of our bank agreements have cross-default provisions.
We have issued parental guarantees and obtained surety bonds on behalf of
our unregulated subsidiaries. The credit support instruments enable Pinnacle
West Energy to continue its generation expansion plan, enable APSES to provide
commodity energy and energy-related products and enable El Dorado to support the
activities of NAC. The amounts as of June 30, 2002 are listed as follows
(dollars in millions):
Guarantees Surety Bonds
---------- ------------
Pinnacle West Energy $ 305 $ --
APSES 72 44
El Dorado 51 --
In addition, SunCor has provided guarantees of approximately $24 million on
behalf of affiliated joint ventures.
PINNACLE WEST
The parent company's cash requirements and its ability to fund those
requirements are discussed under "Capital Needs and Resources" in Management's
Discussion and Analysis of Financial Condition and Results of Operation in Part
II, Item 7 of the 2001 10-K.
On February 8, 2002, we issued $215 million of 4.5% Notes due 2004. See the
cash commitments table above for the parent company's debt repayment
requirements. The majority of these borrowings were used to fund Pinnacle West
Energy capital expenditures.
On July 31, 2002, we completed a $300 million bank credit facility. The
borrowings are LIBOR-based and can be drawn upon as needed, and are expected to
be used primarily to fund Pinnacle West Energy capital requirements. The
facility matures on July 30, 2003.
We fund our pension plan by contributing at least the minimum amount
required under Internal Revenue Service regulations but no more than the maximum
tax-deductible amount. The minimum required funding takes into consideration the
value of the fund assets and our pension obligation. We have contributed cash to
our pension plan in each of the last eight years, the last four of which were
entirely voluntary (our minimum required contributions during each of those
years was zero). Specifically, we contributed $24 million for 2001, $44 million
for 2000, $25 million for 1999 and $14 million for 1998. We again plan to
voluntarily contribute $27 million in 2002. 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 depending on 2002 fund performance. If the fund performance continues
to decline as a result of a continued decline in equity markets, we may be
required to make contributions in future years.
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APS
APS' cash requirements and its ability to fund those requirements are
discussed under "Capital Needs and Resources" in Management's Discussion and
Analysis of Financial Condition and Results of Operation in Part II, Item 7 of
the 2001 10-K.
On March 1, 2002, APS issued $375 million of 6.50% Notes due 2012.
On April 15, 2002, APS redeemed $122 million of its First Mortgage Bonds,
8.75% Series due 2024. On March 15, 2002, APS redeemed at maturity $125 million
of its First Mortgage Bonds, 8.125% Series due 2002. See the cash commitments
table above for APS' debt repayments. Based on market conditions and optional
call provisions, APS may make optional redemptions of long-term debt from time
to time.
Although provisions in APS' first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds and preferred stock that APS may issue, APS does not expect
any of these provisions to limit its ability to meet its capital requirements.
PINNACLE WEST ENERGY
Pinnacle West Energy has completed or announced plans to build about 3,420
MW of natural gas-fired generating capacity from 2001 through 2007 at an
estimated cost of about $1.9 billion. This does not reflect an expected
reimbursement in 2004 by SNWA of approximately $100 million of Pinnacle West
Energy's cumulative capital expenditures in the Silverhawk project in exchange
for SNWA's option to purchase a 25% interest in the project. Our expansion plan
will be sized to meet native load growth, cash flow and market conditions.
Pinnacle West Energy is currently funding its capital requirements through
capital infusions from Pinnacle West, which finances those infusions through
debt financings and internally-generated cash. As Pinnacle West Energy develops
and obtains additional generation assets, Pinnacle West Energy expects to fund
its capital requirements through internally-generated cash and its own debt
issuances. As we discuss in greater detail in Note 5, on July 23, 2002, an ACC
ALJ issued a recommended order recommending, among other things, that the
ability of APS to transfer its generating assets be stayed until at least July
1, 2004. See "Business Outlook - Other Factors Affecting Future Financial
Results" below for the implications of Pinnacle West Energy funding its own
capital requirements if APS is not able to transfer its generation assets to
Pinnacle West Energy. See the Capital Expenditures Table above for actual
capital expenditures through June 30, 2002 and projected capital expenditures
for the next three years.
