e10vq
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2006
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
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Exact Name of Each Registrant as specified in |
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Commission |
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its charter; State of Incorporation; Address; |
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IRS Employer |
File Number |
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and Telephone Number |
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Identification No. |
1-8962
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PINNACLE WEST CAPITAL CORPORATION
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(602) 250-1000
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86-0512431 |
1-4473
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ARIZONA PUBLIC SERVICE COMPANY
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(602) 250-1000
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86-0011170 |
Indicate by check mark whether each 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.
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PINNACLE WEST CAPITAL CORPORATION
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Yes þ
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No o |
ARIZONA PUBLIC SERVICE COMPANY
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Yes o
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No þ |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act.
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PINNACLE WEST CAPITAL CORPORATION
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Large accelerated filer þ Accelerated filer o Non-accelerated filer o |
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ARIZONA PUBLIC SERVICE COMPANY
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Large accelerated filer o Accelerated filer o Non-accelerated filer þ |
Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act
Rule 12b-2).
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PINNACLE WEST CAPITAL CORPORATION
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Yes o
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No þ |
ARIZONA PUBLIC SERVICE COMPANY
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Yes o
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No þ |
Indicate the number of shares outstanding of each of the issuers classes of common stock as
of the latest practicable date.
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PINNACLE WEST CAPITAL CORPORATION
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Number of shares of common stock, no
par value, outstanding as of May 3,
2006: 99,197,295 |
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ARIZONA PUBLIC SERVICE COMPANY
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Number of shares of common stock, $2.50
par value, outstanding as of May 3,
2006: 71,264,947 |
Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a)
and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed
under that General Instruction.
This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona
Public Service Company. Each registrant is filing on its own behalf all of the information
contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries.
Except as stated in the preceding sentence, neither registrant is filing any information that does
not relate to such registrant, and therefore makes no representation as to any such information.
GLOSSARY
ACC Arizona Corporation Commission
ADEQ Arizona Department of Environmental Quality
ALJ Administrative Law Judge
APB Accounting Principles Board
APS Arizona Public Service Company, a subsidiary of the Company
APS Energy Services APS Energy Services Company, Inc., a subsidiary of the Company
Clean Air Act Clean Air Act, as amended
Company Pinnacle West Capital Corporation
Credit Agreement Pinnacle Wests $300 million Amended and Restated Credit Agreement, dated as of
December 9, 2005
DOE United States Department of Energy
EITF FASBs Emerging Issues Task Force
El Dorado El Dorado Investment Company, a subsidiary of the Company
EPA United States Environmental Protection Agency
ERMC Energy Risk Management Committee
FASB Financial Accounting Standards Board
FERC United States Federal Energy Regulatory Commission
GAAP accounting principles generally accepted in the United States of America
IRS United States Internal Revenue Service
kWh kilowatt-hour
Moodys Moodys Investors Service
MWh megawatt-hours, one million watts per hour
Native Load retail and wholesale sales supplied under traditional cost-based rate regulation
NPC Nevada Power Company
NRC United States Nuclear Regulatory Commission
OCI other comprehensive income
Off-System Sales sales of electricity from generation owned by the Company that is over and above
the amount required to serve APS retail customers and traditional wholesale contracts
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
PRP potentially responsible party
PSA power supply adjustor
2
PWEC Dedicated Assets the following power plants, each of which was transferred by Pinnacle West
Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit
3
Retail Fuel and Power Costs fuel and purchased power costs eligible to be deferred under the PSA
Salt River Project Salt River Project Agricultural Improvement and Power District
SEC United States Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
Silverhawk Silverhawk Power Station, a 570-megawatt, natural gas-fueled, combined-cycle electric
generating facility located 20 miles north of Las Vegas, Nevada
Standard & Poors Standard & Poors Corporation
SunCor SunCor Development Company, a subsidiary of the Company
Sundance Plant 450-megawatt generating facility located approximately 55 miles southeast of
Phoenix, Arizona
Superfund Comprehensive Environmental Response, Compensation and Liability Act
Trading energy-related activities entered into with the objective of generating profits on
changes in market prices
2005 Form 10-K Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December
31, 2005
VIE variable interest entity
3
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)
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Three Months Ended |
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March 31, |
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2006 |
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2005 |
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OPERATING REVENUES |
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Regulated electricity segment |
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$ |
466,126 |
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$ |
416,030 |
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Marketing and trading segment |
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85,002 |
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89,257 |
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Real estate segment |
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107,854 |
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69,936 |
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Other revenues |
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11,224 |
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10,135 |
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Total |
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670,206 |
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585,358 |
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OPERATING EXPENSES |
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Regulated electricity segment fuel and purchased power |
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157,395 |
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78,423 |
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Marketing and trading segment fuel and purchased power |
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|
74,175 |
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70,809 |
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Operations and maintenance |
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178,427 |
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155,084 |
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Real estate segment operations |
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71,330 |
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55,334 |
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Depreciation and amortization |
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87,621 |
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90,944 |
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Taxes other than income taxes |
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35,573 |
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34,565 |
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Other expenses |
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8,522 |
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8,374 |
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Total |
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613,043 |
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493,533 |
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OPERATING INCOME |
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57,163 |
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91,825 |
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OTHER |
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Allowance for equity funds used during construction |
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3,801 |
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2,603 |
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Other income (Note 14) |
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5,467 |
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1,726 |
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Other expense (Note 14) |
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(4,541 |
) |
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(5,309 |
) |
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Total |
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4,727 |
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(980 |
) |
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INTEREST EXPENSE |
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Interest charges |
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47,526 |
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45,965 |
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Capitalized interest |
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(4,024 |
) |
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(3,289 |
) |
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Total |
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43,502 |
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42,676 |
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INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES |
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18,388 |
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48,169 |
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INCOME TAXES |
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6,793 |
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18,570 |
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INCOME FROM CONTINUING OPERATIONS |
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11,595 |
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29,599 |
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INCOME (LOSS) FROM DISCONTINUED OPERATIONS |
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Net of income tax expense (benefit) of $557 and $(3,320) (Note 17) |
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860 |
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(5,151 |
) |
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NET INCOME |
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$ |
12,455 |
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$ |
24,448 |
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WEIGHTED-AVERAGE COMMON SHARES
OUTSTANDING BASIC |
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99,115 |
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91,962 |
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WEIGHTED-AVERAGE COMMON SHARES
OUTSTANDING DILUTED |
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99,449 |
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92,045 |
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EARNINGS PER WEIGHTED AVERAGE
COMMON SHARE OUTSTANDING |
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Income from continuing operations basic |
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$ |
0.12 |
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$ |
0.32 |
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Net income basic |
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0.13 |
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0.27 |
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Income from continuing operations diluted |
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0.12 |
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0.32 |
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Net income diluted |
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0.13 |
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0.27 |
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DIVIDENDS DECLARED PER SHARE |
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$ |
1.00 |
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$ |
0.95 |
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See Notes to Pinnacle Wests Condensed Consolidated Financial Statements.
4
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
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March 31, |
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December 31, |
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2006 |
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2005 |
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ASSETS |
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CURRENT ASSETS |
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Cash and cash equivalents |
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$ |
314,855 |
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$ |
154,003 |
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Customer and other receivables |
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|
379,730 |
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502,681 |
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Allowance for doubtful accounts |
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(4,596 |
) |
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|
(4,979 |
) |
Materials and supplies (at average cost) |
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|
112,350 |
|
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|
109,736 |
|
Fossil fuel (at average cost) |
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|
22,145 |
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|
23,658 |
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Assets from risk management and trading
activities (Note 10) |
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|
501,871 |
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|
827,779 |
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Assets held for sale (Note 17) |
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202,645 |
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Other current assets |
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83,406 |
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75,869 |
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Total current assets |
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1,409,761 |
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|
1,891,392 |
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INVESTMENTS AND OTHER ASSETS |
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Real estate investments net |
|
|
427,297 |
|
|
|
390,702 |
|
Assets from long-term risk management and
trading activities (Note 10) |
|
|
385,100 |
|
|
|
597,831 |
|
Decommissioning trust accounts |
|
|
305,096 |
|
|
|
293,943 |
|
Other assets |
|
|
119,264 |
|
|
|
111,931 |
|
|
|
|
|
|
|
|
Total investments and other assets |
|
|
1,236,757 |
|
|
|
1,394,407 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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PROPERTY, PLANT AND EQUIPMENT |
|
|
|
|
|
|
|
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Plant in service and held for future use |
|
|
10,838,110 |
|
|
|
10,727,695 |
|
Less accumulated depreciation and amortization |
|
|
3,672,003 |
|
|
|
3,622,884 |
|
|
|
|
|
|
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Total |
|
|
7,166,107 |
|
|
|
7,104,811 |
|
Construction work in progress |
|
|
307,950 |
|
|
|
327,172 |
|
Intangible assets, net of accumulated amortization |
|
|
109,435 |
|
|
|
90,916 |
|
Nuclear fuel, net of accumulated amortization |
|
|
61,806 |
|
|
|
54,184 |
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
|
7,645,298 |
|
|
|
7,577,083 |
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|
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|
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|
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|
|
|
|
|
|
|
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|
DEFERRED DEBITS |
|
|
|
|
|
|
|
|
Deferred fuel and purchased power regulatory asset
(Note 5) |
|
|
169,486 |
|
|
|
172,756 |
|
Other regulatory assets |
|
|
167,155 |
|
|
|
151,123 |
|
Other deferred debits |
|
|
127,671 |
|
|
|
135,884 |
|
|
|
|
|
|
|
|
Total deferred debits |
|
|
464,312 |
|
|
|
459,763 |
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|
|
|
|
|
|
|
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|
|
|
|
|
|
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TOTAL ASSETS |
|
$ |
10,756,128 |
|
|
$ |
11,322,645 |
|
|
|
|
|
|
|
|
See Notes to Pinnacle Wests Condensed Consolidated Financial Statements.
