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 September 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 November 12, 2002: 84,755,377
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
APS - Arizona Public Service Company, a subsidiary of the Company
APS Energy Services - APS Energy Services Company, Inc., a subsidiary of the
Company
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Pinnacle West Capital Corporation
CPUC - California Public Utility Commission
EITF - the FASB's Emerging Issues Task Force
El Dorado - El Dorado Investment Company, a subsidiary of the Company
ERMC - the Company's Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Financing Application - APS application filed with the ACC on September 16, 2002
Fitch - Fitch, Inc.
Four Corners - Four Corners Power Plant
GAAP - Generally accepted accounting principles in the United States
Interim Financing Application - APS application filed with the ACC on
November 8, 2002
IRS - Internal Revenue Service
ISO - California Independent System Operator
June 2002 10-Q - Pinnacle West Capital Corporation Quarterly Report on Form 10-Q
for the fiscal quarter ended June 30, 2002
Moody's - Moody's Investors Service
MW - megawatt, one million watts
MWh - megawatt hour
NAC -NAC International Inc., a subsidiary of El Dorado
Native Load - retail and wholesale sales supplied under traditional cost-based
rate regulation
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation, the Company
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
SEC - United States Securities and Exchange Commission
SFAS - Statement of Financial Accounting Standards
SNWA - Southern Nevada Water Authority
SPE - special-purpose entity
Standard & Poor's - Standard & Poor's Corporation
SunCor - SunCor Development Company, a subsidiary of the Company
System - Non-trading energy related activities
T&D - transmission and distribution
Track A Order - ACC order dated September 10, 2002 regarding generation asset
transfers and related issues
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
September 30,
--------------------------
2002 2001
----------- -----------
Operating Revenues
Electric retail segment $ 719,361 $ 973,398
Marketing and trading segment 87,258 141,674
Real estate 45,108 43,024
Other revenues 21,224 2,682
----------- -----------
Total 872,951 1,160,778
----------- -----------
Operating Expenses
Electric retail segment purchased power and fuel 257,484 499,789
Marketing and trading segment purchased power and fuel 43,361 33,714
Operations and maintenance 144,438 150,916
Real estate operations 44,928 37,803
Depreciation and amortization 108,812 107,932
Taxes other than income taxes 26,757 29,336
Other expenses 34,146 2,536
----------- -----------
Total 659,926 862,026
----------- -----------
Operating Income 213,025 298,752
----------- -----------
Other
Other income (Note 16) 3,038 1,527
Other expense (Note 16) (10,713) (3,603)
----------- -----------
Total (7,675) (2,076)
----------- -----------
Interest Expense
Interest charges 49,465 42,531
Capitalized interest (11,015) (12,450)
----------- -----------
Total 38,450 30,081
----------- -----------
Income Before Income Taxes 166,900 266,595
Income Taxes 65,984 104,096
----------- -----------
Income Before Accounting Change 100,916 162,499
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $8,099 -- (12,446)
----------- -----------
Net Income $ 100,916 $ 150,053
=========== ===========
Weighted-Average Common Shares Outstanding - Basic 84,768 84,721
Weighted-Average Common Shares Outstanding - Diluted 84,797 84,909
Earnings Per Weighted-Average Common Share Outstanding
Income Before Accounting Change - Basic $ 1.19 $ 1.92
Net Income - Basic 1.19 1.77
Income Before Accounting Change - Diluted 1.19 1.91
Net Income - Diluted 1.19 1.77
Dividends Declared Per Share $ 0.40 $ 0.375
See Notes to Condensed Consolidated Financial Statements.
2
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
Nine Months Ended
September 30,
--------------------------
2002 2001
----------- -----------
Operating Revenues
Electric retail segment $ 1,596,440 $ 2,125,522
Marketing and trading segment 212,576 633,811
Real estate 155,445 107,813
Other revenues 28,382 5,878
----------- -----------
Total 1,992,843 2,873,024
----------- -----------
Operating Expenses
Electric retail segment purchased power and fuel 423,611 1,064,238
Marketing and trading segment purchased power and fuel 109,626 320,855
Operations and maintenance 390,864 408,305
Real estate operations 138,499 101,248
Depreciation and amortization 310,812 318,842
Taxes other than income taxes 81,147 80,101
Other expenses 39,115 4,027
----------- -----------
Total 1,493,674 2,297,616
----------- -----------
Operating Income 499,169 575,408
----------- -----------
Other
Other income (Note 16) 10,313 18,826
Other expense (Note 16) (26,782) (20,108)
----------- -----------
Total (16,469) (1,282)
----------- -----------
Interest Expense
Interest charges 141,149 129,103
Capitalized interest (39,143) (35,404)
----------- -----------
Total 102,006 93,699
----------- -----------
Income Before Income Taxes 380,694 480,427
Income Taxes 150,656 188,866
----------- -----------
Income Before Accounting Change 230,038 291,561
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $9,892 -- (15,201)
----------- -----------
Net Income $ 230,038 $ 276,360
=========== ===========
Weighted-Average Common Shares Outstanding - Basic 84,768 84,731
Weighted-Average Common Shares Outstanding - Diluted 84,859 84,972
Earnings Per Weighted-Average Common Share Outstanding
Income Before Accounting Change - Basic $ 2.71 $ 3.44
Net Income - Basic 2.71 3.26
Income Before Accounting Change - Diluted 2.71 3.43
Net Income - Diluted 2.71 3.25
Dividends Declared Per Share $ 1.20 $ 1.125
See Notes to Condensed Consolidated Financial Statements.
3
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
Twelve Months Ended
September 30,
--------------------------
2002 2001
----------- -----------
Operating Revenues
Electric retail segment $ 2,033,006 $ 2,581,094
Marketing and trading segment 229,996 816,413
Real estate 216,540 148,519
Other revenues 34,275 6,640
----------- -----------
Total 2,513,817 3,552,666
----------- -----------
Operating Expenses
Electric retail segment purchased power and fuel 520,236 1,191,788
Marketing and trading segment purchased power and fuel 122,980 473,288
Operations and maintenance 512,654 527,206
Real estate operations 190,713 134,296
Depreciation and amortization 419,873 424,678
Taxes other than income taxes 102,114 103,238
Other expenses 45,463 4,510
----------- -----------
Total 1,914,033 2,859,004
----------- -----------
Operating Income 599,784 693,662
----------- -----------
Other
Other income (Note 16) 17,903 23,108
Other expense (Note 16) (40,251) (38,700)
----------- -----------
Total (22,348) (15,592)
----------- -----------
Interest Expense
Interest charges 187,868 172,265
Capitalized interest (51,601) (43,167)
----------- -----------
Total 136,267 129,098
----------- -----------
Income Before Income Taxes 441,169 548,972
Income Taxes 175,325 215,099
----------- -----------
Income Before Accounting Change 265,844 333,873
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $9,892 -- (15,201)
----------- -----------
Net Income $ 265,844 $ 318,672
=========== ===========
Weighted-Average Common Shares Outstanding - Basic 84,746 84,730
Weighted-Average Common Shares Outstanding - Diluted 84,851 84,984
Earnings Per Weighted-Average Common Share Outstanding
Income Before Accounting Change - Basic $ 3.14 $ 3.94
Net Income - Basic 3.14 3.76
Income Before Accounting Change - Diluted 3.13 3.93
Net Income - Diluted 3.13 3.75
Dividends Declared Per Share $ 1.60 $ 1.50
See Notes to Condensed Consolidated Financial Statements.
4
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
ASSETS
September 30, December 31,
2002 2001
---------- ----------
(unaudited)
Current Assets
Cash and cash equivalents $ 28,099 $ 28,619
Customer and other receivables--net 458,702 367,241
Accrued utility revenues 103,773 76,131
Materials and supplies (at average cost) 80,868 81,215
Fossil fuel (at average cost) 30,632 27,023
Assets from risk management and trading
activities 53,389 66,973
Other current assets 91,259 80,203
---------- ----------
Total current assets 846,722 727,405
---------- ----------
Investments and Other Assets
Real estate investments--net 424,237 418,673
Assets from risk management and trading
activities - long-term 206,261 200,351
Other assets 252,634 304,453
---------- ----------
Total investments and other assets 883,132 923,477
---------- ----------
Property, Plant and Equipment
Plant in service and held for future use 8,965,104 8,030,847
Less accumulated depreciation and amortization 3,447,463 3,290,097
---------- ----------
Total 5,517,641 4,740,750
Construction work in progress 754,241 1,047,072
Intangible assets, net of accumulated
amortization 100,561 86,782
Nuclear fuel, net of accumulated amortization 54,770 49,282
---------- ----------
Net property, plant and equipment 6,427,213 5,923,886
---------- ----------
Deferred Debits
Regulatory assets 267,104 342,383
Other deferred debits 83,905 64,597
---------- ----------
Total deferred debits 351,009 406,980
---------- ----------
Total Assets $8,508,076 $7,981,748
========== ==========
See Notes to Condensed Consolidated Financial Statements.
5
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
LIABILITIES AND EQUITY
September 30, December 31,
2002 2001
----------- -----------
(unaudited)
Current Liabilities
Accounts payable $ 271,297 $ 269,124
Accrued taxes 102,285 96,729
Accrued interest 45,116 48,806
Short-term borrowings 317,811 405,762
Current maturities of long-term debt 260,303 126,140
Customer deposits 54,659 30,232
Deferred income taxes 3,244 3,244
Liabilities from risk management and
trading activities 30,396 35,994
Other current liabilities 123,912 74,898
----------- -----------
Total current liabilities 1,209,023 1,090,929
----------- -----------
Long-Term Debt Less Current Maturities 2,879,055 2,673,078
----------- -----------
Deferred Credits and Other
Liabilities from risk management and
trading activities - long-term 92,907 207,576
Deferred income taxes 1,222,260 1,064,993
Unamortized gain - sale of utility plant 60,628 64,060
Other 381,673 381,789
----------- -----------
Total deferred credits and other 1,757,468 1,718,418
----------- -----------
Commitments and Contingencies (Note 12)
Common Stock Equity
Common stock, no par value 1,534,025 1,531,038
Retained earnings 1,161,157 1,032,850
Accumulated other comprehensive loss (32,652) (64,565)
----------- -----------
Total common stock equity 2,662,530 2,499,323
----------- -----------
Total Liabilities and Equity $ 8,508,076 $ 7,981,748
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
6
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
Nine Months Ended
September 30,
----------------------
2002 2001
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income before accounting change $ 230,038 $ 291,561
Items not requiring cash
Depreciation and amortization 310,812 318,842
Nuclear fuel amortization 23,639 22,221
Deferred income taxes--net 141,024 (58,936)
Change in mark-to-market--trading (20,937) (185,521)
Change in mark-to-market--system (1,226) (8,604)
Changes in current assets and liabilities
Customer and other receivables--net (65,092) (111,972)
Accrued utility revenues (27,642) (28,385)
Materials, supplies and fossil fuel (3,262) (14,766)
Other current assets (12,590) (6,456)
Accounts payable (14,413) 30,729
Accrued taxes 7,446 254,736
Accrued interest (3,690) (14,915)
Other current liabilities 69,827 (23,872)
Change in real estate investments (5,008) (31,481)
Increase in regulatory assets (8,709) (10,565)
Change in risk management and trading
investments - at cost (36,385) (1,907)
Customer advances 17,132 28,069
Change in long term assets (24,416) (16,155)
Change in long term liabilities (22,994) 6,162
--------- ---------
Net Cash Flow Provided By Operating Activities 553,554 438,785
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Trust fund for bond redemption -- (72,370)
Capital expenditures (689,580) (692,553)
Capitalized interest (39,143) (35,404)
Other--net 41,724 30,126
--------- ---------
Net Cash Flow Used For Investing Activities (686,999) (770,201)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 613,757 744,500
Short-term borrowings and payments--net (95,416) 116,625
Dividends paid on common stock (101,727) (95,341)
Repayment of long-term debt (286,676) (413,589)
Other--net 2,987 (5,805)
--------- ---------
Net Cash Flow Provided By Financing Activities 132,925 346,390
--------- ---------
Net Cash Flow (520) 14,974
Cash and Cash Equivalents at Beginning of Period 28,619 10,363
--------- ---------
Cash and Cash Equivalents at End of Period $ 28,099 $ 25,337
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 100,573 $ 101,072
Income taxes $ 47,450 $ 32,349
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, APS Energy Services,
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 (see Note 8).