Pinnacle West Energy has completed or is currently planning the following
projects:
* A 650 MW expansion of the West Phoenix Power Plant in Phoenix. The 120
MW West Phoenix Unit 4 began commercial operation on June 1, 2001.
Construction has begun on the 530 MW West Phoenix Unit 5, with
commercial operation expected to begin in mid-2003.
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* The construction of a four-unit combined cycle 2,120 MW generating
station near Palo Verde, called Redhawk. Construction of Units 1 and 2
began in December 2000, and commercial operation began in July 2002.
Although Pinnacle West Energy currently plans to bring Units 3 and 4
on line in or before the first quarter of 2007, equipment procurement,
engineering and construction plans will allow for these units to come
on line as early as 2005 if warranted by market conditions.
* The construction of an 80 MW simple-cycle power plant at Saguaro in
Southern Arizona. Commercial operation began in July 2002.
* Development of an electric generating station 20 miles north of Las
Vegas, Nevada. Construction of the 570 MW Silverhawk combined-cycle
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 to have an option to purchase a 25% interest in the
project.
* A Pinnacle West Energy affiliate is exploring the possibility of
creating an underground natural gas storage facility on Company-owned
land west of Phoenix. A feasibility study is in progress to determine
if the proposed acreage can support a natural gas storage cavern.
OTHER SUBSIDIARIES
During the past three years, both SunCor and El Dorado funded all of their
cash requirements with cash from operations and, in the case of SunCor, its own
external financings. APSES funded its cash requirements with cash infusions from
Pinnacle West.
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 six months ended
June 30, 2002 and projected capital expenditures for the next three years.
SunCor expects to fund its capital requirements with cash from operations and
external financings. SunCor's long-term indebtedness decreased $15 million in
the six months ended June 30, 2002. SunCor has provided guarantees of
approximately $24 million on behalf of affiliated joint ventures.
El Dorado does not have any capital requirements over the next three years.
El Dorado intends to focus on prudently realizing the value of its existing
investments. El Dorado's future investments are expected to be related to the
energy sector.
APSES' 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 APSES' capital expenditures.
-44-
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses, and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from
those estimates. Our most critical accounting policies include the determination
of the appropriate accounting for our derivative instruments, mark-to-market
accounting and the impacts of regulatory accounting on our consolidated
financial statements. See Note 1 in the 2001 10-K. There have been no material
changes since the 2001 10-K.
BUSINESS OUTLOOK
We currently believe that we will not be able to match our 2001 earnings
this year. For 2001, our reported income before accounting change was $327
million, or $3.85 per diluted share of common stock, and included charges
totaling $21 million before income taxes, or $0.15 per diluted share, that we do
not expect to recur related to our exposure to Enron and its affiliates. Our
earnings in 2002 are expected to be negatively affected by a significant
decrease in the earnings contribution from our marketing and trading activities
and retail electricity price decreases. These negative factors are expected to
be significantly offset in 2002 by the absence of significant expenses for
reliability and power plant outages that we incurred in 2001 that we do not
expect to recur in 2002 and by retail customer growth, although the pace of
growth is expected to be slower than in the past. These factors are described in
more detail below.
In 2001, the Company reported income of $172 million from its marketing and
trading activities. We expect earnings contributions from these activities will
be down approximately 75% in 2002. The drivers of such reduced earnings
contributions from our marketing and trading activities in 2002 are significant
reductions in wholesale market prices for electricity that occurred during 2001;
reduced wholesale market liquidity, which affects our ability to buy and resell
electricity; and reduced market volatility, which affects our ability to capture
profitable structured trading activities.