5
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
LIABILITIES AND COMMON STOCK EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
259,149 |
|
|
$ |
377,107 |
|
Accrued taxes |
|
|
326,948 |
|
|
|
289,235 |
|
Accrued interest |
|
|
48,828 |
|
|
|
31,774 |
|
Dividends payable |
|
|
49,588 |
|
|
|
|
|
Short-term borrowings |
|
|
10,603 |
|
|
|
15,673 |
|
Current maturities of long-term debt |
|
|
384,055 |
|
|
|
384,947 |
|
Customer deposits |
|
|
64,242 |
|
|
|
60,509 |
|
Deferred income taxes |
|
|
32,160 |
|
|
|
94,710 |
|
Liabilities from risk management and trading
activities (Note 10) |
|
|
490,460 |
|
|
|
720,693 |
|
Other current liabilities (Note 10) |
|
|
130,888 |
|
|
|
297,425 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
1,796,921 |
|
|
|
2,272,073 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT LESS CURRENT MATURITIES |
|
|
2,782,227 |
|
|
|
2,608,455 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
1,202,226 |
|
|
|
1,225,253 |
|
Regulatory liabilities |
|
|
571,939 |
|
|
|
592,494 |
|
Liability for asset retirements |
|
|
273,238 |
|
|
|
269,011 |
|
Pension liability |
|
|
285,735 |
|
|
|
264,476 |
|
Liabilities from long-term risk management
and trading activities (Note 10) |
|
|
230,629 |
|
|
|
256,413 |
|
Unamortized gain sale of utility plant |
|
|
44,613 |
|
|
|
45,757 |
|
Other |
|
|
357,869 |
|
|
|
363,749 |
|
|
|
|
|
|
|
|
Total deferred credits and other |
|
|
2,966,249 |
|
|
|
3,017,153 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13
and 15) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON STOCK EQUITY |
|
|
|
|
|
|
|
|
Common stock, no par value |
|
|
2,075,157 |
|
|
|
2,067,377 |
|
Treasury stock |
|
|
(895 |
) |
|
|
(1,245 |
) |
|
|
|
|
|
|
|
Total common stock |
|
|
2,074,262 |
|
|
|
2,066,132 |
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss)
(Note 11): |
|
|
|
|
|
|
|
|
Minimum pension liability adjustment |
|
|
(97,277 |
) |
|
|
(97,277 |
) |
Derivative instruments |
|
|
126,775 |
|
|
|
262,397 |
|
|
|
|
|
|
|
|
Total accumulated other comprehensive income |
|
|
29,498 |
|
|
|
165,120 |
|
|
|
|
|
|
|
|
Retained earnings |
|
|
1,106,971 |
|
|
|
1,193,712 |
|
|
|
|
|
|
|
|
Total common stock equity |
|
|
3,210,731 |
|
|
|
3,424,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND COMMON STOCK EQUITY |
|
$ |
10,756,128 |
|
|
$ |
11,322,645 |
|
|
|
|
|
|
|
|
See Notes to Pinnacle Wests Condensed Consolidated Financial Statements.
6
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 (a) |
|
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
Net Income |
|
$ |
12,455 |
|
|
$ |
24,448 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization including nuclear fuel |
|
|
95,072 |
|
|
|
99,556 |
|
Deferred fuel and purchased power |
|
|
(14,538 |
) |
|
|
|
|
Deferred fuel amortization |
|
|
17,808 |
|
|
|
|
|
Allowance for equity funds used during construction |
|
|
(3,801 |
) |
|
|
(2,603 |
) |
Deferred income taxes |
|
|
1,757 |
|
|
|
(4,281 |
) |
Change in mark-to-market valuations |
|
|
9,305 |
|
|
|
(18,557 |
) |
Changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
Customer and other receivables |
|
|
129,940 |
|
|
|
117,132 |
|
Materials, supplies and fossil fuel |
|
|
4,186 |
|
|
|
(9,967 |
) |
Other current assets |
|
|
(7,537 |
) |
|
|
(10,265 |
) |
Accounts payable |
|
|
(124,577 |
) |
|
|
(179,467 |
) |
Accrued taxes |
|
|
37,713 |
|
|
|
31,768 |
|
Other current liabilities |
|
|
24,940 |
|
|
|
22,113 |
|
Proceeds from the sale of real estate assets |
|
|
7,884 |
|
|
|
19,427 |
|
Real estate investments |
|
|
(28,670 |
) |
|
|
(13,797 |
) |
Change in risk management and trading assets |
|
|
67,984 |
|
|
|
(1,198 |
) |
Change in risk management and trading liabilities |
|
|
(66,096 |
) |
|
|
37,707 |
|
Collateral |
|
|
(170,690 |
) |
|
|
32,946 |
|
Change in other long-term assets |
|
|
(2,247 |
) |
|
|
(1,676 |
) |
Change in other long-term liabilities |
|
|
12,169 |
|
|
|
19,064 |
|
|
|
|
|
|
|
|
Net cash flow provided by operating activities |
|
|
3,057 |
|
|
|
162,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(167,367 |
) |
|
|
(121,120 |
) |
Proceeds from the sale of Silverhawk |
|
|
207,620 |
|
|
|
|
|
Capitalized interest |
|
|
(4,024 |
) |
|
|
(3,289 |
) |
Purchases of investment securities |
|
|
(269,526 |
) |
|
|
(343,525 |
) |
Proceeds from sale of investment securities |
|
|
269,526 |
|
|
|
424,700 |
|
Proceeds from nuclear decommissioning trust sales |
|
|
33,743 |
|
|
|
39,777 |
|
Investment in nuclear decommissioning trust |
|
|
(38,929 |
) |
|
|
(42,638 |
) |
Proceeds from real estate investments |
|
|
2,138 |
|
|
|
1,869 |
|
Other |
|
|
(1,484 |
) |
|
|
8,999 |
|
|
|
|
|
|
|
|
Net cash flow provided by (used for) investing activities |
|
|
31,697 |
|
|
|
(35,227 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
Issuance of long-term debt |
|
|
206,848 |
|
|
|
163,999 |
|
Short-term borrowings and payments net |
|
|
(70 |
) |
|
|
(7,778 |
) |
Dividends paid on common stock |
|
|
(49,608 |
) |
|
|
(43,666 |
) |
Repayment of long-term debt |
|
|
(39,587 |
) |
|
|
(264,805 |
) |
Common stock equity issuance |
|
|
5,065 |
|
|
|
12,649 |
|
Other |
|
|
3,450 |
|
|
|
21,228 |
|
|
|
|
|
|
|
|
Net cash flow provided by (used for) financing activities |
|
|
126,098 |
|
|
|
(118,373 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE IN CASH AND CASH EQUIVALENTS |
|
|
160,852 |
|
|
|
8,750 |
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD |
|
|
154,003 |
|
|
|
163,366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
|
$ |
314,855 |
|
|
$ |
172,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information
|
|
|
|
|
|
|
|
|
Cash paid during the period for: |
|
|
|
|
|
|
|
|
Income taxes paid, net of refunds |
|
$ |
(40 |
) |
|
$ |
15,230 |
|
Interest paid, net of amounts capitalized |
|
$ |
25,526 |
|
|
$ |
33,891 |
|
See Notes to Pinnacle Wests Condensed Consolidated Financial Statements.
|
|
|
(a) |
|
See Note 1 for information regarding revisions of prior year amounts. |
7
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Consolidation and Nature of Operations
The unaudited condensed consolidated financial statements include the accounts of Pinnacle
West and our wholly-owned subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and
El Dorado. All significant intercompany accounts and transactions between the consolidated
companies have been eliminated. Our accounting records are maintained in accordance with GAAP.
The preparation of financial statements in accordance with GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of
contingent assets and liabilities at the date of the financial statements and reported amounts of
revenues and expenses during the reporting period. Actual results could differ from those
estimates. We have reclassified certain prior year amounts to conform to the current year
presentation.
In the second quarter of 2005, Pinnacle West revised the presentation of its statements of
cash flows to include the cash flows from discontinued operations within the categories of
operating, investing, and financing activities. A summary of the effects of the change in
presentation on the Condensed Consolidated Statements of Cash Flows for the three months ended
March 31, 2005 is as follows (dollars in millions):
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2005 |
|
Net cash flows from operating activities as previously reported |
|
$ |
196 |
|
Change in net cash flows from discontinued operations |
|
|
(34 |
) |
|
|
|
|
Net cash flows from operating activities as currently reported |
|
$ |
162 |
|
|
|
|
|
Net cash flows used for investing activities as previously
reported |
|
$ |
(40 |
) |
Change in net cash flows used for discontinued operations |
|
|
5 |
|
|
|
|
|
Net cash flows used for investing activities as currently
reported |
|
$ |
(35 |
) |
|
|
|
|
Net cash flows used for financing activities as previously
reported |
|
$ |
(147 |
) |
Change in net cash flows used for discontinued operations |
|
|
29 |
|
|
|
|
|
Net cash flows used for financing activities as currently
reported |
|
$ |
(118 |
) |
|
|
|
|
2. Condensed Consolidated Financial Statements
Our unaudited condensed consolidated financial statements reflect all adjustments which we
believe are necessary for the fair presentation of our financial position, results of operations
and cash flows for the periods presented. 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
2005 Form 10-K.
3. Quarterly Fluctuations
Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real
estate and trading and wholesale marketing activities can have significant impacts on our results
for
8
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
interim periods. For these reasons, results for interim periods do not necessarily represent
results to be expected for the year.
4. Changes in Liquidity
In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the
sale of Silverhawk. See Equity Infusions in Note 5 for more information.
On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with
Prudential Investment Management, Inc. (Prudential) and certain of its affiliates. The agreement
provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for
purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes
issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28,
2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal
amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the Series A Notes).
On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006.
Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds
to repay these notes.
The following table shows principal payments due on Pinnacle Wests and APS total long-term
debt and capitalized lease requirements (dollars in millions) as of March 31, 2006:
|
|
|
|
|
|
|
|
|
Year |
|
Pinnacle West |
|
APS |
2006
|
|
$ |
386 |
|
|
$ |
85 |
|
2007
|
|
|
2 |
|
|
|
1 |
|
2008
|
|
|
112 |
|
|
|
1 |
|
2009
|
|
|
10 |
|
|
|
1 |
|
2010
|
|
|
228 |
|
|
|
224 |
|
Thereafter
|
|
|
2,439 |
|
|
|
2,262 |
|
5. Regulatory Matters
APS General Rate Case
On January 31, 2006, APS filed with the ACC updated financial schedules, testimony and other
data in the general rate case that APS originally filed on November 4, 2005. As requested by the
ACC staff, the updated information uses the twelve months ended September 30, 2005 as the test
period instead of the test year ended December 31, 2004 used in APS original filing. As a result
of the updated filing, APS is requesting a 21.3%, or $453.9 million, increase in its annual retail
electricity revenues effective no later than December 31, 2006. The original filing requested a
19.9%, or $409.1 million, retail rate increase.