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 March
15, 2002, APS redeemed at maturity $125 million of its First Mortgage Bonds,
8.125% Series due 2002. On April 15, 2002, APS redeemed $122 million of its
First Mortgage Bonds, 8.75% Series due 2024. SunCor's long-term indebtedness
decreased $11 million during the nine months ended September 30, 2002. El
Dorado's long-term indebtedness increased $9 million during the nine months
ended September 30, 2002, due to its consolidation of NAC for financial
reporting purposes (see Note 14). The above items represent the primary changes
in capitalization for the nine months ended September 30, 2002.
On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation
issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona
Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned
the proceeds to APS pursuant to a loan agreement. The bonds were issued to
refinance $90 million of outstanding pollution control bonds. In addition, see
"ACC Applications" in Note 5 for a discussion of APS applications requesting the
ACC to permit APS to make inter-affiliate loans to, or guarantees in favor of,
Pinnacle West Energy and Pinnacle West.
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
8
Agreement, APS was 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 had 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. The Rules also obligated 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.
On August 27, 2002, the ACC held an open meeting to consider various issues
relating to retail electric competition in Arizona. At that meeting, the ACC
determined, among other things, that APS would not be permitted to transfer its
generation assets. The ACC stayed indefinitely the competitive bidding
requirements described in the preceding paragraph. Instead, the ACC required
that APS competitively procure, at a minimum, any power needed for its retail
customers that it cannot produce from its existing generation assets. The ACC
ordered the ACC Staff and interested parties to develop a competitive
procurement process by March 1, 2003. For purposes of this competitive
procurement process, the ACC stated that the Pinnacle West Energy generation
assets "shall not be counted as APS assets in determining the amount, timing,
and manner of the competitive solicitation." The ACC ordered the development of
a competitive solicitation process that can begin by March 1, 2003.
On September 16, 2002, APS filed an application with the ACC requesting the
ACC to allow APS to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to the Company; to guarantee up to $500 million of
Pinnacle West Energy's or the Company's debt; or a combination of both, not to
exceed $500 million in the aggregate. In its application, APS stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between APS and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing provided
by the Company to fund the construction of Pinnacle West Energy generation
assets or from effectively competing in the wholesale markets. APS noted that
Pinnacle West Energy had previously received investment-grade credit ratings
contingent upon its receipt of APS generation assets and that the Company's
credit ratings could be adversely affected if Pinnacle West Energy is unable to
finance its capital requirements. On November 4, 2002, Standard & Poor's lowered
the Company's senior unsecured debt rating from "BBB" to "BBB-". On November 8,
2002, APS filed an Interim Financing Application with the ACC requesting the ACC
to permit APS to (a) make short-term advances to Pinnacle West in the form of an
inter-affiliate line of credit in the amount of $125 million or (b) guarantee
$125 million of Pinnacle West's short-term debt.
These regulatory developments and legal challenges to the Rules have raised
considerable uncertainty about the status and pace of retail electric
competition in Arizona. 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
9
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. The final 1.5% price
reduction is to be implemented July 1, 2003. For customers having
loads of three MW or greater, standard-offer rates have been reduced
in varying annual increments that total 5% in the years 1999 through
2002.
* 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
Competition Rules" below), including an additional 140 MW being made
available to eligible non-residential customers. APS opened its
distribution system to retail access for all customers on January 1,
2001. The regulatory developments and legal challenges to the Rules
discussed in this note have raised considerable uncertainty about the
status and pace of electric competition in Arizona. Although some very
limited retail competition existed in APS' service area in 1999 and
2000, there are currently no active retail competitors offering
unbundled energy or other utility services to APS' customers. As a
result, we cannot predict when, and the extent to which, additional
competitors will re-enter APS' service territory.
10
* 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. However, as noted above and
discussed in greater detail below, the ACC unilaterally modified this
aspect of the 1999 Settlement Agreement by issuing an order preventing
APS from transferring its generation assets.
RETAIL ELECTRIC COMPETITION RULES. The Rules approved by the ACC included
the following major provisions:
* 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.
* 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
11
competitive electric assets and services to affiliates no later than
December 31, 2002. However, as noted above and discussed in greater
detail below, the ACC reversed its decision, as reflected in the
Rules, to require APS to transfer its generation assets.
Under the 1999 Settlement Agreement, the Rules are to be interpreted and
applied, to the greatest extent possible, in a manner consistent with the 1999
Settlement Agreement. If the two cannot be reconciled, APS must seek, and the
other parties to the 1999 Settlement Agreement must support, a waiver of the
Rules in favor of the 1999 Settlement Agreement.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, to operate in Arizona. We do not believe the
ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was
not at issue in the consolidated cases before the judge. Further, the ACC made
findings related to the fair value of APS' property in the order approving the
1999 Settlement Agreement. The ACC and other parties aligned with the ACC have
appealed the ruling to the Arizona Court of Appeals, as a result of which the
Superior Court's ruling is automatically stayed pending further judicial review.
In a similar appeal concerning the issuance of competitive telecommunications
CC&N's, the Arizona Court of Appeals invalidated rates for competitive carriers
due to the ACC's failure to establish a fair value rate base for such carriers.
That decision was upheld by the Arizona Supreme Court.
PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail
customers to have access to competitive providers of energy and energy services,
APS is the "provider of last resort" for standard-offer, full-service customers
under rates that have been approved by the ACC. These rates are established
until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek
adjustment of these rates in the event of emergency conditions or circumstances,
such as the inability to secure financing on reasonable terms; material changes
in APS' cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or judicial decisions,
actions or orders. Energy prices in the western wholesale market vary and,
during the course of the last two years, have been volatile. At various times,
prices in the spot wholesale market have significantly exceeded the amount
included in APS' current retail rates. In the event of shortfalls due to
unforeseen increases in load demand or generation or transmission outages, APS
may need to purchase additional supplemental power in the wholesale spot market.
Unless APS is able to obtain an adjustment of its rates under the emergency
provisions of the 1999 Settlement Agreement, there can be no assurance that APS
would be able to fully recover the costs of this power.
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 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
12
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.
TRACK A ORDER
On September 10, 2002, the ACC issued the Track A Order, which documents
decisions made by the ACC at an open meeting on August 27, 2002. The major
provisions of the Track A Order include, among other things:
Provisions related to the reversal of the generation asset transfer requirement:
* The ACC reversed its decision, as reflected in the Rules, to require
APS to transfer its generation assets either to an unrelated third
party or to a separate corporate affiliate; and
* the ACC unilaterally modified the 1999 Settlement Agreement, which
authorized APS' transfer of its generating assets, and directed APS to
cancel its activities to transfer its generation assets to Pinnacle
West Energy.
Provisions related to the wholesale competitive energy procurement process
("Track B" issues):
* The ACC stayed indefinitely the requirement of the Rules that APS
acquire 100% of its energy needs for its standard offer customers from
the competitive market, with at least 50% obtained through a
competitive bid process;
* the ACC established a requirement that APS competitively procure, at a
minimum, any required power that it cannot produce from its existing
assets in accordance with the ultimate outcome of the Track B
proceedings;
* the ACC directed the parties to develop a competitive procurement
("bidding") process that can begin by March 1, 2003; and
* the ACC stated that "the [Pinnacle West Energy] generating assets that
APS may acquire from [Pinnacle West Energy] shall not be counted as
APS assets in determining the amount, timing and manner of the
competitive solicitation" for Track B purposes, thereby bifurcating
the regulatory treatment of the existing APS assets and the Pinnacle
West Energy assets.
On September 30, 2002, APS filed a Motion for Reconsideration of the Track
A Order and on October 17, 2002, the ACC voted to deny that motion. APS intends
to appeal the Track A Order or otherwise seek restitution for the ACC's reversal
of the 1999 Settlement Agreement. Such restitution will also be addressed in
APS' 2003 rate filing with the ACC.
The ACC Staff has conducted workshops on the Track B issues with various
parties to determine and define the appropriate process to be used for
competitive power procurement. On October 25, 2002, the ACC Staff issued its
report proposing a process by which APS would procure power not supplied by its
own resources. Under the ACC Staff's proposal, we believe APS will be required
to competitively bid for about 1,500 MW of energy on peak. As described above,
the ACC has directed the parties to complete the Track B proceedings such
13
that the competitive procurement process can begin by March 1, 2003. The ACC
Staff also proposes that Pinnacle West Energy would be able to bid. In addition
to the ACC Staff workshop process, the ACC will conduct evidentiary hearings to
make its final determination on the Track B proceedings. The hearing is
scheduled to begin on November 21, 2002.
ACC APPLICATIONS
On September 16, 2002, APS filed a Financing Application requesting the ACC
to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle
West Energy or the Company; to guarantee up to $500 million of Pinnacle West
Energy's or the Company's debt; or a combination of both, not to exceed $500
million in the aggregate. The loan and/or the guarantee would be used to
refinance debt incurred to fund the construction of Pinnacle West Energy
generation assets. The ACC has established a procedural schedule with a hearing
to begin January 8, 2003.
The Financing Application addresses, among other things, the following
matters:
* APS noted that its April 19, 2002 filing with the ACC had sought
unification of "[Pinnacle West Energy] Assets" (West Phoenix Combined
Cycle Units 4 and 5, Redhawk Units 1 and 2, and Saguaro Combustion
Turbine Unit 3) and APS generation assets under a common financial and
regulatory regime. APS further noted that the Track A Order's language
regarding the treatment of the Pinnacle West Energy Assets for Track B
purposes (see the last bullet point under "Track A Order" above)
appears to postpone a decision regarding the inclusion of the Pinnacle
West Energy Assets in APS' rate base, thereby effectively precluding
the consolidation of the Pinnacle West Energy Assets at APS under a
common financial and regulatory regime at the present time.
* APS stated that it did not intend or desire to foreclose the
possibility that it would acquire all or part of the Pinnacle West
Energy Assets or that it may propose that the Pinnacle West Energy
Assets be included in APS' rate base or afforded cost-of-service
regulatory treatment to the extent the Pinnacle West Energy Assets are
used by APS customers. APS stated that these issues would be
appropriate topics in APS' 2003 general rate case and noted that the
Track A Order specifically stated that the ACC would not pre-judge the
eventual rate treatment of the Pinnacle West Energy Assets.