During 2001, in order to meet the highest customer demand in APS' history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts,
which cost approximately $140 million before income taxes, are not expected to
be repeated in 2002.
In July 2002, the Company announced cost-containment measures that include
a voluntary workforce reduction of 500-600 positions. These reductions would be
implemented in the second half of 2002 and are expected to produce annual
operating expense savings of $30-35 million beginning in 2003, and a comparable
one-time charge to earnings later in 2002.
We estimate our retail customer growth in 2002 to be 3.2%, which is slower
than the pace of growth in recent years, although still about three times the
national average. Our customer growth in 2001 was 3.7%. Our current estimate for
customer growth in 2003 and 2004 is between 3.5% and 4.0% annually.
-45-
As of December 31, 2001, the indicated annual dividend rate on our common
stock was $1.60 per share. Since 1994, we have increased the dividend on our
common stock ten cents per share per year. We currently plan to continue annual
dividend increases of relatively consistent amounts, which would continue
dividend growth at a pace above the industry average.
The foregoing discussion of future expectations is forward-looking
information. Actual results may differ materially from expectations. See
"Forward-Looking Statements" below.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See "Business Outlook - Competition and Industry Restructuring" in Item 7
of the 2001 10-K and Note 5 above for a discussion of developments affecting
retail and wholesale electric competition.
GENERATION EXPANSION
See "Capital Resources and Cash Requirements - Pinnacle West Energy" above
for information regarding our generation expansion plans. The planned additional
generation is expected to increase revenues, fuel expenses, operating expenses,
and financing costs.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona, and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer, as well as electricity prices and
variations in weather from period to period.
In APS' regulated retail market area, APS will provide electricity services
to standard-offer, full-service customers and to energy delivery customers who
have chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in APS' service territory averaged about 4% a year
for the three years 1999 through 2001; we currently expect customer growth to be
about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We
currently estimate that retail electricity sales in kilowatt-hours will grow
3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather
variations. The customer growth and sales growth referred to in this paragraph
apply to energy delivery customers. As industry restructuring evolves in the
regulated market area, we cannot predict the number of APS' standard-offer
customers that will switch to unbundled service. As previously noted, under the
1999 Settlement Agreement, we agreed to retail electricity price reductions of
1.5% annually through July 1, 2003 (see Note 5).
Competitive sales of energy and energy-related products and services are
made by APSES in western states that have opened to competitive supply.
-46-
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
As we discuss in greater detail in Note 5, on July 23, 2002, an ACC ALJ
issued a recommended order recommending, among other things, that the ability of
APS to transfer its generating assets be stayed until at least July 1, 2004. The
Company has financed Pinnacle West Energy's generation expansion program
premised upon Pinnacle West Energy's receipt of APS' generation assets by the
end of 2002, as promised by the 1999 Settlement Agreement. Pinnacle West Energy
has previously received investment grade credit ratings contingent upon its
acquisition of APS' generation assets. If APS is prohibited from transferring
its generation assets to Pinnacle West Energy, the Company believes that if
Pinnacle West Energy is able to finance its capital requirements (including the
repayment of the bridge financing provided by the Company), it would only be
able to do so on commercially unattractive terms. In such a case, the Company's
overall financing costs could increase. As we discuss in Note 5, APS has
proposed that APS be permitted to acquire certain of Pinnacle West Energy's
generating facilities if the ACC prohibits or delays APS' transfer of generation
assets to Pinnacle West Energy. If APS were to acquire Pinnacle West Energy
generation assets, the Company believes that APS could obtain financing for
those assets and could do so on terms more favorable than those that would be
otherwise available to Pinnacle West Energy.
Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, new generating plants being placed
in service and our hedging program for managing such costs.
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, outages, higher trending
pension and other post-retirement costs and other factors. See "Business
Outlook" above for information regarding Company cost-containment measures
announced in July 2002.