9
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The updated requested rate increase is designed to recover the following (dollars in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Updated Filing |
|
|
Original Filing |
|
|
|
(January 31, 2006) |
|
|
(November 4, 2005) |
|
|
|
Annual |
|
|
|
|
|
|
Annual |
|
|
|
|
|
|
Revenue |
|
|
Percentage |
|
|
Revenue |
|
|
Percentage |
|
|
|
Increase |
|
|
Increase |
|
|
Increase |
|
|
Increase |
|
Increased fuel and purchased power |
|
$ |
299.0 |
|
|
|
14.0 |
% |
|
$ |
246.8 |
|
|
|
12.0 |
% |
Capital structure update |
|
|
98.3 |
|
|
|
4.6 |
% |
|
|
96.8 |
|
|
|
4.7 |
% |
Rate base update, including acquisition of
Sundance Plant |
|
|
46.2 |
|
|
|
2.2 |
% |
|
|
42.5 |
|
|
|
2.1 |
% |
Pension funding |
|
|
41.3 |
|
|
|
1.9 |
% |
|
|
41.2 |
|
|
|
2.0 |
% |
Other items |
|
|
(30.9 |
) |
|
|
(1.4 |
)% |
|
|
(18.2 |
) |
|
|
(0.9 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total increase |
|
$ |
453.9 |
|
|
|
21.3 |
% |
|
$ |
409.1 |
|
|
|
19.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
The request is based on (a) a rate base of $4.4 billion as of September 30, 2005; (b) a base
rate for fuel and purchased power costs of $0.031904 per kilowatt-hour based on estimated 2006
prices; and (c) a proposed capital structure of 45% long-term debt and 55% common stock equity,
with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common
stock equity). The requested increase in annual retail electricity revenues from the original
filing is based solely on increased fuel and purchased power costs, slightly offset by other items
(see the above chart). If the ACC approves the requested base rate increase for fuel and purchased
power costs (see clause (b) of this paragraph), subsequent PSA rate adjustments and/or PSA
surcharges would be reduced because more of such costs would be
recovered in base rates.
The updated request does not include the PSA annual adjustor rate increase of approximately 5%
that took effect February 1, 2006 or the pending application for a PSA surcharge that APS filed on
February 2, 2006. See Power Supply Adjustor below.
Interim Rate Increase
On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate
increase of $299 million, or approximately 14%, to be effective April 1, 2006. APS later reduced
this request to $232 million, or approximately 11%, due to a
decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase is solely to address APS under-collection of
higher annual fuel and purchased power costs. On May 2, 2006,
the ACC approved an order in this
matter that, among other things:
|
|
|
authorizes an interim PSA adjustor, effective May 1, 2006, that will result in an
interim retail rate increase of approximately 8.3% designed to recover approximately
$138 million of fuel and purchased power costs during 2006 (this interim adjustor,
combined with the $15 million PSA surcharge approved by the ACC (see Application for
PSA Surcharges below), will result in a rate increase of |
10
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
approximately 9.0% designed to recover approximately $149 million of fuel and
purchased power costs during 2006); |
|
|
|
|
provides that amounts collected through the interim PSA
adjustor remain subject to
a prudency review at the appropriate time and that all unplanned Palo Verde outage
costs for 2006 should undergo a prudence audit by [the ACC]
Staff (PSA deferrals related to these outages are estimated to be about $32 million
during the quarter ended March 31, 2006); |
|
|
|
|
encourages parties to APS general rate case to propose modifications to the PSA
that will address on a permanent basis, the issues with timing of recovery when
deferrals are large and growing; |
|
|
|
|
affirms APS ability to defer fuel and purchased power costs above the prior annual
cap of $776.2 million until the ACC decides the general rate case; and |
|
|
|
|
encourages APS to diversify its resources through large scale, sustained energy
efficiency programs, [using] low cost renewable energy resources as a hedge against
high fossil fuel costs. |
The
interim PSA adjustor accelerates recovery of the fuel and
purchased power component of APS general rate case and is not an additional increase.
Power Supply Adjustor
PSA Provisions
The PSA approved by the ACC in April 2005 as part of APS 2003 rate case provides for
adjustment of retail rates to reflect variations in retail fuel and purchased power costs. On
January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject
to specified parameters and procedures, including the following:
|
|
|
APS will record deferrals for recovery or refund to the extent actual retail fuel
and purchased power costs vary from the base fuel amount (currently $0.020743 per kWh); |
|
|
|
|
the deferrals are subject to a 90/10 sharing arrangement in which APS must absorb
10% of the retail fuel and purchased power costs above the base fuel amount and may
retain 10% of the benefit from the retail fuel and purchased power costs that are below
the base fuel amount; |
|
|
|
|
amounts to be recovered or refunded through the PSA adjustor
are limited to a) a cumulative plus or minus $0.004 per kWh from
the base fuel amount over the life of the PSA and b) a maximum
plus or minus $0.004 change in the adjustor rate in any one year; |
11
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
the recoverable amount of annual retail fuel and purchased power costs through
current base rates and the PSA was originally capped at $776.2 million; however, the
ACC has removed the cap pending the ACCs final ruling on
APS pending request in the general rate case to have
the cap eliminated or substantially raised; |
|
|
|
|
the PSA will remain in effect for a minimum five-year period, but the ACC may
eliminate the PSA at any time, if appropriate, in the event APS files a rate case
before the expiration of the five-year period (which APS did by filing the general rate
case noted above) or if APS does not comply with the terms of the PSA; and |
|
|
|
|
APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor
rate has been set each year. The amount available for potential PSA surcharges will be
limited to the amount of accumulated deferrals through the prior year-end, which are
not expected to be recovered through the annual adjustor or any PSA surcharges
previously approved by the ACC. |
2006 PSA Annual Adjustor The effective date of the PSAs annual adjustor is
February 1, and the adjustor rate was set at the maximum $0.004 per kilowatt-hour effective
February 1, 2006. The change in the adjustor rate represents a retail rate increase of
approximately 5% designed to recover $110 million of deferred fuel and purchased power costs over
the twelve-month period beginning February 1, 2006, of which
$18 million was recorded as revenue and fuel and purchased power
costs during the quarter ended March 31, 2006.
Application for PSA Surcharges On February 2, 2006, APS filed with the ACC an application for
two separate surcharges under the PSA. The surcharges would recover approximately $60 million in
retail fuel and purchased power costs deferred by APS in 2005 under the PSA. The combined
surcharges would represent a temporary rate increase of approximately 2.6% during the overlapping
portion of the twelve-month recovery periods for the two surcharges. The other component of the
2005 PSA deferrals is being recovered under the 2006 PSA annual adjustor discussed in the preceding
paragraph. The first surcharge would recover approximately $15 million over a twelve-month period,
representing a temporary rate increase of approximately 0.7%, proposed to begin with the date of
the ACCs decision in APS emergency interim rate case. The second requested surcharge
would recover approximately $45 million over a twelve-month period, representing a temporary rate
increase of approximately 1.9%, proposed to begin no later than the ACCs completion of its inquiry
regarding the unplanned 2005 Palo Verde outages. The $45 million of PSA deferrals represents
replacement power costs associated with these outages. On April 12, 2006, the ACC issued an order
approving the $15 million surcharge request. As a result of the ACCs decision described under
Interim Rate Increase above, this temporary rate increase
became effective May 1, 2006. The second surcharge request is
still pending.
Proposed Modifications to PSA (Requested In General Rate Case)
In its pending general rate case, APS has requested the following modifications to the PSA:
|
|
|
The cumulative plus or minus $0.004 per kWh limit from the
base fuel amount over the life of the PSA would be eliminated, while
the maximum plus or minus $0.004 limit to changes in the adjustor
rate in any one year would remain in effect; |
12
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
The $776.2 million annual limit on the retail fuel and purchased power costs under
APS current base rates and the PSA would be removed or increased (although APS may
defer fuel and purchased power costs above $776.2 million per year pending the ACCs
final ruling on APS pending request to have the cap eliminated or substantially
raised); |
|
|
|
|
The current provision that APS is required to file a surcharge application with the
ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100
million would be eliminated, thereby giving APS flexibility in determining when a
surcharge filing should be made; |
|
|
|
|
The costs of renewable energy and capacity costs attributable to purchased power
obtained through competitive procurement would be excluded from the existing 90/10
sharing arrangement under which APS absorbs 10% of the retail fuel and purchased power
costs above the base fuel amount and retains 10% of the benefit from retail fuel and
purchased power costs that are below the base fuel amount; and |
|
|
|
|
10% of any realized gains or losses resulting from APS hedges of Retail Fuel and
Power Costs would be retained or absorbed by APS before being subject to the 90/10
sharing provision under the PSA. |
APS 2003 Rate Case
On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003.
In addition to the ACCs approval of the PSA discussed under Power Supply Adjustor above, certain
key financial components of the order include:
|
|
|
APS received an annual retail rate increase of approximately 4.2%, which was
effective as of April 1, 2005. This increase does not include the impact of the PSA. |
|
|
|
|
APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy,
with a net carrying value of approximately $850 million, and to rate base the PWEC
Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory
rate base disallowance of approximately $150 million. Due to depreciation and other
miscellaneous factors, the actual disallowance was $139 million at December 31, 2005.
This transfer was completed on July 29, 2005. As a result, for financial reporting
purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of
approximately $84 million in the third quarter of 2005. |
|
|
|
|
Effective April 1, 2005, APS adopted longer service lives for certain depreciable
assets. This change reduced annual depreciation expense for financial reporting
purposes by approximately $30 million. APS also adopted longer service lives for the
PWEC Dedicated Assets, which reduced annual depreciation expense for financial
reporting purposes by approximately $10 million. |
13
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Equity Infusions
On November 8, 2005, the ACC approved Pinnacle Wests request to infuse more than $450 million
of equity into APS during 2005 or 2006. These infusions consist of about $250 million of the
proceeds of Pinnacle Wests common equity issuance on
May 2, 2005 and about $210 million of the
proceeds from the sale of Silverhawk in January 2006 (see Note 17). Pinnacle West has made these
equity infusions into APS.