* APS stated that the Track A Order's reversal of the generation asset
transfer requirement and the resulting bifurcation of generation
assets between APS and Pinnacle West Energy under different regulatory
regimes result in Pinnacle West Energy being unable to attain
investment-grade credit ratings. This, in turn, precludes Pinnacle
West Energy from accessing capital markets to refinance the bridge
financing provided by the Company to fund the construction of the
Pinnacle West Energy Assets or from effectively competing in the
wholesale markets. APS noted that Pinnacle West Energy had previously
received investment-grade credit ratings contingent upon its receipt
of APS generation assets and that the Company's credit ratings could
be adversely affected if Pinnacle West Energy is unable to finance its
14
capital requirements. On November 4, 2002, Standard & Poor's lowered
the Company's senior unsecured debt rating from BBB to BBB-.
* APS stated that the amount of the requested loan and/or guarantee is
APS' present estimate of the amount of credit support necessary
through APS to restore Pinnacle West Energy and the Company to their
credit status prior to the ACC's issuance of the Track A Order. APS
further stated that if the requested amount proves to be inadequate,
APS reserves the right to submit a second financing application
seeking additional credit support.
In mid-2003, the Company will need to refinance approximately $550 million
of parent company indebtedness. If the ACC does not grant the approvals
requested in the Financing Application in a timely fashion, the Company would
anticipate taking the following steps, to the extent necessary, in priority
order, although the timing of the Company's liquidity needs may affect the order
of the steps taken:
* The reduction of capital expenditures through plant delay and
cancellation;
* The sale of non-core assets; and
* The issuance of new debt and, if appropriate, new equity.
Although we believe it would be inappropriate to discuss specific amounts
for each of the foregoing categories, we estimate the sum of these steps to be
approximately equivalent to the current outstanding debt at the parent company,
which totaled approximately $1.1 billion as of September 30, 2002.
On November 8, 2002, APS filed an Interim Financing Application with the
ACC requesting a waiver of certain ACC rules to permit APS to (a) make
short-term advances to Pinnacle West in the form of an inter-affiliate line of
credit or (b) guarantee Pinnacle West's short-term debt. In either case, the
waiver would be limited to a maximum aggregate principal amount of $125 million
and for a maximum term of 364 days. In the Interim Financing Application APS
stated that Pinnacle West was facing short-term liquidity needs as a result of
the pending expiration of a $125 million bank facility, which is used as part of
the backup for the Company's $250 million commercial paper program, on November
29, 2002. As of November 12, 2002, the Company had $100 million of commercial
paper outstanding. APS further stated that many of Pinnacle West's lenders have
advised Pinnacle West that they will not renew the expiring facility because
they are unwilling to assume the regulatory risk that the ACC will act on the
Financing Application in a timely and favorable manner, particularly in light of
Standard & Poor's recent lowering of Pinnacle West's senior unsecured debt
rating. APS stressed that Pinnacle West's need for the short-term line of credit
or guarantee was a direct result of the regulatory developments giving rise to
the Financing Application (see above) and stated that the line of credit or
guarantee was designed as a pure liquidity backstop and would be the last
borrowing choice for Pinnacle West. The Company is also evaluating other options
to ensure adequate liquidity. APS requested that the Interim Financing
Application be decided by the ACC on an emergency basis at its November 19, 2002
meeting.
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 and
was originally ordered to remain in effect until September 30, 2002, was
extended to remain in place until October 31, 2002. FERC has adopted a price cap
for the period thereafter of $250 per MWh.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for
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.
15
GENERAL
The regulatory developments and legal challenges to the Rules discussed in
this note have raised considerable uncertainty about the status and pace of
electric competition in Arizona. Although some very limited retail competition
existed in APS' service area in 1999 and 2000, there are currently no active
retail competitors offering unbundled energy or other utility services to APS'
customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter APS' service territory. As competition in
the electric industry continues to evolve, we will continue to evaluate
strategies and alternatives that will position us to compete in the new
regulatory environment.
6. Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $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
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 APS Energy Services' commodity-related 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 Company's business segments follows (dollars in
millions):
16
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
------------------ ------------------ ------------------
2002 2001 2002 2001 2002 2001
------- ------- ------- ------- ------- -------
Operating Revenues:
Electric retail $ 720 $ 973 $ 1,597 $ 2,125 $ 2,033 $ 2,581
Marketing and trading 87 142 213 634 230 817
Other 66 46 183 114 251 155
------- ------- ------- ------- ------- -------
Total $ 873 $ 1,161 $ 1,993 $ 2,873 $ 2,514 $ 3,553
======= ======= ======= ======= ======= =======
Income Before
Accounting Change:
Electric retail $ 88 $ 99 $ 185 $ 112 $ 222 $ 145
Marketing and trading 24 61 49 175 46 187
Other (11) 2 (4) 4 (2) 2
------- ------- ------- ------- ------- -------
Total $ 101 $ 162 $ 230 $ 291 $ 266 $ 334
======= ======= ======= ======= ======= =======
As of As of
September 30, 2002 December 31, 2001
------------------ -----------------
Assets:
Electric retail $ 7,568 $ 7,077
Marketing and trading 428 417
Other 512 488
------- -------
Total $ 8,508 $ 7,982
======= =======
8. Accounting Matters
In June 2002, the FASB's EITF issued certain guidance related to energy
trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities." The new guidance, which was effective July 1, 2002,
required 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 be restated.
17
In October 2002, the EITF reached a consensus that gains and losses on
derivative instruments within the scope of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" should be shown net in the income
statement if the derivative is held for trading purposes. This decision
effectively supersedes the guidance provided at the June meeting. Beginning in
the third quarter of 2002, we have netted all of our energy trading activities
on the income statement and have restated prior amounts.
In the October 2002 meeting, the EITF also rescinded EITF 98-10. This
guidance is effective immediately for all new contracts and on January 1, 2003
for existing contracts. As such, energy trading contracts will be accounted for
on an accrual basis with the associated revenues and costs recorded at the time
the contracted commodities are delivered or received, unless the contracts are
required to be marked to market as derivatives under SFAS No. 133 or if allowed
by other guidance. For existing contracts, we will record a cumulative effect
adjustment in net income for the previously recorded accumulated unrealized
mark-to-market on energy trading contracts that do not meet the definition of a
derivative under SFAS No. 133. We are currently evaluating the impact of this
guidance on our consolidated financial statements.
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 determined that we have asset retirement obligations for our nuclear
facilities (nuclear decommissioning) and certain other fossil generation,
transmission, and distribution assets. The standard is not expected to have a
material impact on net income because the assets with significant retirement
obligations are regulated. We expect to establish a regulatory asset or
liability to offset the impacts of this standard on the regulated assets.
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 early 2003.
In the third quarter of 2002, we changed to the fair value method of
accounting for stock-based compensation, as provided for in SFAS No. 123,
"Accounting for Stock-Based Compensation". The fair value method of accounting
is the preferred method. In accordance with the transition requirements of SFAS
No. 123, we applied the fair value method prospectively, beginning with 2002
stock grants. We expect to record approximately $500,000 in stock option expense
before income taxes in our consolidated income statement for 2002, approximately
18
one-half of which was recorded in the third quarter of 2002. This amount may not
be reflective of the stock option expense we record in future years because
stock options typically vest over several years and additional grants are
generally made each year.
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 condensed consolidated balance sheets. This new
standard has no material impact on our financial statements, and the required
disclosures are provided in Note 13.
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 April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
Nos. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" which, among other things, supersedes previous guidance for
reporting gains and losses from extinguishment of debt and accounting for
leases. 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.
See Note 9 for accounting developments related to special-purpose entities.
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 during the fourth quarter of 2002,
with an immediate effective date for newly-created entities and for all other
entities as of the beginning of the first fiscal period beginning on or after
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 on the date of implementation. We are
currently evaluating the impact of including the related fair value of
19
assets and liabilities. The secured lease obligation bonds that are not
reflected on our condensed consolidated balance sheet at September 30, 2002
total 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.
10. Derivative Instruments and Energy Trading Activities
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 commodities. 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. 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", or the amount by which the derivative contract and the hedge
commodity are not directly correlated, 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 cumulative effects 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 was reflected in consolidated net income and other
comprehensive income as cumulative effects 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.
20
The changes in derivative fair value included in the condensed consolidated
statements of income for the three, nine and twelve months ended September 30,
2002 and 2001 are comprised of the following (dollars in thousands):
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Gains (losses) on the ineffective
portion of derivatives
qualifying for hedge
accounting $ 42 $ (1,879) $ 1,965 $ (5,748) $ 1,657 $ (5,748)
Gains (losses) from the
discontinuance of cash flow
hedges -- (2,417) (45) (5,273) 546 (5,273)
Gains (losses) from non-hedge
derivatives (5,513) 1,050 (7,092) (6,733) (7,516) (6,733)
Prior period mark-to-
market losses realized upon
delivery of commodities 376 19,880 6,398 26,358 5,986 26,358
-------- -------- -------- -------- -------- --------
Total pretax gain (loss) $ (5,095) $ 16,634 $ 1,226 $ 8,604 $ 673 $ 8,604
======== ======== ======== ======== ======== ========
As of September 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 twenty-seven months. During the twelve months ending September
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 September 30, 2002 (dollars in
thousands):
21
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
--------- ----------- ----------- ----------- -----------
Mark-to-
market:
Trading $ 37,506 $ 133,886 $ (2,613) $ (10,009) $ 158,770
System 15,883 3 (27,783) (41,865) (53,762)
Cost: Emission
allowances
and other -- 72,372(a) -- (41,033) 31,339
--------- --------- --------- --------- ---------
Total $ 53,389 $ 206,261 $ (30,396) $ (92,907) $ 136,347
========= ========= ========= ========= =========
(a) Includes $12 million required to counterparties to serve as collateral
against our open positions on energy-related contracts. The Standard &
Poor's rating action on November 4, 2002 did not significantly change our
collateral requirements with counter-parties.
11. Comprehensive Income
Components of comprehensive income for the three, nine and twelve months
ended September 30, 2002 and 2001, are as follows (dollars in thousands):
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
--------------------- ---------------------- ----------------------
2002 2001 2002 2001 2002 2001
--------- --------- --------- --------- --------- ---------
Net income $ 100,916 $ 150,053 $ 230,038 $ 276,360 $ 265,844 $ 318,672
--------- --------- --------- --------- --------- ---------
Other comprehensive income
(loss):
Minimum pension liability,
net of tax -- -- (1,835) -- (2,801) --
Cumulative effect of change
in accounting for
derivatives, net of tax -- 7,801 -- 72,501 -- 72,501
Unrealized gains (losses)
on hedging derivatives,
net of tax (a) 1,446 (11,353) 20,731 (92,493) 22,758 (92,493)
Reclassification of hedging
derivatives net realized
(gains) losses to income,
net of tax (b) 2,364 (11,145) 13,017 (46,617) 14,000 (46,617)
--------- --------- --------- --------- --------- ---------
Total other comprehensive
income (loss) 3,810 (14,697) 31,913 (66,609) 33,957 (66,609)
--------- --------- --------- --------- --------- ---------
Comprehensive income $ 104,726 $ 135,356 $ 261,951 $ 209,751 $ 299,801 $ 252,063
========= ========= ========= ========= ========= =========
22
(a) These amounts primarily include unrealized gains and losses on contracts
used to hedge our forecasted gas requirements to serve Native Load.
(b) These amounts primarily include the reclassification of unrealized gains
and losses to realized for contracted commodities delivered during the
period.