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 expansion program. As noted above,
Redhawk Units 1 and 2 and the Saguaro power plant began commercial operations in
July 2002.
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 9.32% of assessed value for 2001 and 9.16% for
2000. We expect property taxes to increase primarily due to our generation
expansion program and our additions to existing facilities.
Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels in
the next several years are expected to be our generation expansion program 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, Redhawk Units 1 and 2 and the Saguaro power plant
began commercial operations in July 2002.
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The annual earnings contribution from APSES is expected to be positive over
the next several years due primarily to a number of retail electricity contracts
in California. APSES' pretax losses were $10 million in 2001 and $13 million in
2000.
The annual earnings contribution from SunCor is expected to remain modest
over the next several years. SunCor's earnings were $3 million in 2001, $11
million in 2000 and $6 million in 1999.
El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. El Dorado's strategies focus on prudently realizing
the value of its existing investments. Any future investments are expected to be
related to the energy sector.
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.
Our financial results may be affected by the application of SFAS No. 133.
See Note 10 for further information.
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.
RATE MATTERS
See Note 5 for a discussion of a price reduction effective as of July 1,
2002, and for a discussion of the 1999 Settlement Agreement that will, among
other things, result in five annual price reductions over a four-year period
ending July 1, 2003.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements, except as
required by applicable laws. Because actual results may differ materially from
expectations, we caution readers not to place undue reliance on these
statements. A number of factors could cause future results to differ materially
from historical results, or from results or outcomes currently expected or
sought by us. These factors include the ongoing restructuring of the electric
industry, including the introduction of retail electric competition in Arizona;
the outcome of regulatory and legislative proceedings relating to the
restructuring; state and federal regulatory and legislative decisions and
actions, including the price mitigation plan adopted by the FERC; regional
economic and market conditions, including the California energy situation and
completion of generation construction in the region, which could affect customer
growth and the cost of power supplies; the cost of debt and equity capital;
weather variations affecting local and regional customer energy usage;
conservation programs; power plant performance; the successful completion of our
generation expansion program; regulatory issues associated with generation
expansion, such as permitting and licensing; our ability to compete successfully
outside traditional regulated markets (including the wholesale market);
technological developments in the electric industry; the performance of the
stock market, which affects the amount of our required contributions to our
pension plan; and the strength of the real estate market in SunCor's market
areas, which include Arizona, New Mexico and Utah.
-48-
These factors and the other matters discussed above may cause future
results to differ materially from historical results, or from results or
outcomes we currently expect or seek.
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in interest
rates, commodity prices, and investments held by our nuclear decommissioning
trust fund.
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
In addition, subject to specified risk parameters established by the Board
of Directors and monitored by our Energy Risk Management Committee, we engage in
trading activities intended to profit from market price movements. In accordance
with EITF 98-10, "Accounting For Contracts Involved in Energy Trading and Risk
Management Activities," such trading positions are marked-to-market. These
trading activities are part of our marketing and trading activities and are
reflected in the marketing and trading segment revenues and expenses.
The following schedule shows the changes in mark-to-market of our trading
positions during the three, six and twelve months ended June 30, 2002 (dollars
in millions):
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Three Months Ended Six Months Ended Twelve Months Ended
June 30, 2002 June 30, 2002 June 30, 2002
------------- ------------- -------------
Mark-to-market of net
trading positions at
beginning of period $ 141 $ 138 $ 105
Prior period mark-to-market
gains realized during the
period (8) (22) (89)
Change in mark-to-market
gains for future period
deliveries -- 17 117
Change in valuation
techniques -- -- --
----- ----- -----
Mark-to-Market of net
trading positions at end
of period $ 133 $ 133 $ 133
===== ===== =====
Net gains at inception include a reasonable marketing margin and were
approximately $1 million for the three months ended June 30, 2002, approximately
$9 million for the six months ended June 30, 2002 and approximately $12 million
for the twelve months ended June 30, 2002. See Note 10 for mark-to-market on
system hedges and for disclosure of risk management activities recorded on the
consolidated balance sheets.