Federal
Price Mitigation Plan
In July 2002, the FERC adopted a price mitigation plan that constrains the price of
electricity in the wholesale spot electricity market in the western United States. The FERC
adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices
above the cap must be justified and are subject to potential refund.
FERC Order
On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services
(collectively, the Pinnacle West Companies) submitted to the FERC an update to its three-year
market-based rate review pursuant to the FERCs order implementing a new generation market power
analysis. On December 20, 2004, the FERC issued an order
approving the Pinnacle West Companies market-based rates for control
areas other than those of APS, Public Service Company of New Mexico (PNM) and Tucson Electric
Power Company (TEP). The FERC staff required the Pinnacle West Companies to submit additional
data with respect to these control areas, and the Pinnacle West Companies did so.
On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies market-based
rate authority in the APS control area (the FERC Order). The FERC found that the Pinnacle West
Companies failed to provide the necessary information about the APS control area to allow the FERC
to make a determination about the FERCs generation market power screens in the APS control area.
The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP
control areas.
As a result of the FERC Order, the Pinnacle West Companies must charge cost-based rates,
rather than market-based rates, in the APS control area, with an effective date of February 27,
2005. The Pinnacle West Companies will be required to refund any over-collection of rates from
February 27, 2005.
The Pinnacle West Companies will seek rehearing of the FERC Order on or before May 17, 2006.
Based upon an analysis of the FERC Order and preliminary calculations
of the refund obligations, at this time, neither Pinnacle West nor APS believes that the FERC Order has a
material adverse effect on its financial position, results of operations or cash flows.
In addition, the FERC Order revoked a previously-granted FERC order allowing Pinnacle West to
issue securities or incur long-term debt without FERC approval. On
May 3, 2006, the FERC issued an
order approving Pinnacle Wests April 20, 2006 application to borrow funds under the Credit
Agreement and to issue a broad range of other debt and equity securities.
14
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
6. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a
nonqualified supplemental excess benefit retirement plan, and other postretirement benefit plans
for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31
measurement date for its pension and other postretirement benefit plans. The market-related value
of our plan assets is their fair value at the measurement date.
The following table provides details of the plans benefit costs for the three months ended
March 31, 2006 and 2005. Also included is the portion of these costs charged to expense, including
administrative costs and excluding amounts billed to electric plant participants or capitalized as
overhead construction (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Benefits |
|
|
|
Three Months |
|
|
Three Months |
|
|
|
Ended |
|
|
Ended |
|
|
|
March 31, |
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Service cost-benefits earned
during the period |
|
$ |
15 |
|
|
$ |
12 |
|
|
$ |
7 |
|
|
$ |
6 |
|
Interest cost on benefit
obligation |
|
|
29 |
|
|
|
23 |
|
|
|
13 |
|
|
|
9 |
|
Expected return on plan assets |
|
|
(30 |
) |
|
|
(24 |
) |
|
|
(13 |
) |
|
|
(8 |
) |
Amortization of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transition (asset)
obligation |
|
|
|
|
|
|
(1 |
) |
|
|
1 |
|
|
|
1 |
|
Prior service cost |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
Net actuarial loss |
|
|
7 |
|
|
|
5 |
|
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
22 |
|
|
$ |
16 |
|
|
$ |
11 |
|
|
$ |
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of cost charged to
expense |
|
$ |
9 |
|
|
$ |
7 |
|
|
$ |
5 |
|
|
$ |
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
APS share of costs charged
to expense |
|
$ |
8 |
|
|
$ |
6 |
|
|
$ |
4 |
|
|
$ |
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions
The contribution to our pension plan in 2006 is estimated to be approximately $50 million, $14
million of which was contributed on April 14, 2006. The contribution to our other postretirement
benefit plans in 2006 is estimated to be approximately $29 million. APS share is approximately
97% of both plans.
15
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
7. Business Segments
We have three principal business segments (determined by products, services and the regulatory
environment):
|
|
|
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electricity service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution; |
|
|
|
|
our real estate segment, which consists of SunCors real estate development and
investment activities; and |
|
|
|
|
our marketing and trading segment, which consists of our competitive energy business
activities, including wholesale marketing and trading and APS Energy Services
commodity-related energy services. |
Financial data for the three months ended March 31, 2006 and 2005 and at March 31, 2006 and
December 31, 2005 by business segment is provided as follows (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Operating Revenues: |
|
|
|
|
|
|
|
|
Regulated electricity |
|
$ |
466 |
|
|
$ |
416 |
|
Real estate |
|
|
108 |
|
|
|
70 |
|
Marketing and trading |
|
|
85 |
|
|
|
89 |
|
Other |
|
|
11 |
|
|
|
10 |
|
|
|
|
|
|
|
|
Total |
|
$ |
670 |
|
|
$ |
585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss): |
|
|
|
|
|
|
|
|
Regulated electricity |
|
$ |
(12 |
) |
|
$ |
14 |
|
Real estate |
|
|
21 |
|
|
|
9 |
|
Marketing and trading |
|
|
2 |
|
|
|
|
|
Other |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
Total |
|
$ |
12 |
|
|
$ |
24 |
|
|
|
|
|
|
|
|
16
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
As of |
|
|
As of |
|
|
|
March 31, 2006 |
|
|
December 31, 2005 |
|
Assets: |
|
|
| |
|
|
|
|
|
Regulated electricity |
|
$ |
9,756 |
|
|
|
$ |
9,732 |
|
Real estate |
|
|
517 |
|
|
|
|
483 |
|
Marketing and trading |
|
|
452 |
|
|
|
|
1,070 |
|
Other |
|
|
31 |
|
|
|
|
38 |
|
|
|
|
| |
|
Total |
|
$ |
10,756 |
|
|
|
$ |
11,323 |
|
|
|
|
|
|
|
8. Stock-Based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle
West and our subsidiaries.
The 2002 Long-Term Incentive Plan (2002 Plan) allows Pinnacle West to grant performance
shares, stock ownership incentive awards and non-qualified and performance-accelerated stock
options to key employees. We have reserved 6 million shares of common stock for issuance under the
2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards
and stock ownership incentive awards. The plan also provides for the granting of new non-qualified
stock options at a price per share not less than the fair market value of the common stock at the
time of grant. The stock options vest over three years, unless certain performance criteria are
met, which can accelerate the vesting period. The term of the option cannot be longer than 10
years and the option cannot be repriced during its term.
Generally, each recipient of performance shares is entitled to receive shares of common stock
at the end of a three-year period based upon PinnacleWests earnings per share growth rate during
that three-year period compared to the earnings per share growth rate of all relevant companies in
a specified utilities index. The number of shares of common stock a recipient is entitled to
receive is determined by Pinnacle Wests relative percentile ranking during the three-year period.
The 1994 Long-Term Incentive Plan (1994 Plan) includes outstanding options but no new
options may be granted under the plan. Options vest one-third of the grant per year beginning one
year after the date the option is granted and expire ten years from the date of the grant. The
1994 Plan also provided for the granting of any combination of shares of restricted stock, stock
appreciation rights or dividend equivalents.
In the third quarter of 2002, we began applying the fair value method of accounting for
stock-based compensation, as provided for in SFAS No. 123, Accounting for Stock-Based
Compensation. In accordance with the transition requirements of SFAS No. 123, we applied the fair
value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock
compensation expense based on the intrinsic value method allowed in APB No. 25, Accounting for
Stock Issued to Employees.
Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, using the
modified prospective application transition method. Because the fair value recognition provisions
of both SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based
17
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our
financial statements.
The compensation cost that has been charged against income for share-based compensation plans
was $2.9 million and $0.6 million for the quarters ended March 31, 2006 and 2005, respectively.
The total income tax benefit recognized in the condensed consolidated income statement for
share-based compensation arrangements was $1.1 million and $0.2 million for the quarters ended
March 31, 2006 and 2005, respectively.
The following table is a summary of option activity under our equity incentive plans as of
March 31, 2006 and changes during the quarter ending on that date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Aggregate |
|
|
|
|
|
|
|
Weighted- |
|
|
Remaining |
|
|
Intrinsic Value |
|
|
|
|
Shares |
|
|
Average Exercise |
|
|
Contractual Term |
|
|
(dollars in |
|
Options |
|
(in
thousands) |
|
|
Price |
|
|
(Years) |
|
|
thousands) |
|
Outstanding at
January 1, 2006 |
|
|
1,696 |
|
|
$ |
39.65 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(2 |
) |
|
|
32.29 |
|
|
|
|
|
|
|
|
|
Forfeited or expired |
|
|
(6 |
) |
|
|
43.29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
March 31, 2006 |
|
|
1,688 |
|
|
|
39.64 |
|
|
|
4.9 |
|
|
$ |
2,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at
March 31, 2006 |
|
|
1,682 |
|
|
|
39.65 |
|
|
|
4.9 |
|
|
|
2,923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were no options granted during the quarters ended March 31, 2006 and 2005. The
intrinsic value of options exercised during the quarters ended March 31, 2006 and 2005 was not
material.
The following table is a summary of the status of stock compensation awards, other than
options, as of March 31, 2006 and changes during the quarter ending on that date:
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
Weighted-Average Grant-Date |
Nonvested shares |
|
(in thousands) |
|
Fair Value |
Nonvested at January 1, 2006 |
|
|
528 |
|
|
$ |
38.23 |
|
Granted |
|
|
274 |
|
|
|
41.50 |
|
Vested |
|
|
(13 |
) |
|
|
44.13 |
|
Forfeited |
|
|
(217 |
) |
|
|
35.96 |
|
|
|
|
|
|
|
|
|
|
Nonvested at March 31, 2006 |
|
|
572 |
|
|
|
40.52 |
|
|
|
|
|
|
|
|
|
|
As of March 31, 2006, there was $10.4 million of total unrecognized compensation cost related
to nonvested share-based compensation arrangements granted under the plan. That cost is expected
to be recognized over a weighted-average period of 2 years. The total fair value of shares vested
during the quarters ended March 31, 2006 and 2005 was $0.5 million and $2.9 million, respectively.