12. Commitments and Contingencies
CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST
In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC 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 nor calculated the specific refund amounts due in California,
we do not expect that the resolution of these issues, as to the amounts alleged
in the proceedings, will have a material adverse impact on our financial
position, results of operations or liquidity.
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; APS Energy Services' 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 APS
Energy Services. 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
23
that any future resolution or attempted resolution, of the California energy
market situation may have on us, our subsidiaries or the regional energy market
in general.
CALIFORNIA ENERGY MARKET LITIGATION. On March 19, 2002, the State of
California filed a complaint with the FERC alleging that wholesale sellers of
power and energy, including the Company, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the
present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET. AL., Docket
No. EL02-71-000. The complaint requests the FERC to require the wholesale
sellers to refund any rates that are "found to exceed just and reasonable
levels." This complaint has been dismissed by FERC and the State of California
is now appealing the matter to the Ninth Circuit Court of Appeals. In addition,
the State of California and others have filed various claims, which have now
been consolidated, against several power suppliers to California alleging
antitrust violations. WHOLESALE ELECTRICITY ANTITRUST CASES I AND II, Superior
Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and
4204-00006. Two of the suppliers who were named as defendants in those matters,
Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and
Trading, LLP (and other Duke entities), filed cross-claims against various other
participants in the PX and ISO markets, including APS, attempting to expand
those matters to such other participants. APS has not yet filed a responsive
pleading in the matter, but APS believes the claims by Reliant and Duke as they
relate to APS are without merit.
APS was also named in a lawsuit regarding wholesale contracts in
California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United
States District Court in and for the District of Northern California, Case No.
C02-2855 EMC. The complaint alleges basically that the contracts entered into
were the result of an unfair and unreasonable market. The PX has filed a lawsuit
against the State of California regarding the seizure of forward contracts and
the State has filed a cross complaint against APS and numerous other PX
participants. CAL PX V. THE STATE OF CALIFORNIA Superior Court in and for the
County of Sacramento, JCCP No. 4203. Various preliminary motions are being filed
and we cannot currently predict the outcome of this matter. The "United States
Justice Foundation" is suing numerous wholesale energy contract suppliers to
California, including us, as well as the California Department of Water
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 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.
24
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 $203 million at September 30, 2002 and $175 million at December
31, 2001. The related accumulated amortization was $102 million at September 30,
2002 and $88 million at December 31, 2001. Amortization expense for the three
month period ended September 30 was $6 million in 2002 and 2001. Amortization
expense for the nine month period ended September 30 was $14 million in 2002 and
$16 million in 2001. Amortization expense for the twelve-month period ended
September 30 was $20 million in 2002 and $22 million in 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's Investment in NAC
NAC develops, markets and contracts for the manufacture of cask designs for
spent nuclear fuel storage and transportation. Prior to the third quarter 2002,
El Dorado's investment in NAC was 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 fully consolidated NAC's financial
statements after acquiring a controlling interest in NAC as a result of
increased voting representation on NAC's board of directors. El Dorado
consolidated a pretax loss of $13 million in the third quarter of 2002 related
to NAC. In addition, Pinnacle West provided guarantees for credit support
related to NAC in the cumulative amount of $43 million as of September 30, 2002.
25
15. Earnings Per Share
The following table presents earnings per weighted average common share
outstanding (EPS):
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
------------------- ------------------- -------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Basic EPS:
Income before accounting change $ 1.19 $ 1.92 $ 2.71 $ 3.44 $ 3.14 $ 3.94
Cumulative effect of change in
accounting -- (0.15) -- (0.18) -- (0.18)
-------- -------- -------- -------- -------- --------
Earnings per share - basic $ 1.19 $ 1.77 $ 2.71 $ 3.26 $ 3.14 $ 3.76
======== ======== ======== ======== ======== ========
Diluted EPS:
Income before accounting change $ 1.19 $ 1.91 $ 2.71 $ 3.43 $ 3.13 $ 3.93
Cumulative effect of change in
accounting -- (0.14) -- (0.18) -- (0.18)
-------- -------- -------- -------- -------- --------
Earnings per share - diluted $ 1.19 $ 1.77 $ 2.71 $ 3.25 $ 3.13 $ 3.75
======== ======== ======== ======== ======== ========
The following table reconciles average common shares outstanding - basic to
average common shares outstanding - diluted that are used in the EPS calculation
in the condensed consolidated income statement (in thousands):
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
--------------- --------------- ---------------
2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------
Average common shares
outstanding - basic 84,768 84,721 84,768 84,731 84,746 84,730
Dilutive stock options 29 188 91 241 105 254
------ ------ ------ ------ ------ ------
Average common shares
outstanding - diluted 84,797 84,909 84,859 84,972 84,851 84,984
====== ====== ====== ====== ====== ======
Options to purchase 2,118,994 shares for the three-month period ended
September 30, 2002, 1,281,721 shares for the nine-month period ended September
30, 2002 and 1,284,063 shares for the twelve-month period ended September 30,
2002 were outstanding but were not included in the computation of EPS because
the options' exercise prices were greater than the average market price of the
common shares. Options to purchase shares of common stock that were not included
in the computation of diluted EPS were 637,872 shares for the three-month period
September 30, 2001, 213,358 shares for the nine-month period September 30, 2001
26
and 214,006 shares for the twelve-month period September 30, 2001.
16. Other Income and Other Expense
The following table provides detail of other income and other expense for
the three, nine and twelve months ended September 30, 2002 and 2001 (dollars in
thousands):
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- --------
Other income
Environmental
insurance recovery $ -- $ -- $ -- $ 10,947 $ 1,402 $ 10,947
Interest income 1,863 889 3,749 4,037 6,945 6,951
SunCor joint venture
earnings 123 188 3,522 2,669 2,040 3,607
Miscellaneous 1,052 450 3,042 1,173 7,516 1,603
-------- -------- -------- -------- -------- --------
Total other income $ 3,038 $ 1,527 $ 10,313 $ 18,826 $ 17,903 $ 23,108
======== ======== ======== ======== ======== ========
Other expense:
Investment losses -
net (a) $ (4,256) $ (605) $ (8,371) $ (3,083) $(10,071) $(10,745)
Non-operating costs -
SunCor -- -- -- (4,500) (2,500) (4,500)
Non-operating costs (b) (3,884) (2,641) (13,696) (9,620) (18,386) (15,403)
Miscellaneous (2,573) (357) (4,715) (2,905) (9,294) (8,052)
-------- -------- -------- -------- -------- --------
Total other expense $(10,713) $ (3,603) $(26,782) $(20,108) $(40,251) $(38,700)
======== ======== ======== ======== ======== ========
(a) Primarily related to El Dorado's investments in NAC in 2002 (see Note 14).
(b) Primarily below-the-line non-operating utility costs.
17. 2002 Severance Charges
In July 2002, we announced cost containment measures that included a
voluntary workforce reduction. We recorded $25 million before taxes in voluntary
severance costs in the third quarter of 2002. We expect to record up to $12
million before taxes for additional severance costs in the fourth quarter of
2002.
18. 2002 IRS Tax Refund
As a result of a change in IRS guidance, we claimed a tax deduction related
to an APS tax accounting method change on the 2001 Federal consolidated income
tax return. The accelerated deduction has resulted in a $200 million reduction
in current tax liability.
27
19. Regulatory Accounting
APS is regulated by the ACC and the FERC. The accompanying condensed
consolidated financial statements reflect the ratemaking policies of these
commissions. For regulated operations, we prepare our financial statements in
accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to
reflect the impact of regulatory decisions in its financial statements. EITF
97-4 requires that SFAS No. 71 be discontinued no later than when legislation is
passed or a rate order is used that contains sufficient detail to determine its
effect on the portion of the business being deregulated. In 1999, we
discontinued the application of SFAS No. 71 for APS' generation operations due
to the 1999 Settlement Agreement with the ACC. See Note 5 for a discussion of
the 1999 Settlement Agreement. In the Track A order, the ACC determined that APS
would not be able to transfer its generation assets as provided for in the 1999
Settlement Agreement (see Note 5). Accordingly, we now consider APS generation
to be cost-based, rate-regulated and subject to the requirements of SFAS No. 71.
The impacts of this change were immaterial to our financial statements.
28
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, nine and twelve months
ended September 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 September 30, 2002 and
September 30, 2001 are available on our website (www.pinnaclewest.com) and in
our Current Report on Form 8-K dated September 30, 2002.
OVERVIEW OF OUR BUSINESS
The Company owns all of the outstanding common stock of APS. APS is an
electric utility that provides retail and 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 the Company's marketing and trading
division, sells and delivers electricity to wholesale customers in the western
United States. Pinnacle West's marketing and trading division currently sells
into the wholesale market, the APS and Pinnacle West Energy generation output
that is not needed for APS' Native Load, which includes loads for retail
customers and traditional cost-of-service wholesale customers. Subject to
specified risk parameters established by our Board of Directors and the ERMC,
the marketing and trading division also has engaged in activities to hedge
purchases and sales of electricity, fuels, and emissions allowances and credits
and to profit from market price movements. However, as discussed in Note 5, the
ACC has ordered the ACC Staff and interested parties to develop a competitive
procurement process by March 1, 2003 by which APS will competitively procure, at
a minimum, any power needed for its retail customers that it cannot produce from
its existing generation assets. For purposes of this competitive procurement
process, Pinnacle West Energy generation assets are not counted as APS
generation assets. The draft ACC Staff report proposing a competitive
procurement process provides that Pinnacle West Energy would be able to bid.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our unregulated
electricity generation operations;
* APS Energy Services, 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
29
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; and
* El Dorado, an investment firm.
EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT
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 segment) and our competitive business
activities (marketing and trading 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 APS Energy
Services' commodity related energy services. The other amounts primarily include
activities related to SunCor and El Dorado. Certain parent company costs, other
than marketing and trading, are included in our electric retail segment.