The table below shows the maturities of our trading positions as of June
30, 2002, by the type of valuation that is performed to calculate the fair value
of the contract (millions of dollars):
Years Total
there- fair
Source of Fair Value 2002 2003 2004 2005 2006 after value
----- ----- ----- ----- ----- ----- -----
Prices actively quoted $ (27) $ 3 $ 4 $ 5 $ 3 $ 6 $ (6)
Prices provided by other
external sources 1 (2) (1) 1 2 (4) (3)
Prices based on models and
other valuation methods 38 27 26 20 17 14 142
----- ----- ----- ----- ----- ----- -----
Total by maturity $ 12 $ 28 $ 29 $ 26 $ 22 $ 16 $ 133
===== ===== ===== ===== ===== ===== =====
The table below shows the impact that 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 June 30,
2002 (dollars in millions):
-50-
June 30, 2002
Gain (Loss)
--------------------------------
Commodity Price Up 10% Price Down 10%
--------- ------------ --------------
Trading (a):
Electric $ (2) $ 2
Natural gas (1) 1
Other 2 (1)
System (b):
Natural gas
hedges 18 (16)
---- ----
Total $ 17 $(14)
==== ====
(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is 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. 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.
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 one counterparty for which a worst case exposure
represents approximately 47% of our $267 million of risk management and trading
assets as of June 30, 2002. We use a risk management process to assess and
monitor the financial exposure of this and all other counterparties. Despite the
fact that the great majority of trading counterparties are rated as investment
grade by the credit rating agencies, including the counterparty 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.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our pension and nuclear decommissioning trust fund. Our
policy is to manage interest rates through the use of a combination of
fixed-rate and floating-rate debt. The pension and nuclear decommissioning fund
also has risks associated with changing market values of equity investments.
Pension and nuclear decommissioning costs are recovered in regulated electricity
prices.
-51-
PART II - OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
At our Annual Meeting of Shareholders held on May 22, 2002, the following
shareholder proposal was submitted to shareholders:
Votes Votes Abstentions and
For Against Broker Non Votes
--- ------- ----------------
PROPOSAL THAT PINNACLE WEST
PROVIDE SHAREHOLDERS WITH AN
ENERGY REPORT 4,395,349 63,512,921 2,197,596
In addition, at the same annual meeting, the following management proposal
was submitted to shareholders:
Votes Votes Abstentions and
For Against Broker Non Votes
--- ------- ----------------
PROPOSAL FOR APPROVAL OF A
LONG-TERM INCENTIVE PLAN 65,804,188 3,394,492 907,186
Also, at the same annual meeting, the following persons were elected as
directors:
Votes Votes
For Against Abstentions
--- ------- -----------
CLASS I (TERM TO EXPIRE AT
2004 ANNUAL MEETING)
William L. Stewart 75,953,254 140,845 --
CLASS II (TERM TO EXPIRE AT
2005 ANNUAL MEETING
Edward N. Basha, Jr. 75,409,816 1,896,132 --
Michael L. Gallagher 75,120,087 2,203,533 --
Bruce J. Nordstrom 75,431,462 1,894,875 --
William J. Post 75,893,114 1,443,078 --
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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.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 of Notes to Condensed Consolidated Financial Statements in Part
I, Item 1 of this report for a discussion of regulatory developments regarding
the introduction of retail electric competition in Arizona and related matters.
PALO VERDE NUCLEAR GENERATING STATION
In February 2002, the U. S. Secretary of Energy recommended to President
Bush that the Yucca Mountain, Nevada site be developed as a permanent repository
for spent nuclear fuel. The President transmitted this recommendation to
Congress and the State of Nevada vetoed the President's recommendation. See
"Palo Verde Nuclear Generating Station" in Part II, Item 5 of the March 2002
10-Q. Congress recently approved the Yucca Mountain site, overriding the Nevada
veto. It is now expected that the U.S. Department of Energy will submit a
license application to the NRC late in 2004.