18
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Cash received from options exercised under our share-based payment arrangements for the
quarter ended March 31, 2006 was $0.1 million and for the quarter ended March 31,
2005 was $4.0 million. The actual tax benefit realized for the tax deductions from option exercises of the
share-based payment arrangements was immaterial for the three months ended March 31, 2006 or 2005.
Pinnacle West has a current policy of issuing new shares to satisfy share requirements for
stock compensation plans and does not expect to repurchase any shares during 2006.
9. Variable-Interest Entities
In 1986, APS entered into agreements with three separate VIE 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. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly,
do not consolidate them.
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of
certain events that APS does not consider to be reasonably likely to occur. Under certain
circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde
or the occurrence of specified nuclear events), APS would be required to assume the debt associated
with the transactions, make specified payments to the equity participants, and take title to the
leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If
such an event had occurred as of March 31, 2006, APS would have been required to assume
approximately $234 million of debt and pay the equity participants approximately $185 million.
10. Derivative and Energy Trading Accounting
We use derivative instruments (primarily forward purchases and sales, swaps, options and
futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of
fuel, electricity and emission allowances and credits, as well as interest rate risk associated
with long-term debt. As of March 31, 2006, we hedged exposures to the price variability of the
power and gas commodities for a maximum of 3.25 years. The changes in market value of such
contracts have a high correlation to price changes in the hedged transactions. In addition,
subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading
activities intended to profit from market price movements.
Cash Flow Hedges
The changes in the fair value of our hedged positions included in the Condensed Consolidated
Statements of Income, after consideration of amounts deferred under the PSA, for the three months
ended March 31, 2006 and 2005 are comprised of the following (dollars in thousands):
19
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2006 |
|
2005 |
Gains (losses) on the ineffective portion of
derivatives qualifying for hedge accounting |
|
$ |
(178 |
) |
|
$ |
7,324 |
|
Gains (losses) from the change in options
time value excluded from measurement of
effectiveness |
|
|
(18 |
) |
|
|
858 |
|
Gains from the discontinuance of cash flow
hedges |
|
|
434 |
|
|
|
385 |
|
During the next twelve months ending March 31, 2007, we estimate that a net gain of $73
million before income taxes will be reclassified from accumulated other comprehensive income as an
offset to the effect of market price changes for the related hedged transactions. To the extent
the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a
regulatory asset or liability and have no effect on earnings (see Note 5).
Our assets and liabilities from risk management and trading activities are presented in two
categories, consistent with our business segments.
The following table summarizes our assets and liabilities from risk management and trading
activities at March 31, 2006 and December 31, 2005 (dollars in thousands):
March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments |
|
|
|
|
|
|
Deferred |
|
|
|
|
|
|
Current |
|
|
and Other |
|
|
Current |
|
|
Credits and |
|
|
Net Asset |
|
|
|
Assets |
|
|
Assets |
|
|
Liabilities |
|
|
Other |
|
|
(Liability) |
|
Regulated electricity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
$ |
381,639 |
|
|
$ |
194,319 |
|
|
$ |
(350,517 |
) |
|
$ |
(121,356 |
) |
|
$ |
104,085 |
|
Margin account and
options |
|
|
45 |
|
|
|
|
|
|
|
(58,224 |
) |
|
|
|
|
|
|
(58,179 |
) |
Marketing
and trading: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
|
118,925 |
|
|
|
178,740 |
|
|
|
(58,668 |
) |
|
|
(108,466 |
) |
|
|
130,531 |
|
Options and
emission
allowances
at cost |
|
|
1,262 |
|
|
|
12,041 |
|
|
|
(23,051 |
) |
|
|
(807 |
) |
|
|
(10,555 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
501,871 |
|
|
$ |
385,100 |
|
|
$ |
(490,460 |
) |
|
$ |
(230,629 |
) |
|
$ |
165,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments |
|
|
|
|
|
|
Deferred |
|
|
|
|
|
|
Current |
|
|
and Other |
|
|
Current |
|
|
Credits and |
|
|
Net Asset |
|
|
|
Assets |
|
|
Assets |
|
|
Liabilities |
|
|
Other |
|
|
(Liability) |
|
Regulated electricity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
$ |
516,399 |
|
|
$ |
228,873 |
|
|
$ |
(335,801 |
) |
|
$ |
(74,787 |
) |
|
$ |
334,684 |
|
Margin account and
options |
|
|
1,814 |
|
|
|
|
|
|
|
(124,165 |
) |
|
|
|
|
|
|
(122,351 |
) |
Marketing
and trading: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
|
307,883 |
|
|
|
291,122 |
|
|
|
(236,922 |
) |
|
|
(181,417 |
) |
|
|
180,666 |
|
Options and
emission
allowances
at cost |
|
|
1,683 |
|
|
|
77,836 |
|
|
|
(23,805 |
) |
|
|
(209 |
) |
|
|
55,505 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
827,779 |
|
|
$ |
597,831 |
|
|
$ |
(720,693 |
) |
|
$ |
(256,413 |
) |
|
$ |
448,504 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was a liability of $57 million at March 31, 2006 and $123 million
at December 31, 2005 and is included in the margin account in the table above. Cash is deposited
with the broker in this account at the time futures or options contracts are initiated. The change
in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin
account balance.
Cash or other assets may be required to serve as collateral against our open positions on
certain energy-related contracts. Collateral provided to counterparties was $10 million at March
31, 2006 and $6 million at December 31, 2005, and is included in other current assets on the
Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $46 million
at March 31, 2006 and $216 million at December 31, 2005, and is included in other current
liabilities on the Condensed Consolidated Balance Sheets.
Fair Value Hedges
On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on
our $300 million 6.4% Senior Notes. The purpose of these hedges
was to protect against significant
fluctuations in the fair value of our debt. These interest rate swaps
were considered to be fully
effective with any resulting gains or losses on the derivative offset by a similar loss or gain
amount on the underlying fair value of our debt. The fair value of the interest rate swaps was a
loss of approximately $1.7 million at March 31, 2006 and is included in other current liabilities
with the corresponding offset in current maturities of long-term debt on the Condensed Consolidated
Balance Sheets. These interest rate swaps were settled in April 2006.
Credit Risk
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We
have risk management and trading contracts with many counterparties, including one counterparty for
which a worst case exposure represents approximately 10% of Pinnacle Wests $887
21
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
million of risk management and trading assets as of March 31, 2006. Our risk management
process assesses and monitors the financial exposure of this and all other counterparties.
Despite the fact that the great majority of trading counterparties securities are rated as
investment grade by the credit rating agencies, including the counterparty discussed 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 financial institutions, 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.
To manage credit risk, we employ collateral requirements, standardized agreements that allow for
the netting of positive and negative exposures associated with a single counterparty and credit
default swaps. Valuation adjustments are established representing our estimated credit losses on
our overall exposure to counterparties.
11. Comprehensive Income (Loss)
Components of comprehensive income (loss) for the three months ended March 31, 2006 and 2005
are as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Net income |
|
$ |
12,455 |
|
|
$ |
24,448 |
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
Net unrealized gains (losses) on derivative
instruments (a) |
|
|
(204,983 |
) |
|
|
159,644 |
|
Net reclassification of realized gains to
income (b) |
|
|
(17,530 |
) |
|
|
(5,919 |
) |
Net income tax benefit (expense) related to
items of other comprehensive income (loss) |
|
|
86,891 |
|
|
|
(60,306 |
) |
|
|
|
|
|
|
|
Total other comprehensive income (loss) |
|
|
(135,622 |
) |
|
|
93,419 |
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(123,167 |
) |
|
$ |
117,867 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
These amounts primarily include unrealized gains and losses on contracts used to
hedge our forecasted electricity and natural gas requirements to serve Native Load.
These changes are primarily due to changes in forward natural gas prices and wholesale
electricity prices. |
|
(b) |
|
These amounts primarily include the reclassification of unrealized gains and
losses to realized for contracted commodities delivered during the period. |
22
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
12. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with
the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other
high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste
Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent
nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and
it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the
United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a
decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin
accepting spent nuclear fuel. Based on this decision and the DOEs delay, a number of utilities,
including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against
the DOE in the Court of Federal Claims.
APS currently estimates it will incur $147 million (in 2005 dollars) over the life of Palo
Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At
March 31, 2006, APS had a regulatory asset of $4 million that represents amounts spent for on-site
interim spent fuel storage net of amounts recovered in rates per the ACC rate order that was
effective April 1, 2005.
California Energy Market Issues and Refunds in the Pacific Northwest
FERC
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. APS was a seller and a purchaser
in the California markets at issue, and to the extent that refunds are ordered, APS should be a
recipient as well as a payor of such amounts. The FERC is still considering the evidence and
refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit
issued a decision, concluding that the FERC may not order refunds from entities that are not within
the FERCs jurisdiction. Because a number of the entities owing refunds under the FERCs
calculations are not within the FERCs jurisdiction, this order may affect the level of recovery of
refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing
sellers in the California markets to demonstrate that its refund methodology results in an overall
revenue shortfall for their transactions in the relevant markets over a specified time frame. More
than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006,
the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these
sellers. Correspondingly, this will reduce the recovery of total refunds in the California
markets. We currently believe the refund claims at FERC will have no material adverse impact on
our financial position, results of operations, cash flow or liquidity.
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 under
23
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
market-based rates. 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 was dismissed by the
FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an
order issued September 9, 2004, the Ninth Circuit upheld the FERCs authority to permit
market-based rates, but rejected the FERCs claim that it was without authority to consider
retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements
of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the
FERC for further proceedings. Several of the intervenors in this appeal filed a petition for
rehearing of this decision on October 25, 2004. The petition for rehearing has not been acted
upon, and the outcome of the further proceedings cannot be predicted at this time.
The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for
the Pacific Northwest. The FERC affirmed the ALJs conclusion that the prices in the Pacific
Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding.
This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC
ruling in the Pacific Northwest matter is being appealed and the FERC has not yet 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 cash flows.
On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western
Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report
stated that a significant number of entities who participated in the California markets during the
2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions
that allegedly violated certain provisions of the Independent System Operator tariff. After
reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the
claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on
January 22, 2004. Certain parties have sought rehearing of this order, and that request is
pending.