The following tables summarize net income and segment details for the
three, nine and twelve months ended September 30, 2002 and the comparable prior
year periods for Pinnacle West and each of our subsidiaries (dollars in
millions):
30
Marketing and
Total Electric Retail Trading Other
THREE MONTHS ENDED ---------------- ---------------- --------------- ----------------
SEPTEMBER 30, 2002 2001 2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------ ------ ------
Arizona Public Service (a) $ 87 $ 108 $ 86 $ 87 $ 1 $ 21 $ -- $ --
Pinnacle West Energy (a) 10 13 10 13 -- -- -- --
APS Energy Services 7 (3) -- -- 7 (3) -- --
SunCor (1) 2 -- -- -- -- (1) 2
El Dorado (15) -- -- -- -- -- (15) --
Parent company 13 42 (8) (1) 16 43 5 --
------ ------ ------ ------ ------ ------ ------ ------
Income before
accounting change 101 162 88 99 24 61 (11) 2
Cumulative effect of
change in accounting
net of income taxes (b) -- (12) -- (12) -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Net Income $ 101 $ 150 $ 88 $ 87 $ 24 $ 61 $ (11) $ 2
====== ====== ====== ====== ====== ====== ====== ======
Marketing and
Total Electric Retail Trading Other
NINE MONTHS ENDED ---------------- ---------------- --------------- ----------------
SEPTEMBER 30, 2002 2001 2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------ ------ ------
Arizona Public Service (a) $ 183 $ 242 $ 182 $ 103 $ 1 $ 139 $ -- $ --
Pinnacle West Energy (a) 12 14 12 14 -- -- -- --
APS Energy Services 20 (10) -- -- 18 (11) 2 1
SunCor 9 3 -- -- -- -- 9 3
El Dorado (18) -- -- -- -- -- (18) --
Parent company 24 42 (9) (5) 30 47 3 --
------ ------ ------ ------ ------ ------ ------ ------
Income before
accounting change 230 291 185 112 49 175 (4) 4
Cumulative effect of
change in accounting
net of income taxes (b) -- (15) -- (15) -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Net Income $ 230 $ 276 $ 185 $ 97 $ 49 $ 175 $ (4) $ 4
====== ====== ====== ====== ====== ====== ====== ======
Marketing and
Total Electric Retail Trading Other
TWELVE MONTHS ENDED ---------------- ---------------- --------------- ----------------
SEPTEMBER 30, 2002 2001 2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------ ------ ------
Arizona Public Service (a) $ 222 $ 296 $ 218 $ 136 $ 4 $ 160 $ -- $ --
Pinnacle West Energy (a) 15 14 15 14 -- -- -- --
APS Energy Services 21 (19) -- -- 20 (21) 1 2
SunCor 10 6 -- -- -- -- 10 6
El Dorado (19) (5) -- -- -- -- (19) (5)
Parent company 17 42 (11) (5) 22 48 6 (1)
------ ------ ------ ------ ------ ------ ------ ------
Income before
accounting change 266 334 222 145 46 187 (2) 2
Cumulative effect of
change in accounting
net of income taxes (b) -- (15) -- (15) -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Net Income $ 266 $ 319 $ 222 $ 130 $ 46 $ 187 $ (2) $ 2
====== ====== ====== ====== ====== ====== ====== ======
31
(a) Consistent with APS' October 2001 ACC filing, in which APS requested
approval of a purchase power agreement with the Company to ensure ongoing
reliable service to APS customers in a volatile generation market, during
2002 APS entered into agreements with its affiliates to buy power. The
agreements, which expire December 31, 2002, reflect a price based on the
fully-dispatchable dedication of the Pinnacle West Energy generating assets
to APS' Native Load customers.
(b) APS recorded the cumulative effects of a change in accounting for
derivatives related to the 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. In
June and October 2002, the EITF provided certain guidance related to energy
trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities" (see Note 8). Beginning in the third quarter of
2002, we have netted all of our energy trading activities on the income
statement and have restated prior period amounts. Real estate gross margin
refers to real estate revenues less real estate operations costs. Other gross
margin refers to other operating revenues less other operating expenses, which
includes El Dorado's investment in NAC, which we began consolidating on our
financial statements in July 2002 (see Note 14). It also includes amounts
related to APS Energy Services' energy consulting services.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2002 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2001
Our consolidated net income for the three months ended September 30, 2002
was $101 million compared with $150 million for the same period in the prior
year. We recognized a $12 million after-tax loss in the three months ended
September 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 three months ended September
30, 2002 was $101 million compared with $162 million for the same period in the
prior year. The period-to-period decrease was primarily the result of lower
earnings contributions from our marketing and trading activities, severance
costs of $25 million pretax recorded in the third quarter of 2002 related to a
voluntary workforce reduction (see Note 17) and losses at El Dorado primarily
related to its investment in NAC in the third quarter of 2002 (see Note 14). The
comparison for marketing and trading activities reflects lower prices in the
wholesale power markets in the western United States. The regulated retail
comparison was negatively impacted by higher costs for purchased power and gas,
weather impacts and the 1.5% electric retail price reduction that took effect
July 1, 2002. These factors were offset by lower replacement costs for power
plant outages, lower operating costs related to generation reliability, customer
growth of 3.1% and higher average usage per customer for the third quarter of
2002.
32
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Marketing and trading segment gross margin:
Increase in realized marketing and trading in the current period
primarily due to higher volumes $ 3(a)
Change related to prior period mark-to-market gains on contracts
delivered during the current period (b) 39(a)
Lower mark-to-market gains for future period deliveries (b) (106)
----------
Net decrease in marketing and trading segment gross margin (64)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower market
prices and fewer unplanned outages 15
Lower hedge management margin, partially offset by lower purchased
power and fuel costs due to lower spot market prices (14)
Effects of weather on retail sales (10)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 22
Retail price reduction effective July 1, 2002 (9)
Change in mark-to-market for hedged natural gas and purchased
power costs for future period deliveries (see Note 10) (10)
Miscellaneous factors, net (6)
----------
Net decrease in electric retail segment gross margin (12)
----------
Total decrease in electric retail and marketing and trading segments'
gross margins (76)
Lower other gross margin primarily related to losses recorded on El Dorado's
investment in NAC (see Note 14) (13)
Lower operations and maintenance expense primarily related to lower
generation reliability costs, partially offset by 2002 severance costs of
$25 million (see Note 17) and other costs 6
Higher other expense (7)
Higher net interest expense primarily due to higher debt balances (8)
Miscellaneous items, net (1)
----------
Decrease in income before income taxes (99)
Lower income taxes primarily due to lower pretax income 38
----------
Decrease in income before accounting change $ (61)
==========
(a) Net recognized marketing and trading gains (excluding the effects of
generation sales other than Native Load) increased $42 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.
33
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $54 million lower in the
three-month period ended September 30, 2002, compared with the same period in
the prior year as a result of:
* increased revenues from generation sales other than Native Load due to
higher sales volumes ($4 million);
* increased realized revenues from other realized marketing and trading
in the current period primarily due to higher sales volumes ($10
million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to lower unit margins on higher volumes
being delivered ($40 million increase); 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 ($108 million).
Marketing and trading segment purchased power and fuel costs were $10
million higher in the three-month period ended September 30, 2002, compared to
the same period in the prior year as a result of:
* increased fuel costs related to generation sales other than Native
Load primarily because of higher sales volumes and higher natural gas
prices ($4 million);
* increased purchased power costs related to other realized marketing
activities in the current period primarily due to higher sales volumes
($7 million); and
* other miscellaneous factors ($1 million decrease).
ELECTRIC RETAIL SEGMENT GROSS MARGIN
Revenues related to our regulated retail and wholesale electricity
businesses were $254 million lower in the three-month period ended September 30,
2002, compared with the same period in the prior year as a result of:
* decreased revenues related to wholesale sales for retail load hedge
management, as a result of lower prices ($265 million);
* decreased retail revenues related to milder weather ($15 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($33 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($9 million); and
* other miscellaneous factors ($2 million net increase).
Electric retail segment purchased power and fuel costs were $242 million
lower in the three-month period ended September 30, 2002, compared with the same
period in the prior year as a result of:
* decreased costs related to lower prices for hedged natural gas and
purchased power ($251 million);
* decreased costs related to the effects of milder weather on retail
sales ($5 million);
34
* increased costs related to retail sales growth, excluding weather
effects ($11 million);
* change in mark-to-market for hedged natural gas and purchased power
costs for future period deliveries (see Note 10) ($10 million
increase);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned nuclear and coal plant outages ($15
million); and
* other miscellaneous factors ($8 million net increase).
The decrease in other gross margin of $13 million was primarily due to
losses recorded on El Dorado's investment in NAC (see Note 14).
The decrease in operations and maintenance expense of $6 million was due to
lower costs related to generation reliability, plant outages and maintenance
costs of $24 million. These factors were partially offset by severance costs of
$25 million related to a 2002 voluntary workforce reduction (see Note 17) and
other costs.
Other expense increased $7 million primarily due to higher net investment
losses in the current period and higher miscellaneous non-operating costs.
Interest expense, net of amounts capitalized, increased $8 million
primarily due to higher debt balances.
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2002 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2001
Our consolidated net income for the nine months ended September 30, 2002
was $230 million compared with $276 million for the same period in the prior
year. We recognized a $15 million after-tax loss in the nine months ended
September 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 nine months ended September 30,
2002 was $230 million compared with $291 million for the same period in 2001.
The period-to-period decrease was the result of lower earnings contributions
from our marketing and trading activities, severance costs of $25 million pretax
recorded in the third quarter of 2002 related to a voluntary workforce reduction
(see Note 17) and losses related to El Dorado's investment in NAC (see Note 14),
partially offset by increased earnings contributions from our regulated retail
electricity and real estate operations. The regulated retail comparison was
favorably impacted by lower replacement costs for power plant outages, customer
growth and higher average usage per customer, lower costs for purchased power
and gas related to lower market prices, and lower generation reliability
expenses, partially offset by the effects of milder weather and retail
electricity price decreases. 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.
35
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Marketing and trading segment gross margin:
Decrease in generation sales other than Native Load due to lower
market prices and resulting lower sales volumes $ (72)
Increase in other realized marketing and trading in the current period
primarily due to higher unit margins on increased volumes 35(a)
Change in prior period mark-to-market gains on contracts delivered
during the current period (b) (55)(a)
Lower mark-to-market gains for future period deliveries (b) (118)
----------
Net decrease in marketing and trading segment gross margin (210)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower market
prices and fewer unplanned outages 123
Lower purchased power and fuel costs related to lower prices, net of
hedge management sales 2
Effects of weather on retail sales (21)
Higher retail sales volumes due to 3.1% customer growth and higher
average usage, excluding weather effects 37
Retail price reductions effective July 1, 2001 and July 1, 2002 (22)
Change in mark-to-market for hedged natural gas and purchased
power costs for future period deliveries (see Note 10) 5
Miscellaneous factors, net (12)
----------
Net increase in electric retail segment gross margin 112
----------
Total decrease in electric retail and marketing and trading segments'
gross margins (98)
Higher real estate margin primarily due to increased sales activities 10
Lower other gross margin primarily related to losses recorded on El Dorado's
investment in NAC (see Note 14) (13)
Lower operations and maintenance expense primarily related to lower
generation reliability costs, partially offset by 2002 severance costs of
$25 million (see Note 17) and other costs 17
Lower depreciation and amortization expense primarily due to lower
regulatory asset amortization, partially offset by higher depreciation
on higher plant balances 8
Lower other income (9)
Higher other expense (7)
Higher net interest expense primarily due to higher debt balances,
partially offset by lower interest rates (8)
Miscellaneous factors, net 1
----------
Decrease in income before income taxes (99)
Lower income taxes primarily due to lower pretax income 38
----------
Decrease in income before accounting change $ (61)
==========
36
(a) Net recognized marketing and trading gains (excluding the effects of
generation sales other than Native Load) 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.
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $421 million lower in the
nine-month period ended September 30, 2002, compared with 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 ($124 million);
* decreased revenues from other realized marketing and trading in the
current period primarily due to lower prices ($132 million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to higher volumes being delivered ($47
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 ($118 million).
Marketing and trading segment purchased power and fuel costs were $211
million lower in the nine-month period ended September 30, 2002, compared with
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 natural gas prices and lower sales
volumes ($52 million);
* decreased purchased power costs related to other realized marketing
activities in the current period primarily due to lower prices ($167
million); and
* change in prior period mark-to-market fuel costs for current period
deliveries ($8 million net increase).
ELECTRIC RETAIL SEGMENT GROSS MARGIN
Revenues related to our regulated retail and wholesale electricity
businesses were $529 million lower in the nine-month period ended September 30,
2002, compared with 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 ($65 million);
* decreased revenues related to wholesale sales for retail load hedge
management, as a result of lower prices and lower sales volumes ($439
million);
* decreased retail revenues related to milder weather ($50 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($68 million);
* decreased retail revenues related to reductions in retail electricity
prices ($22 million); and
37
* other miscellaneous factors ($21 million net decrease).