NATURAL GAS SUPPLY
In a pending FERC proceeding, El Paso Natural Gas Company has proposed
allocating its gas pipeline capacity in such a way that APS' (and other
companies with the same contract type) gas transportation rights could be
significantly impacted, and various parties, including APS and Pinnacle West
Energy, have challenged this allocation. See "Generating Fuel and Purchased
Power - Natural Gas Supply" in Part I, Item 1 of the 2001 10-K. The FERC
conducted a public conference in April 2002 to discuss an appropriate mechanism
for allocating capacity on the El Paso Natural Gas Company pipeline. On May 31,
2002 the FERC issued an order requiring the conversion of all firm, Full
Requirements contracts to Contract Demand contracts by November 1, 2002. In
addition, the FERC order set forth procedures to encourage parties to resolve
the details of such conversions through the settlement process. APS and other
Full Requirement contract holders have sought rehearing of the FERC order and
have requested a stay of the November 1, 2002 implementation date. We cannot
currently predict the outcome of this matter.
COAL SUPPLY
Because covenants under the Four Corners lease and related federal
rights-of-way and grants expired in July 2001, the Navajo Nation assessed taxes
on the coal supplier and the plant. See "Generating Fuel and Purchased Power -
Coal Supply - Four Corners" in Part I, Item 1 of the 2001 10-K. In July 2002,
APS and the Navajo Nation negotiated a settlement agreement relating to the
plant pursuant to which APS will make settlement payments to the Navajo Nation.
That settlement agreement is expected to be executed in August 2002. Pursuant to
the terms of the settlement agreement, APS does not expect the payments to have
a material adverse impact on its financial position, results of operations or
liquidity.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
10.1 Amendment to Letter Agreement effective as of
January 1, 2002 between APS and William L. Stewart
10.2 Summary of James M. Levine Retirement Benefits
12.1 Ratio of Earnings to Fixed Charges
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In addition, the Company hereby incorporates the following Exhibits
pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to
the filings set forth below:
Originally Filed Date
Exhibit No. Description as Exhibit: File No.(a) Effective
- ----------- ----------- ----------- ----------- ---------
3.1 Articles of Incorporation 19.1 to the Company's 1-8962 11-14-88
restated as of July 29, September 30, 1988
1988 Form 10-Q Report
3.2 Bylaws, amended as of 4.1 to the Company's 1-8962 1-20-00
December 15, 1999 Registration Statement
on Form S-8 No. 333-95035
(b) Reports on Form 8-K
During the quarter ended June 30, 2002, and the period from July 1 through
August 13, 2002, we filed the following reports on Form 8-K:
Report dated March 31, 2002 regarding a motion filed by APS in a
consolidated ACC docket.
Report dated April 26, 2002 regarding procedural orders issued by the ACC
in a consolidated ACC docket.
Report dated May 22, 2002 regarding responses to FERC data requests that
were filed with the FERC on May 22, 2002.
Report dated June 5, 2002 regarding responses to FERC data requests that
were filed with the FERC on June 5, 2002.
Report dated June 11, 2002 comprised of a slide presentation for use at an
analyst conference.
Report dated July 11, 2002 regarding a letter filed by APS with the ACC
discussing the circumstances under which APS would support a temporary
suspension or stay of certain Arizona electric competition rules.
Report dated June 30, 2002 comprised of exhibits relating to financial
information and earnings variance explanations.
Report dated July 23, 2002 regarding ALJ recommendations in a consolidated
ACC docket.
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(a) Reports filed under File No. 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
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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: August 13, 2002 By: Chris N. Froggatt
------------------------------------
Chris N. Froggatt
Vice President and Controller
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)
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