FERC Order
See
FERC Order in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.
Natural Gas Supply
Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural
Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium
through December 31, 2005.
On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the
1996 settlement but maintained the cost responsibility provisions agreed to by parties to that
settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERCs authority to alter
the capacity rights of parties to the settlement. With respect to the FERCs authority to maintain
the cost responsibility provisions of the settlement, a party has sought appellate review and is
seeking to reallocate the costs responsibility associated with the changed contractual obligations
in a way that would be less favorable to APS and Pinnacle West Energy than under the FERCs July 9,
2003 order.
24
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Should this party prevail on this point, APS and Pinnacle West Energys annual capacity cost could
be increased by approximately $3 million after income taxes for the period September 2003 through
December 2005. This appeal has been stayed pending further consideration by the FERC.
Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on
June 30, 2005, which proposed new rates and new services to become effective on January 1, 2006.
The FERC allowed the new rates to take effect on January 1, 2006, but made the rates subject to
refund pending the outcome of a hearing. On March 23, 2006, the FERC issued an order approving El
Pasos proposed new services. APS has sought rehearing of this
order. On March 29, 2006, El Paso filed a partial settlement that postpones the implementation and the associated cost impact
of the new services until June 1, 2006. As part of this settlement, El Paso will accept bids for
new services that will be evaluated and awarded on a net present value, first-come, first-serve
basis. APS will be able to evaluate the cost impact of these new services once it has been
notified of the services contracts it has been awarded. APS cannot currently predict the outcome
of this matter; however, APS believes most of these increased costs
would be eligible for recovery under the PSA (see Note 5).
Navajo Nation Litigation
In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United
States District Court for the District of Columbia (the D.C. Lawsuit) naming Salt River Project,
several Peabody Coal Company entities (collectively, Peabody), Southern California Edison Company
and other defendants, and citing various claims in connection with the renegotiations of the coal
royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and
the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt
River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained
a favorable coal royalty rate by improperly influencing the outcome of a federal administrative
process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages,
treble damages, punitive damages of not less than $1 billion, and the ejection of defendants from
all possessory interests and Navajo Tribal lands arising out of the [primary coal lease]. In July
2001, the court dismissed all claims against Salt River Project.
In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of
St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other
things, a declaration that the participants are obligated to reimburse Peabody for any royalty,
tax, or other obligation arising out of the D.C. Lawsuit. Based on APS ownership interest in the
Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the
litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.
Superfund
Superfund establishes liability for the cleanup of hazardous substances found contaminating
the soil, water or air. Those who generated, transported or disposed of hazardous substances at a
contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and
severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers
APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in
Phoenix, Arizona. APS has facilities that are within this superfund site. APS and Pinnacle West
have agreed with the EPA to perform certain investigative activities of the APS facilities within
OU3. Because
25
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
the investigation has not yet been completed and ultimate remediation requirements are not yet
finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be
required.
Litigation
We are party to various other claims, legal actions and complaints arising in the ordinary
course of business, including but not limited to environmental matters related to the Clean Air
Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial position, results of
operations, cash flows or liquidity.
13. Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy
hazards to the full limit of liability under federal law. This potential liability is covered by
primary liability insurance provided by commercial insurance carriers in the amount of $300 million
and the balance by an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, APS could be assessed
retrospective premium adjustments. The maximum assessment per reactor under the program for each
nuclear incident is approximately $101 million, subject to an annual limit of $15 million per
incident, to be periodically adjusted for inflation. Based on APS interest in the three Palo
Verde units, APS maximum potential assessment per incident for all three units is approximately
$88 million, with an annual payment limitation of approximately $13 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 accidental outage of any of
the three units. The property damage, decontamination, and replacement power coverages are
provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments
under all NEIL policies if NEILs losses in any policy year exceed accumulated funds. The maximum
amount of retrospective assessments APS could incur under the current NEIL policies totals $17.8
million. The insurance coverage discussed in this and the previous paragraph is subject to certain
policy conditions and exclusions.
14. Other Income and Other Expense
The following table provides detail of other income and other expense for the three months
ended March 31, 2006 and 2005 (dollars in thousands):
26
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Other income: |
|
|
|
|
|
|
|
|
Interest income |
|
$ |
4,905 |
|
|
$ |
1,320 |
|
Asset sales |
|
|
361 |
|
|
|
241 |
|
SunCor (a) |
|
|
166 |
|
|
|
(28 |
) |
Miscellaneous |
|
|
35 |
|
|
|
193 |
|
|
|
|
|
|
|
|
Total other income |
|
$ |
5,467 |
|
|
$ |
1,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense: |
|
|
|
|
|
|
|
|
Non-operating costs (b) |
|
$ |
(3,719 |
) |
|
$ |
(3,098 |
) |
Asset sales |
|
|
(196 |
) |
|
|
(64 |
) |
Investment losses net |
|
|
(31 |
) |
|
|
(1,249 |
) |
Miscellaneous |
|
|
(595 |
) |
|
|
(898 |
) |
|
|
|
|
|
|
|
Total other expense |
|
$ |
(4,541 |
) |
|
$ |
(5,309 |
) |
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes joint venture and other non-operating income. |
|
(b) |
|
As defined by the FERC, includes below-the-line non-operating utility costs
(primarily community relations and other costs excluded from utility rate recovery). |
15. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf
of one of our unregulated subsidiaries. Our credit support instruments enable APS Energy Services
to offer commodity energy and energy-related products. Non-performance or non-payment under the
original contract by our unregulated subsidiary would require us to perform under the guarantee or
surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets
related to Pinnacle Wests current outstanding guarantees on behalf of its subsidiary. Our
guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the
guarantees. At March 31, 2006, we had a guarantee of $18 million with a term
of one year and a surety bond of $65 million with a term of one
year for APS Energy Services.
At March 31, 2006, Pinnacle West had approximately $4 million of letters of credit related to
workers compensation expiring in 2006. These letters of credit were subsequently extended and
expire in 2007. We intend to provide from either existing or new facilities for the extension,
renewal or substitution of the letters of credit to the extent required.
APS has entered into various agreements that require letters of credit for financial assurance
purposes. At March 31, 2006, approximately $200 million of letters of credit were outstanding to
support existing pollution control bonds of approximately $200 million. The letters of credit are
available to fund the payment of principal and interest of such debt obligations and expire in
2010. APS has also entered into approximately $93 million of letters of credit to support certain
equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the
Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally,
APS has approximately $5 million of letters of credit related to counterparty collateral
requirements expiring
27
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
in 2006. APS intends to provide from either existing or new facilities for the extension,
renewal or substitution of the letters of credit to the extent required.
We enter into agreements that include indemnification provisions relating to liabilities
arising from or related to certain of our agreements. APS has agreed to indemnify the equity
participants and other parties in the Palo Verde sale leaseback transactions with respect to
certain tax matters. Generally, a maximum obligation is not explicitly stated in the
indemnification provisions and, therefore, the overall maximum amount of the obligation under such
indemnification provisions cannot be reasonably estimated. Based on historical experience and
evaluation of the specific indemnities, we do not believe that any material loss related to such
indemnification provisions is likely.
16. Earnings Per Share
The following table presents earnings per weighted average common share outstanding for the
three months ended March 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
0.12 |
|
|
$ |
0.32 |
|
Income (loss) from discontinued operations |
|
|
0.01 |
|
|
|
(0.05 |
) |
|
|
|
|
|
|
|
Earnings per share basic |
|
$ |
0.13 |
|
|
$ |
0.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
0.12 |
|
|
$ |
0.32 |
|
Income (loss) from discontinued operations |
|
|
0.01 |
|
|
|
(0.05 |
) |
|
|
|
|
|
|
|
Earnings per share diluted |
|
$ |
0.13 |
|
|
$ |
0.27 |
|
|
|
|
|
|
|
|
Dilutive stock options and performance shares increased average common shares outstanding by
approximately 334,000 shares and 83,000 shares for the three months ended March 31, 2006 and March
31, 2005, respectively.
Options to purchase 747,874 shares for the three-month period ended March 31, 2006 were
outstanding but were not included in the computation of earnings per share because the options
exercise prices were greater than the average market price of the common shares. Options to
purchase shares of common stock that were not included in the computation of diluted earnings per
share for that same reason were 868,934 shares for the three-month period ended March 31, 2005.
17. Discontinued Operations
Silverhawk (marketing and trading segment) In June 2005, we entered into an agreement to
sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on
28
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
January 10, 2006. The marketing and trading segment discontinued operations amounts in the
chart below are the revenues and expenses related to the operations of Silverhawk.
SunCor (real estate segment) In 2005 and 2006, SunCor sold commercial properties, which are
required to be reported as discontinued operations on Pinnacle Wests Condensed Consolidated
Statements of Income in accordance with SFAS No. 144.
The following table provides revenue and income (loss) before income taxes and after income
taxes classified as discontinued operations on Pinnacle Wests Condensed Consolidated Statements of
Income for the three months ended March 31, 2006 and 2005 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Revenue: |
|
|
|
|
|
|
|
|
Silverhawk |
|
$ |
1 |
|
|
$ |
28 |
|
SunCor commercial operations |
|
|
1 |
|
|
|
4 |
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
2 |
|
|
$ |
32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before taxes: |
|
|
|
|
|
|
|
|
Silverhawk (a) |
|
$ |
|
|
|
$ |
(10 |
) |
SunCor commercial operations |
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Total income (loss) before taxes |
|
$ |
1 |
|
|
$ |
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) after taxes: |
|
|
|
|
|
|
|
|
Silverhawk |
|
$ |
|
|
|
$ |
(7 |
) |
SunCor commercial operations |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
Total income (loss) after taxes |
|
$ |
|
|
|
$ |
(6 |
) |
|
|
|
|
|
|
|
|
|
|
(a) |
|
For the three months ended March 31, 2005, income (loss) before
income taxes includes an interest expense allocation, net of capitalized costs,
of $3 million. The allocation was based on Pinnacle Wests weighted-average
interest rate applied to the net property, plant and equipment. |
18. Nuclear Decommissioning Trust
To fund the costs APS expects to incur to decommission Palo Verde, APS established external
decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in
debt and domestic equity securities. APS applies the provisions of SFAS
No. 115, Accounting for Certain Investments in Debt and Equity Securities, in accounting for
investments in decommissioning trust funds, and classifies these investments as available for sale.