Electric retail segment purchased power and fuel costs were $641 million
lower in the nine-month period ended September 30, 2002, compared with 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 ($65 million);
* decreased costs related to lower prices for hedged natural gas and
purchased power ($441 million);
* decreased costs related to the effects of milder weather on retail
sales ($29 million);
* increased costs related to retail sales growth, excluding weather
effects ($31 million);
* change in mark-to-market for hedged natural gas and purchased power
costs for future period deliveries (see Note 10) ($5 million
decrease);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned nuclear and coal plant outages ($123
million); and
* other miscellaneous factors ($9 million net decrease).
The increase in real estate gross margin of $10 million was primarily due
to increased sales activities.
The decrease in other gross margin of $13 million was primarily due to
losses recorded on El Dorado's investment in NAC (see Note 14).
The decrease in operations and maintenance expense of $17 million was
primarily due to lower costs related to generation reliability, plant outages
and maintenance costs of $38 million. 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 (see Note 12).
These decreases were partially offset by severance costs of $25 million related
to a 2002 voluntary workforce reduction (see Note 17) and other costs.
The decrease in depreciation and amortization expense of $8 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.
Other expense increased $7 million primarily due to losses recorded on El
Dorado's investments in the current period, partially offset by lower
miscellaneous non-operating costs.
Interest expense increased $8 million primarily due to higher debt
balances, partially offset by lower interest rates.
38
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2002 COMPARED
WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2001
Our consolidated net income for the twelve months ended September 30, 2002
was $266 million compared with $319 million for the same period in the prior
year. We recognized a $15 million after-tax loss in the twelve months ended
September 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 twelve months ended September
30, 2002 was $266 million compared with $334 million for the same period a year
earlier. The period-to-period comparison was lower due to lower earnings
contributions from our marketing and trading activities, severance costs of $25
million pretax recorded in the third quarter of 2002 relating to a voluntary
workforce reduction (see Note 17), and losses related to El Dorado's investment
in NAC (see Note 14), partially offset by increased earnings contributions from
our regulated retail electricity and real estate operations. The regulated
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 retail electricity price decreases. 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.
39
The major factors that increased (decreased) income before accounting change
were as follows (dollars in millions):
Increase
(Decrease)
----------
Marketing and trading segment gross margin:
Decrease in generation sales other than Native Load due to lower
market prices and resulting lower sales volumes $ (108)
Increase in other realized marketing and trading in the current period
primarily due to higher unit margins on increased volumes 91(a)
Change in prior period mark-to-market gains on contracts delivered
during the current period (b) (114)(a)
Lower mark-to-market gains for future period deliveries (b) (105)
----------
Net decrease in marketing and trading segment gross margin (236)
----------
Electric retail segment gross margin:
Lower replacement power costs for plant outages due to lower market
prices and fewer unplanned outages 148
Lower hedge management margins, partially offset by lower
purchased power and fuel costs due to lower market prices (12)
Effects of milder weather on retail sales (21)
Higher retail sales volumes due to customer growth and higher
average usage, excluding weather effects 39
Retail price reductions effective July 1, 2001 and July 1, 2002 (28)
Change in mark-to-market for hedged natural gas and purchase
power costs for future period deliveries (see Note 10) 4
Miscellaneous factors, net (7)
----------
Net increase in electric retail segment gross margin 123
----------
Total decrease in electric retail and marketing and trading segments'
gross margins (113)
Higher real estate gross margin primarily due to increased sales activities 12
Lower other gross margin primarily related to losses recorded on El Dorado's
investment in NAC (see Note 14) (13)
Lower operations and maintenance expense primarily related to lower
generation reliability costs, partially offset by 2002 severance costs
of $25 million (see Note 17) and other costs 15
Lower depreciation and amortization primarily due to lower regulatory asset
amortization, partially offset by increased depreciation and
amortization on higher property, plant and equipment balances 5
Lower other income (5)
Higher net interest expense primarily due to higher debt balances, partially
offset by higher capitalized interest and lower interest rates (7)
Miscellaneous factors, net (2)
----------
Decrease in income before income taxes (108)
Lower income taxes primarily due to lower income 40
----------
Decrease in income before accounting change $ (68)
==========
40
(a) Net marketing and trading gains (excluding the effects of generation sales
other than Native Load) recognized for the current period decreased $23
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.
MARKETING AND TRADING SEGMENT GROSS MARGIN
Marketing and trading segment revenues were $586 million lower in the
twelve-month period ended September 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 ($198 million);
* decreased revenues from other realized marketing and trading in the
current period primarily due to lower prices ($176 million);
* change in prior period mark-to-market gains on contracts delivered
during the current period due to higher volumes being delivered ($107
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 ($105 million).
Marketing and trading segment purchased power and fuel costs were $350
million lower in the twelve-month period ended September 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 ($90 million);
* decreased purchased power costs related to other realized marketing
activities in the current period primarily due to lower prices ($267
million); and
* change in prior period mark-to-market fuel costs for current period
deliveries ($7 million increase).
ELECTRIC RETAIL SEGMENT GROSS MARGIN
Revenues related to our regulated retail and wholesale electricity
businesses were $548 million lower in the twelve-month period ended September
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 ($458
million);
* decreased retail revenues related to milder weather ($50 million);
* increased retail revenues related to customer growth and higher
average usage, excluding weather effects ($82 million);
* decreased retail revenues related to reductions in retail electricity
prices ($28 million); and
41
* other miscellaneous factors ($15 million net decrease).
Electric retail segment purchased power and fuel costs were $671 million
lower in the twelve-month period ended September 30, 2002, compared with 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 prices ($446 million);
* decreased costs related to the effects of milder weather on retail
sales ($29 million);
* increased costs related to retail sales growth, excluding weather
effects ($43 million);
* change in mark-to-market for hedged natural gas and purchased power
costs for future period deliveries (see Note 10) ($4 million
decrease);
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($148 million); and
* miscellaneous factors ($8 million net decrease).
The increase in real estate gross margin of $12 million was primarily due
to increased sales activities.
The decrease in other gross margin of $13 million was primarily due to
losses on El Dorado's investment in NAC (see Note 14).
The decrease in operations and maintenance expense of $15 million was
primarily due to lower costs related to generation reliability, plant outages
and maintenance costs of $37 million. Operations 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 (see Note 12),
partially offset by severance costs of $25 million related to a 2002 voluntary
workforce reduction (see Note 17) and other costs.
The decrease in depreciation and amortization expenses of $5 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 regulatory settlement, partially offset by increased depreciation and
amortization on higher property, plant and equipment balances.
Other income decreased $5 million primarily due to an insurance recovery
recorded in the prior period related to environmental remediation costs and
other costs.
Net interest expense increased $7 million primarily because of higher debt
balances related to our generation expansion program, partially offset by the
increase in capitalized interest on our generation expansion program and lower
interest rates.
42
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the nine
months ended September 30, 2002 and estimated capital expenditures for the next
three years (dollars in millions):
Nine Months
Ended Estimated
September 30, ----------------------------
2002 2002 2003 2004
------ ------ ------ ------
APS
Delivery $ 270 $ 347 $ 270 $ 267
Existing generation (a) 106 149 116 89
------ ------ ------ ------
Subtotal 376 496 386 356
------ ------ ------ ------
Pinnacle West Energy (b) 306 411 257 109(e)
SunCor(c) 55 79 48 52
Other(d) 22 38 22 21
------ ------ ------ ------
Total $ 759 $1,024 $ 713 $ 538
====== ====== ====== ======
(a) This table assumes that APS and Pinnacle West Energy generation assets
remain separated, consistent with the ACC's Track A Order (see Note 5).
(b) See further discussion of Pinnacle West Energy's generation expansion
program in "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 the parent company and APS Energy Services.
(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.
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, APS began several major transmission projects
in 2001. These projects are periodic in nature and are driven by strong regional
customer growth. APS expects to spend about $150 million on major transmission
projects during the 2002 to 2004 time frame.
43
Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants and the replacement of
steam generators. Examples of the types of projects included in this category
are additions, upgrades and capital replacements of various power plant
equipment such as turbines, boilers, and environmental equipment. The existing
generation also contains nuclear fuel expenditures of approximately $30 million
annually in 2002, 2003, and 2004.
Several years ago APS and the other Palo Verde participants decided to
replace Palo Verde 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 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. Existing generation in 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, APS has estimated that its 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.
CAPITAL RESOURCES AND CASH REQUIREMENTS
CONTRACTUAL COMMITMENTS
The following table summarizes actual contractual cash commitments for the
nine months ended September 30, 2002 and estimated contractual commitments for
the next five years and thereafter (dollars in millions):
Estimated
Nine -----------------------------------------------------
Months Years Ended December 31,
Ended -----------------------------------------------------
September 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 11 11 117 -- -- 3 16
------ ------ ------ ------ ------ ------ ------
Total long-term debt payments 258 259 393 421 400 387 1,534
Operating leases payments 47 68 66 65 64 63 550
Fuel and purchase power
commitments 258 338 134 82 65 68 170
------ ------ ------ ------ ------ ------ ------
Total cash commitments (a) 563 $ 665 $ 593 $ 568 $ 529 $ 518 $2,254
====== ====== ====== ====== ====== ====== ======
(a) Total cash commitments are approximately $5.1 billion. The total net
present value of these cash commitments is approximately $3.0 billion.
44
CONTINGENT COMMITMENTS
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 (primarily equipment and
performance guarantees), enable APS Energy Services to provide commodity energy
and energy-related products and enable El Dorado to support the activities of
NAC. The amounts as of September 30, 2002 are listed as follows (dollars in
millions):
Guarantees Surety Bonds
---------- ------------
Pinnacle West Energy $ 250 $ --
APS Energy Services 72 39
El Dorado 43 --
In addition, as of September 30, 2002, SunCor had outstanding guarantees of
approximately $29 million on behalf of affiliated joint ventures.
CREDIT RATINGS
The ratings of securities of Pinnacle West and APS as of the date of this
report are shown below and reflect the respective views of the rating agencies,
from whom an explanation of the significance of their ratings may be obtained.
There is no assurance that these ratings will continue for any given period of
time or that they will not be revised or withdrawn entirely by the rating
agencies, if, in their respective judgments, circumstances so warrant. Any
downward revision or withdrawal may adversely effect the market price of
Pinnacle West's or APS' securities and serve to increase those companies' cost
of capital, and access to capital.
Moody's Standard & Poor's Fitch
------- ----------------- -----
PINNACLE WEST
Senior Unsecured Baa2 BBB- BBB
Commercial Paper P-2 A-2 F-2
APS
Senior Secured A3 A- A-
Senior Unsecured Baa1 BBB BBB+
Secured Lease
Obligation Bonds Baa2 BBB BBB
Commercial Paper P-2 A-2 F-2
On November 4, 2002 Standard & Poor's affirmed the APS debt ratings in the
above chart, but lowered Pinnacle West's senior unsecured debt rating from BBB
to BBB- "because of the structural subordination of this debt as compared to the
unsecured debt at APS." On that same date, Standard & Poor's lowered APS'
corporate credit rating from BBB+ to BBB and affirmed the BBB corporate credit
rating of Pinnacle West. All of Pinnacle West's and APS' credit ratings remain
investment grade. Standard & Poor's assigned a stable outlook to the ratings.