As a result, we record the decommissioning trust funds at their fair value on our Condensed
Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in
rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has
recorded the offsetting amount of unrealized gains (losses) on investment securities in other
regulatory liabilities/assets. The following table summarizes the fair value of APS
nuclear decommissioning trust fund assets at March 31, 2006 and December 31, 2005 (dollars in
millions):
29
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Total |
|
|
|
|
|
|
|
Unrealized |
|
|
Unrealized |
|
|
|
Fair Value |
|
|
Gains |
|
|
Losses |
|
March 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities |
|
$ |
160 |
|
|
$ |
56 |
|
|
$ |
|
|
Debt securities |
|
|
145 |
|
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
305 |
|
|
$ |
57 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities |
|
$ |
150 |
|
|
$ |
50 |
|
|
$ |
|
|
Debt securities |
|
|
144 |
|
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
294 |
|
|
$ |
53 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
The costs of securities sold are determined on the basis of specific identification. The
following table sets forth approximate gains and losses and proceeds from the sale of securities by
the nuclear decommissioning trust funds (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2006 |
|
2005 |
Realized gains |
|
$ |
1 |
|
|
$ |
1 |
|
Realized losses |
|
|
(1 |
) |
|
|
(1 |
) |
Proceeds from the sale of securities |
|
|
34 |
|
|
|
40 |
|
The fair value of debt securities, summarized by contractual maturities, at March 31, 2006 is
as follows:
|
|
|
|
|
|
|
March 31, |
|
Fair Value (in millions) |
|
2006 |
|
Less than one year |
|
$ |
10 |
|
1 year - 5 years |
|
|
36 |
|
5 years - 10 years |
|
|
38 |
|
Greater than 10 years |
|
|
61 |
|
|
|
|
|
Total |
|
$ |
145 |
|
|
|
|
|
30
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
ELECTRIC OPERATING REVENUES |
|
|
|
|
|
|
|
|
Regulated electricity |
|
$ |
467,222 |
|
|
$ |
418,434 |
|
Marketing and trading |
|
|
9,647 |
|
|
|
22,858 |
|
|
|
|
|
|
|
|
Total |
|
|
476,869 |
|
|
|
441,292 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
Regulated electricity fuel and purchased power |
|
|
158,274 |
|
|
|
81,914 |
|
Marketing and trading fuel and purchased power |
|
|
1,368 |
|
|
|
28,302 |
|
Operations and maintenance |
|
|
173,353 |
|
|
|
142,294 |
|
Depreciation and amortization |
|
|
86,311 |
|
|
|
82,214 |
|
Income taxes |
|
|
(3,029 |
) |
|
|
16,380 |
|
Other taxes |
|
|
35,548 |
|
|
|
31,445 |
|
|
|
|
|
|
|
|
Total |
|
|
451,825 |
|
|
|
382,549 |
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
|
25,044 |
|
|
|
58,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (DEDUCTIONS) |
|
|
|
|
|
|
|
|
Income taxes |
|
|
236 |
|
|
|
(837 |
) |
Allowance for equity funds used during construction |
|
|
3,801 |
|
|
|
2,603 |
|
Other income (Note S-3) |
|
|
4,806 |
|
|
|
6,161 |
|
Other expense (Note S-3) |
|
|
(3,680 |
) |
|
|
(3,860 |
) |
|
|
|
|
|
|
|
Total |
|
|
5,163 |
|
|
|
4,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST DEDUCTIONS |
|
|
|
|
|
|
|
|
Interest on long-term debt |
|
|
34,250 |
|
|
|
35,517 |
|
Interest on short-term borrowings |
|
|
2,026 |
|
|
|
1,191 |
|
Debt discount, premium and expense |
|
|
1,173 |
|
|
|
1,004 |
|
Allowance for borrowed funds used during construction |
|
|
(1,721 |
) |
|
|
(1,947 |
) |
|
|
|
|
|
|
|
Total |
|
|
35,728 |
|
|
|
35,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
$ |
(5,521 |
) |
|
$ |
27,045 |
|
|
|
|
|
|
|
|
See Notes to Pinnacle Wests Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Companys Condensed Financial Statements.
31
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILITY PLANT |
|
|
|
|
|
|
|
|
Electric plant in service and held for future use |
|
$ |
10,793,563 |
|
|
$ |
10,682,999 |
|
Less accumulated depreciation and amortization |
|
|
3,665,740 |
|
|
|
3,616,886 |
|
|
|
|
|
|
|
|
Total |
|
|
7,127,823 |
|
|
|
7,066,113 |
|
|
|
|
|
|
|
|
|
|
Construction work in progress |
|
|
292,893 |
|
|
|
314,584 |
|
Intangible assets, net of accumulated amortization |
|
|
108,922 |
|
|
|
90,327 |
|
Nuclear fuel, net of accumulated amortization |
|
|
61,806 |
|
|
|
54,184 |
|
|
|
|
|
|
|
|
Utility plant net |
|
|
7,591,444 |
|
|
|
7,525,208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS AND OTHER ASSETS |
|
|
|
|
|
|
|
|
Decommissioning trust accounts |
|
|
305,096 |
|
|
|
293,943 |
|
Assets from long-term risk management and trading
activities (Note S-1) |
|
|
198,329 |
|
|
|
234,372 |
|
Other assets |
|
|
65,612 |
|
|
|
64,128 |
|
|
|
|
|
|
|
|
Total investments and other assets |
|
|
569,037 |
|
|
|
592,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
76,645 |
|
|
|
49,933 |
|
Customer and other receivables |
|
|
304,569 |
|
|
|
421,621 |
|
Allowance for doubtful accounts |
|
|
(3,192 |
) |
|
|
(3,568 |
) |
Materials and supplies (at average cost) |
|
|
112,350 |
|
|
|
109,736 |
|
Fossil fuel (at average cost) |
|
|
22,145 |
|
|
|
23,658 |
|
Assets from risk management and trading activities (Note
S-1) |
|
|
387,426 |
|
|
|
532,923 |
|
Other current assets |
|
|
10,229 |
|
|
|
14,639 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
910,172 |
|
|
|
1,148,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED DEBITS |
|
|
|
|
|
|
|
|
Deferred fuel and purchased power regulatory asset (Note 5) |
|
|
169,486 |
|
|
|
172,756 |
|
Other regulatory assets |
|
|
167,155 |
|
|
|
151,123 |
|
Unamortized debt issue costs |
|
|
24,630 |
|
|
|
25,279 |
|
Other deferred debits |
|
|
87,291 |
|
|
|
91,690 |
|
|
|
|
|
|
|
|
Total deferred debits |
|
|
448,562 |
|
|
|
440,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS |
|
$ |
9,519,215 |
|
|
$ |
9,707,441 |
|
|
|
|
|
|
|
|
See Notes to Pinnacle Wests Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Companys Condensed Financial Statements.
32
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
CAPITALIZATION AND LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION |
|
|
|
|
|
|
|
|
Common stock |
|
$ |
178,162 |
|
|
$ |
178,162 |
|
Additional paid-in capital (Note 5) |
|
|
2,063,098 |
|
|
|
1,853,098 |
|
Retained earnings |
|
|
770,154 |
|
|
|
860,675 |
|
Accumulated other comprehensive income (loss): |
|
|
|
|
|
|
|
|
Minimum pension liability adjustment |
|
|
(86,132 |
) |
|
|
(86,132 |
) |
Derivative instruments |
|
|
73,974 |
|
|
|
179,422 |
|
|
|
|
|
|
|
|
Common stock equity |
|
|
2,999,256 |
|
|
|
2,985,225 |
|
Long-term debt less current maturities |
|
|
2,479,689 |
|
|
|
2,479,703 |
|
|
|
|
|
|
|
|
Total capitalization |
|
|
5,478,945 |
|
|
|
5,464,928 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES |
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
|
85,018 |
|
|
|
85,620 |
|
Accounts payable |
|
|
149,529 |
|
|
|
215,384 |
|
Accrued taxes |
|
|
391,080 |
|
|
|
360,737 |
|
Accrued interest |
|
|
35,262 |
|
|
|
25,003 |
|
Dividends payable |
|
|
42,500 |
|
|
|
|
|
Customer deposits |
|
|
57,192 |
|
|
|
55,474 |
|
Deferred income taxes |
|
|
8,682 |
|
|
|
64,210 |
|
Liabilities from risk management and trading activities (Note S-1) |
|
|
413,299 |
|
|
|
480,138 |
|
Other
current liabilities (Note S-1) |
|
|
97,012 |
|
|
|
227,398 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
1,279,574 |
|
|
|
1,513,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
1,205,489 |
|
|
|
1,215,403 |
|
Regulatory liabilities |
|
|
571,939 |
|
|
|
592,494 |
|
Liability for asset retirements |
|
|
273,238 |
|
|
|
269,011 |
|
Pension liability |
|
|
253,298 |
|
|
|
233,342 |
|
Customer advances for construction |
|
|
62,248 |
|
|
|
60,287 |
|
Unamortized gain sale of utility plant |
|
|
44,613 |
|
|
|
45,757 |
|
Liabilities from long-term risk management and trading
activities (Note S-1) |
|
|
129,029 |
|
|
|
83,774 |
|
Other |
|
|
220,842 |
|
|
|
228,481 |
|
|
|
|
|
|
|
|
Total deferred credits and other |
|
|
2,760,696 |
|
|
|
2,728,549 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13, 15 and S-4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION AND LIABILITIES |
|
$ |
9,519,215 |
|
|
$ |
9,707,441 |
|
|
|
|
|
|
|
|
See Notes to Pinnacle Wests Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Companys Condensed Financial Statements.