45
DEBT PROVISIONS
Pinnacle West's and APS' significant debt covenants related to their
respective financing arrangements include a debt- to-total-capitalization ratio
and an interest coverage test. Pinnacle West and APS are in compliance with such
covenants and each anticipates that it will continue to meet all the significant
covenant requirement levels. Failure to comply with such covenant levels would
result in an event of default which, generally speaking, would require the
immediate repayment of the debt subject to the covenants.
Neither Pinnacle West's nor APS' financing agreements contain "ratings
triggers" that would result in an acceleration of the required interest and
principal payments in the event of a ratings downgrade. However, in the event of
a ratings downgrade, Pinnacle West and/or APS may be subject to increased
interest costs under certain financing agreements. We are unable to quantify the
effects, if any, that Standard & Poor's lowering of Pinnacle West's senior
unsecured debt rating may have on Pinnacle West's borrowing costs in 2002
through 2004 or whether the lower rating will affect the timing or nature of the
Company's capital requirements.
All of Pinnacle West's bank agreements contain "cross-default" provisions
under which a default by it or APS in a specified amount under another agreement
would result in a default and the potential acceleration of payment under the
agreements. All of APS' bank agreements contain cross-default provisions under
which a default by APS in a specified amount under another agreement would
result in a default and the potential acceleration of payment under the
agreements. Pinnacle West's and APS' credit agreements generally contain
provisions under which the lenders could refuse to advance loans in the event of
a material adverse change in the borrower's business or financial condition.
PINNACLE WEST (PARENT COMPANY)
Our primary cash needs are for dividends to our shareholders; equity
infusions into our subsidiaries, primarily Pinnacle West Energy; interest
payments; and optional and mandatory repayments of principal on our long-term
debt (see the table above for the Company's contractual cash commitments,
including our debt repayment obligations). On October 23, 2002, the Company's
board of directors increased the common stock dividend to an indicated annual
rate of $1.70 per share from $1.60 per share, effective with the December 1,
2002 dividend payment. The Company currently intends to continue growing the
common dividends in the future; such growth will be dependent on a number of
factors including, but not limited to, payout ratio trends, free cash flow, and
financial market conditions.
Our primary sources of cash are dividends from APS, our marketing and
trading operations, external financings, and cash distributions from our other
subsidiaries, primarily SunCor. For the years 1999 through 2001, total dividends
from APS were $510 million. For the nine months ended September 30, 2002,
dividends from APS were approximately $128 million. We expect SunCor to make
cash distributions to the Company of $80 million to $100 million annually in
2003 through 2005 due to anticipated accelerated asset sales activity.
46
On February 8, 2002, we issued $215 million of 4.5% Notes due 2004. 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. The majority of these borrowings were used to fund
Pinnacle West Energy capital expenditures.
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 discussed in Note 5, on September 16, 2002, APS filed a
Financing Application requesting the ACC to allow APS to borrow up to $500
million and to lend the proceeds to Pinnacle West Energy or to the Company; to
guarantee up to $500 million of Pinnacle West Energy's debt or of the Company's
debt; or a combination of both, not to exceed $500 million in the aggregate. In
the Financing Application, APS stated that the ACC's reversal of the generation
asset transfer requirement and the resulting bifurcation of generation assets
between APS and Pinnacle West Energy under different regulatory regimes results
in Pinnacle West Energy being unable to attain investment-grade credit ratings.
This, in turn, precludes Pinnacle West Energy from accessing capital markets to
refinance the bridge financing provided by the Company to fund the construction
of Pinnacle West Energy generation assets or from effectively competing in the
wholesale markets. APS noted that Pinnacle West Energy had previously received
investment-grade credit ratings contingent upon its receipt of APS generation
assets, and that the Company's credit ratings could be adversely affected if
Pinnacle West Energy is unable to finance its capital requirements. On November
4, 2002, Standard & Poor's lowered the Company's senior unsecured debt rating
from BBB to BBB-. See "Credit Ratings" above. On November 8, 2002, APS filed
an Interim Financing Application with the ACC requesting the ACC to permit APS
to (a) make short-term advances to Pinnacle West in the form of an
inter-affiliate line of credit in the amount of $125 million or (b) guarantee
$125 million of Pinnacle West's short-term debt. See "ACC Applications" in Note
5.
The parent company's outstanding debt was approximately $1.1 billion at
September 30, 2002. At September 30, 2002, we had credit commitments from
various banks totaling $250 million, which were available to support the
issuance of commercial paper or to be used as bank borrowings. At September 30,
2002, we had about $206 million of commercial paper outstanding and $35 million
of short-term borrowings. In addition, as noted above, we had an additional $300
million of borrowing capacity under a credit facility with various banks, under
which $45 million had been borrowed as of September 30, 2002.
In mid-2003, the Company will need to refinance approximately $550 million
of parent company indebtedness, including a total of $300 million we expect to
borrow under the credit facility referenced in the preceding paragraph. If the
ACC does not grant the approvals requested in
47
the Financing Application in a timely fashion, the Company would anticipate
taking the following steps, to the extent necessary in priority order, although
the timing of the Company's liquidity needs may affect the order of the steps
taken:
* The reduction of capital expenditures through plant delay and
cancellation;
* The sale of non-core assets; and
* The issuance of new debt and, if appropriate, new equity.
Although we believe it would be inappropriate to discuss specific amounts
for each of the foregoing categories, we estimate the sum of these steps to
approximate the current outstanding debt at the Company, which, as noted above,
totaled approximately $1.1 billion as of September 30, 2002. We believe, even in
this scenario, if the parent company's near-term debt maturities were paid in
full, that the Company's common stock dividend would remain intact.
As part of a multi-employer pension plan sponsored by Pinnacle West, we
contribute 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 voluntarily contributed cash to our pension plan in
each of the last four years; 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. APS and other subsidiaries fund
their share of the pension contribution, of which APS represents approximately
90% of the total funding amounts described above. The assets in the plan are
mostly domestic common stocks, bonds and real estate. We currently forecast a
pension contribution in 2003 of approximately $50-$80 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.
As a result of change in IRS guidance, we claimed a tax deduction related
to an APS tax accounting method change on the 2001 Federal consolidated income
tax return. The accelerated deduction has resulted in a $200 million reduction
in current tax liability.
APS
APS' capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. On September 16, 2002, APS
filed a Financing Application with the ACC requesting the ACC to allow APS to
borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to
the Company; to guarantee up to $500 million of Pinnacle West Energy's or the
Company's debt; or a combination of both, not to exceed $500 million in the
aggregate. On November 8, 2002, APS filed an Interim Financing Application with
the ACC requesting the ACC to permit APS to (a) make short-term advances to
Pinnacle West in the form of an inter-affiliate line of credit in the amount of
$125 million or (b) guarantee $125 million of Pinnacle West's short-term debt.
See "ACC Applications" in Note 5 for a discussion of the Financing Application
and the Interim Financing Application. See the table above for APS' cash
commitments, including its debt repayment obligations; that table does not take
into account any funds that APS may lend to Pinnacle West Energy, or the Company
consistent with the Interim Financing Application or the Financing Application.
48
APS pays for its capital requirements with cash from operations and, to the
extent necessary, external financings. APS pays for its dividends to Pinnacle
West with cash from operations.
On March 1, 2002, APS issued $375 million of 6.5% Notes due 2012.
On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation
issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona
Public Service Company Palo Verde Project) 2002 Series A, due 2029 and loaned
the proceeds to APS pursuant to a loan agreement. The bonds were issued to
refinance $90 million of outstanding pollution control bonds.
On March 15, 2002, APS redeemed at maturity $125 million of its First
Mortgage Bonds, 8.125% Series due 2002. On April 15, 2002, APS redeemed $122
million of its First Mortgage Bonds, 8.75% Series due 2024. 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.
At September 30, 2002, APS had credit commitments from various banks
totaling about $250 million, which were available either to support the issuance
of commercial paper or to be used as bank borrowings. At September 30, 2002, APS
had about $25 million of commercial paper outstanding and no bank borrowings.
Although provisions in APS' first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds, debt and preferred stock that APS may issue, APS does not
expect any of these provisions to limit its ability to meet its capital
requirements.
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 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. See the capital expenditures table above for actual
capital expenditures through September 30, 2002 and projected capital
expenditures for the next three years.
As discussed under "ACC Applications" in Note 5, APS has filed a Financing
Application with the ACC requesting the ACC to allow APS to borrow up to $500
million and to lend the proceeds to Pinnacle West Energy or the Company; to
guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or
a combination of both, not to exceed $500 million in the aggregate. In the
Financing Application, APS stated that the ACC's reversal of the generation
49
asset transfer requirement and the resulting bifurcation of generation assets
between APS and Pinnacle West Energy under different regulatory regimes results
in Pinnacle West Energy being unable to attain investment grade credit ratings.
This, in turn, precludes Pinnacle West Energy from accessing capital markets to
refinance the bridge financing provided by the Company to fund the construction
of Pinnacle West Energy generation assets or from effectively competing in the
wholesale markets. On November 8, 2002, APS filed an Interim Financing
Application with the ACC requesting the ACC to permit APS to (a) make short-term
advances to Pinnacle West in the form of an inter-affiliate line of credit in
the amount of $125 million or (b) guarantee $125 million of Pinnacle West's
short-term debt.
Pinnacle West Energy has completed or is currently planning the following
natural gas-fired plants and other projects:
* A 650 MW combined cycle expansion of the West Phoenix Power Plant in
Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation in
June 2001. Construction has begun on the 530 MW West Phoenix Unit 5,
with commercial operation expected to begin in mid-2003.
* The Redhawk Power Plant Units 1 and 2 are each 530 MW combined cycle
units, near Palo Verde. Commercial operations began in July 2002 for
Units 1 and 2. The Company is evaluating whether to construct Redhawk
Units 3 and 4. Pinnacle West Energy has procured four gas turbines for
Redhawk Units 3 and 4. The cancellation cost for these turbines would
be approximately $50 million until September 2003.
* The construction of an 80 MW simple cycle power plant at Saguaro in
Southern Arizona. Commercial operation began in July 2002.
* Development of the 570 MW Silverhawk combined cycle plant 20 miles
north of Las Vegas, Nevada. Construction of the plant began in August
2002, with an expected commercial operation date in mid-2004. As noted
above, Pinnacle West Energy has signed an agreement with Las
Vegas-based SNWA under which SNWA has an option to purchase a 25%
interest in the project.
* 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, SunCor funded its cash requirements with cash
from operations and its own external financings. SunCor's capital needs consist
primarily of capital expenditures for land development and retail and office
building construction. See the capital expenditures table above for actual
capital expenditures in the nine months ended September 30, 2002 and projected
capital expenditures for the next three years. SunCor expects to fund its
50
capital requirements with cash from operations and external financings. SunCor's
long-term indebtedness decreased $11 million in the nine months ended September
30, 2002. SunCor has provided guarantees of approximately $29 million on behalf
of affiliated joint ventures.
We expect SunCor to make cash distributions to the parent company of $80
million to $100 million annually in 2003 through 2005 due to anticipated
accelerated asset sales activity.
El Dorado funded its cash requirements during the past three years with
cash from operations and with cash infused by the parent company, primarily for
NAC in 2002. El Dorado expects minimal 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. El Dorado's long-term indebtedness increased $9 million
during the nine months ended September 30, 2002, due to its consolidation of NAC
for financial reporting purposes.
APS Energy Services' cash requirements during the past three years were
funded with cash infusions from the parent company. APS Energy Services' capital
expenditures and other cash requirements are increasingly funded by operations,
with some funding from cash infused by Pinnacle West. See the capital
expenditures table above regarding APS Energy Services' capital expenditures.
See "Business Outlook" below for information about the expected earnings
contributions of SunCor, El Dorado and APS Energy Services.
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 (see Note 8) and the impacts of regulatory accounting (see Note 19)
on our consolidated financial statements. See Note 1 in the 2001 10-K.
BUSINESS OUTLOOK
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.
51
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.
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
3.1% 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, although recent regulatory developments and
legal challenges to the Rules have raised considerable uncertainty about the
status and pace of retail electric competition in Arizona (see Note 5). 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.
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
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. We implemented a
voluntary workforce reduction program announced in July 2002. We recorded $25
million before taxes in voluntary severance costs in the third quarter of 2002.
We expect to record up to $12 million before taxes for additional severance
costs in the fourth quarter of 2002 (See Note 17). In addition, we are expecting
to produce annual operating expense savings of approximately $30 million
beginning in 2003.
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, West
Phoenix Unit 4 was placed in service in June 2001, Redhawk Units 1 and 2 and the
new Saguaro unit began commercial operations in July 2002, West Phoenix Unit 5
is expected to be on line in mid-2003 and Silverhawk is expected to be in
52
service in mid-2004. The regulatory assets to be recovered under the 1999
Settlement Agreement are currently being amortized as follows (dollars in
millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $686
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, we have placed new power plants in commercial
operation in 2001 and 2002 and we expect to bring additional plants on-line in
2003 and 2004. We are continuing to evaluate our generation expansion program.
If we decide not to construct Redhawk Units 3 and 4, we would expect to
record a pretax charge of approximately $50 million related to the cancellation
of gas turbine contracts.
The regulatory developments and legal challenges to the Rules discussed in
Note 5 have raised considerable uncertainty about the status and pace of
electric competition in Arizona. Although some very limited retail competition
existed in APS' service area in 1999 and 2000, there are currently no active
retail competitors offering unbundled energy or other utility services to APS'
customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter APS' service territory. As competition in
the electric industry continues to evolve, we will continue to evaluate
strategies and alternatives that will position us to compete effectively in a
restructured industry.
In the case of SunCor, we are undertaking an aggresive effort to accelerate
asset sales activities to approximately double SunCor's annual earnings in the
2003-2005 period compared to the approximate $20 million in earnings expected
for 2002.
The annual earnings contribution from APS Energy Services is expected to be
positive over the next several years due primarily to a number of retail
electricity contracts in California. APS Energy Services' pretax losses were $10
million in 2001 and $13 million in 2000.
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.
Our financial results may be affected by the application of SFAS No. 133.
See Note 10 for further information.
On October 25, 2002, the EITF voted to rescind EITF 98-10 (see Note 8). We
are evaluating the current effect of the rescission on our financial results.
On November 4, 2002, Standard & Poor's lowered the Company's senior
unsecured debt rating from BBB to BBB-. See "Credit Ratings" above. We are
unable to quantify the effects, if any, that Standard & Poor's lowering of
53
Pinnacle West's senior unsecured debt rating may have on Pinnacle West's
borrowing costs or whether the lower rating will affect the timing or nature of
the Company's capital requirements.
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.
The Company's current 2002 adjusted debt to total capitalization ratio,
adjusted as per rating agency methodology to include debt and equity related to
Palo Verde SPE's (see Note 9), is approximately 60%. The Company expects to
decrease the adjusted debt to total capitalization ratio to approximately 55%
over the next several years.
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.
RISK FACTORS
Exhibit 99.3, which is hereby incorporated by reference, contains a
discussion of risk factors involving the Company.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements or to make
any further statements on any of these issues, 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.
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.
54
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 ERMC, 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. See Note 8 for a
discussion of the EITF's decision to rescind EITF 98-10.
The following schedule shows the changes in mark-to-market on our trading
positions during the three, nine and twelve months ended September 30, 2002
(dollars in millions):
Periods Ended September 30, 2002
------------------------------------------
Three Months Nine Months Twelve Months
Ended Ended Ended
------------ ----------- -------------
Mark-to-market of net
trading positions at
beginning of period $ 133 $ 138 $ 198
Prior period mark-to-
market (gains) losses
realized during the
period 3 (34) (96)
Change in mark-to-
market gains for
future period
deliveries 23 55 57
Change in valuation
techniques -- -- --
------ ------ ------
Mark-to-market of net
trading positions at
end of period $ 159 $ 159 $ 159
====== ====== ======
Net gains at inception were approximately zero for the three months ended
September 30, 2002. Net gains at inceptions were approximately $10 million for
55
the nine months ended September 30, 2002 and $11 million for the twelve months
ended September 30, 2002, these amounts included a reasonable marketing margin.
See Note 10 for mark-to-market on system hedges and for disclosure of risk
management activities recorded on the condensed consolidated balance sheets.
The table below shows the maturities of our trading positions as of
September 30, 2002, by the type of valuation that is performed to calculate the
fair value of the contract (dollars in millions):
Years Total
there- fair
SOURCE OF FAIR VALUE 2002 2003 2004 2005 2006 after value
------ ------ ------ ------ ------ ------ ------
Prices actively quoted $ (7) $ 8 $ 5 $ 6 $ 3 $ 9 $ 24
Prices provided by other
external sources (1) (3) (8) 4 5 -- (3)
Prices based on models
and other valuation
methods 20 26 38 20 18 16 138
------ ------ ------ ------ ------ ------ ------
Total by maturity $ 12 $ 31 $ 35 $ 30 $ 26 $ 25 $ 159
====== ====== ====== ====== ====== ====== ======
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 September
30, 2002 (dollars in millions):
September 30, 2002
-------------------------
Gain(Loss)
-------------------------
Price Up Price Down
Commodity 10% 10%
--------- -------- ----------
Trading (a):
Electricity $ (1) $ 2
Natural gas (1) 1
Other 1 --
System (b):
Natural gas
hedges 17 (15)
------ ------
Total $ 16 $ (12)
====== ======
(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.
56
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 $260 million of risk management and trading
assets as of September 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 our 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 funds. 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 trust
funds also have risks associated with changing market values of equity
investments. Pension and nuclear decommissioning costs are recovered in
regulated electricity prices.
ITEM 4. CONTROLS AND PROCEDURES
As of a date within 90 days of the date of this report (the "Evaluation
Date"), we carried out an evaluation, under the supervision and with the
participation of our management, including our President and Chief Executive
Officer and our Vice President, Finance, of the effectiveness of the design and
operation of our disclosure controls and procedures, as defined in Rules 13a-14
and 15d-14 under the Securities Exchange Act of 1934, as amended (the "Exchange
Act"). Based upon this evaluation, our President and Chief Executive Officer and
our Vice President, Finance, concluded that, as of the Evaluation Date, our
disclosure controls and procedures were adequate to ensure that information
required to be disclosed by us in the reports filed or submitted by us under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms.
There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
the evaluation, including any corrective actions with regard to significant
deficiencies and internal weaknesses.
57
PART II - OTHER INFORMATION
ITEM 5. OTHER INFORMATION
CONSTRUCTION AND FINANCING PROGRAMS
See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
a discussion of construction and financing programs of the Company 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.
REGIONAL TRANSMISSION ORGANIZATIONS
As previously reported, on October 16, 2001, APS and other owners of
electric transmission lines in the Southwest filed with the FERC a request for a
declaratory order confirming that their proposal to form WestConnect RTO, LLC
would satisfy the FERC's requirements for the formation of a regional
transmission organization ("RTO"). See "Regulation and Competition - Wholesale -
Regional Transmission Organizations" in Part I, Item 1 of the 2001 10-K. On
October 10, 2002, the FERC issued an order finding that the WestConnect
proposal, if modified to address specified issues, could meet the FERC's RTO
requirements and provide the basic framework for a standard market design for
the Southwest. In its order, the FERC also stated that its approval of various
WestConnect provisions addressed in the order would not be overturned or
affected by the final rule the FERC intends to ultimately adopt in response to
its July 31, 2002 Notice of Proposed Rulemaking regarding a standard market
design for the electric utility industry (see "Federal" in Note 5 for additional
information regarding the Notice of Proposed Rulemaking). FERC did not address
all of the proposed WestConnect provisions in its order and some could still be
affected by a final rule in the pending rulemaking proceeding. We cannot
currently predict what, if any, impact there may be to the WestConnect proposal
or to us if the FERC adopts the proposed SMD rule. On November 12, 2002, APS and
other owners filed a request for rehearing and clarification on portions of the
October 10 order.
NATURAL GAS SUPPLY
As previously reported on May 31, 2002, the FERC issued an order requiring
the conversion of all Full Requirements contracts to Contract Demand contracts.
See "Natural Gas Supply in Part II, Item 5 of the June 10-Q. On September 20,
2002, the FERC issued another order clarifying the capacity allocation
methodology, extending the conversion implementation date from November 1, 2002
to May 1, 2003 and approving reallocation of costs for service. APS and other
Full Requirement contract holders have sought rehearings of the FERC orders. We
currently do not expect this to have a material adverse impact on our financial
position, results of operations or liquidity.
58
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 "Coal Supply" in Part II, Item 5 of the
June 2002 10-Q. 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 and that settlement agreement was 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.
59
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
3.1 Pinnacle West Bylaws, amended as of September 18, 2002
3.2 APS Bylaws, amended as of September 18, 2002
10.1 Employment Agreement effective as of October 1, 2002
between APS and James M. Levine
12.1 Ratio of Earnings to Fixed Charges
99.1 Certification of William J. Post, the Registrant's
principal executive officer, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
99.2 Certification of Michael V. Palmeri, the Registrant's
principal financial officer, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
99.3 Pinnacle West Risk Factors
In addition, the Company hereby incorporates the following Exhibits
pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to
the filings set forth below:
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
(b) Reports on Form 8-K
During the quarter ended September 30, 2002, and the period from October 1
through November 14, 2002, we filed the following reports on Form 8-K:
Report dated June 30, 2002 regarding exhibits comprised of financial
information and earnings variance explanations.
- ----------
(a) Reports filed under File No. 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
60
Report dated July 11, 2002 regarding a letter APS filed with the ACC.
Report dated July 23, 2002 regarding an ACC Administrative Law Judge's
recommendation on Track A issues.
Report dated August 13, 2002 filing certifications of the Company's
principal executive officer and principal financial officer.
Report dated August 27, 2002 regarding the ACC's decision on Track A
issues.
Report dated September 10, 2002 regarding the ACC's Track A Order and APS'
filing of the Financing Application.
Report dated September 30, 2002 regarding exhibits comprised of financial
information and earnings variance explanations.
Report dated October 17, 2002 regarding the Company's earnings outlook and
a slide presentation for use at an analyst conference.
61
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: November 14, 2002 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Financial Officer
and Officer Duly Authorized
to sign this Report)
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
CERTIFICATIONS
I, William J. Post, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Pinnacle West Capital
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the period presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
62
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002.
William J. Post
----------------------------------------
William J. Post
Title: Chairman of the Board and Chief
Executive Officer
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
CERTIFICATIONS
I, Michael V. Palmeri, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Pinnacle West Capital
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the period presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
63
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002.
Michael V. Palmeri
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Michael V. Palmeri
Title: Vice President, Finance
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