33
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(5,521 |
) |
|
$ |
27,045 |
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization including nuclear fuel |
|
|
93,762 |
|
|
|
87,539 |
|
Deferred fuel and purchased power |
|
|
(14,538 |
) |
|
|
|
|
Deferred fuel amortization |
|
|
17,808 |
|
|
|
|
|
Allowance for equity funds used during construction |
|
|
(3,801 |
) |
|
|
(2,603 |
) |
Deferred income taxes |
|
|
1,757 |
|
|
|
(1,009 |
) |
Change in mark-to-market valuations |
|
|
974 |
|
|
|
(8,234 |
) |
Changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
Customer and other receivables |
|
|
124,568 |
|
|
|
70,493 |
|
Materials, supplies and fossil fuel |
|
|
(1,101 |
) |
|
|
(5,309 |
) |
Other current assets |
|
|
4,892 |
|
|
|
3,089 |
|
Accounts payable |
|
|
(62,543 |
) |
|
|
(123,460 |
) |
Accrued taxes |
|
|
30,343 |
|
|
|
47,839 |
|
Collateral |
|
|
(150,640 |
) |
|
|
31,080 |
|
Other current liabilities |
|
|
32,231 |
|
|
|
(29,573 |
) |
Change in risk management and trading activities liabilities |
|
|
(65,131 |
) |
|
|
36,204 |
|
Change in other long-term assets |
|
|
(5,335 |
) |
|
|
(11,821 |
) |
Change in other long-term liabilities |
|
|
11,366 |
|
|
|
6,168 |
|
|
|
|
|
|
|
|
Net cash flow provided by operating activities |
|
|
9,091 |
|
|
|
127,448 |
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(140,185 |
) |
|
|
(117,501 |
) |
Allowance for borrowed funds used during construction |
|
|
(1,721 |
) |
|
|
(1,947 |
) |
Purchases of investment securities |
|
|
(122,025 |
) |
|
|
(67,450 |
) |
Proceeds from sale of investment securities |
|
|
122,025 |
|
|
|
248,625 |
|
Proceeds from nuclear decommissioning trust sales |
|
|
33,743 |
|
|
|
39,777 |
|
Investment in nuclear decommissioning trust |
|
|
(38,929 |
) |
|
|
(42,638 |
) |
Other |
|
|
(1,966 |
) |
|
|
8,934 |
|
|
|
|
|
|
|
|
Net cash flow provided by (used for) investing activities |
|
|
(149,058 |
) |
|
|
67,800 |
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
Issuance of long-term debt |
|
|
|
|
|
|
163,975 |
|
Equity infusion |
|
|
210,000 |
|
|
|
|
|
Dividends paid on common stock |
|
|
(42,500 |
) |
|
|
(42,500 |
) |
Repayment and reacquisition of long-term debt |
|
|
(821 |
) |
|
|
(264,482 |
) |
|
|
|
|
|
|
|
Net cash flow provided by (used for) financing activities |
|
|
166,679 |
|
|
|
(143,007 |
) |
|
|
|
|
|
|
|
NET INCREASE IN CASH AND CASH EQUIVALENTS |
|
|
26,712 |
|
|
|
52,241 |
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD |
|
|
49,933 |
|
|
|
49,575 |
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
|
$ |
76,645 |
|
|
$ |
101,816 |
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
Cash paid during the year for: |
|
|
|
|
|
|
|
|
Income taxes paid, net of refunds |
|
$ |
|
|
|
$ |
9 |
|
Interest, net of amounts capitalized |
|
$ |
24,297 |
|
|
$ |
30,149 |
|
See Notes to Pinnacle Wests Condensed Consolidated Financial Statements and Supplemental Notes
to Arizona Public Service Companys Condensed Financial Statements.
34
Certain notes to APS Condensed Financial Statements are combined with the Notes to
Pinnacle Wests Condensed Consolidated Financial Statements. Listed below are the Condensed
Consolidated Notes to Pinnacle Wests Condensed Consolidated Financial Statements, the majority of
which also relate to APS Condensed Financial Statements. In addition, listed below are the
Supplemental Notes which are required disclosures for APS and should be read in conjunction with
Pinnacle Wests Condensed Consolidated Notes.
|
|
|
|
|
|
|
Condensed |
|
APS |
|
|
Consolidated |
|
Supplemental |
|
|
Footnote |
|
Footnote |
|
|
Reference |
|
Reference |
Consolidation and Nature of Operations |
|
Note 1 |
|
|
Condensed Consolidated Financial Statements |
|
Note 2 |
|
|
Quarterly Fluctuations |
|
Note 3 |
|
|
Changes in Liquidity |
|
Note 4 |
|
|
Regulatory Matters |
|
Note 5 |
|
|
Retirement Plans and Other Benefits |
|
Note 6 |
|
|
Business Segments |
|
Note 7 |
|
|
Stock-Based Compensation |
|
Note 8 |
|
|
Variable Interest Entities |
|
Note 9 |
|
|
Derivative and Energy Trading Accounting |
|
Note 10 |
|
Note S-1 |
Comprehensive Income |
|
Note 11 |
|
Note S-2 |
Commitments and Contingencies |
|
Note 12 |
|
|
Nuclear Insurance |
|
Note 13 |
|
|
Other Income and Other Expense |
|
Note 14 |
|
Note S-3 |
Guarantees |
|
Note 15 |
|
|
Earnings Per Share |
|
Note 16 |
|
|
Discontinued Operations |
|
Note 17 |
|
|
Nuclear Decommissioning Trust |
|
Note 18 |
|
|
Related Party Transactions |
|
|
|
Note S-4 |
35
ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-1. Derivative and Energy Trading Accounting
APS is exposed to the impact of market fluctuations in the commodity price of electricity,
natural gas, coal and emissions allowances. As part of its overall risk management program, APS
uses various commodity instruments that qualify as derivatives to hedge purchases and sales of
electricity, fuels, and emission allowances and credits. As of March 31, 2006, APS hedged
exposures to these risks for a maximum of 3.25 years.
Cash Flow Hedges
The changes in the fair value of APS hedged positions included in the APS Condensed
Statements of Income, after consideration of amounts deferred under the PSA, for the three months
ended March 31, 2006 and 2005 were comprised of the following (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2006 |
|
2005 |
Gains (losses) on the ineffective portion of
derivatives qualifying for hedge accounting |
|
$ |
(436 |
) |
|
$ |
7,417 |
|
Gains (losses) from the change in options time
value excluded from measurement of
effectiveness |
|
|
(18 |
) |
|
|
858 |
|
Gains from the discontinuance of cash flow
hedges |
|
|
159 |
|
|
|
302 |
|
During the next twelve months ending March 31, 2007, APS estimates that a net gain of $41
million before income taxes will be reclassified from accumulated other comprehensive income as an
offset to the effect of market price changes for the related hedged transactions. To the extent
the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a
regulatory asset or liability and have no effect on earnings (see Note 5).
APS assets and liabilities from risk management and trading activities are presented in two
categories, consistent with Pinnacle Wests business segments.
The following table summarizes APS assets and liabilities from risk management and trading
activities at March 31, 2006 and December 31, 2005 (dollars in thousands):
36
ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments |
|
|
|
|
|
|
Deferred |
|
|
|
|
|
|
Current |
|
|
and Other |
|
|
Current |
|
|
Credits and |
|
|
Net Asset |
|
|
|
Assets |
|
|
Assets |
|
|
Liabilities |
|
|
Other |
|
|
(Liability) |
|
Regulated Electricity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
$ |
381,639 |
|
|
$ |
194,319 |
|
|
$ |
(350,517 |
) |
|
$ |
(121,356 |
) |
|
$ |
104,085 |
|
Margin account
and options |
|
|
45 |
|
|
|
|
|
|
|
(58,224 |
) |
|
|
|
|
|
|
(58,179 |
) |
Marketing and Trading: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
|
4,480 |
|
|
|
4,010 |
|
|
|
(4,347 |
) |
|
|
(6,866 |
) |
|
|
(2,723 |
) |
Options at cost |
|
|
1,262 |
|
|
|
|
|
|
|
(211 |
) |
|
|
(807 |
) |
|
|
244 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
387,426 |
|
|
$ |
198,329 |
|
|
$ |
(413,299 |
) |
|
$ |
(129,029 |
) |
|
$ |
43,427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments |
|
|
|
|
|
|
Deferred |
|
|
|
|
|
|
Current |
|
|
and Other |
|
|
Current |
|
|
Credits and |
|
|
Net Asset |
|
|
|
Assets |
|
|
Assets |
|
|
Liabilities |
|
|
Other |
|
|
(Liability) |
|
Regulated Electricity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
$ |
516,399 |
|
|
$ |
228,873 |
|
|
$ |
(335,801 |
) |
|
$ |
(74,787 |
) |
|
$ |
334,684 |
|
Margin account
and options |
|
|
1,814 |
|
|
|
|
|
|
|
(124,165 |
) |
|
|
|
|
|
|
(122,351 |
) |
Marketing and Trading: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
|
13,027 |
|
|
|
5,499 |
|
|
|
(20,172 |
) |
|
|
(8,778 |
) |
|
|
(10,424 |
) |
Options at cost |
|
|
1,683 |
|
|
|
|
|
|
|
|
|
|
|
(209 |
) |
|
|
1,474 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
532,923 |
|
|
$ |
234,372 |
|
|
$ |
(480,138 |
) |
|
$ |
(83,774 |
) |
|
$ |
203,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was a liability of $57 million at March 31, 2006 and $123 million
at December 31, 2005 and is included in the margin account in the table above. Cash is deposited
with the broker in this account at the time futures or options contracts are initiated. The change
in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin
account balance.
Cash or other assets may be required to serve as collateral against APS open positions on
certain energy-related contracts. No collateral was provided to counterparties at March 31, 2006
or December 31, 2005. Collateral provided to us by counterparties was $24 million at March 31,
2006 and $175 million at December 31, 2005, and is included in other current liabilities on the
Condensed Balance Sheets.
S-2. Comprehensive Income (Loss)
Components of APS comprehensive income (loss) for the three months ended March 31, 2006 and
2005 are as follows (dollars in thousands):
37
ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Net income (loss) |
|
$ |
(5,521 |
) |
|
$ |
27,045 |
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
Net unrealized gains (losses) on derivative
instruments (a) |
|
|
(162,892 |
) |
|
|
108,217 |
|
Net reclassification of realized gains to income (b) |
|
|
(10,116 |
) |
|
|
(1,381 |
) |
Net income tax benefit (expense) related to items
of other comprehensive income (loss) |
|
|
67,560 |
|
|
|
(42,061 |
) |
|
|
|
|
|
|
|
Total other comprehensive income (loss) |
|
|
(105,448 |
) |
|
|
64,775 |
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(110,969 |
) |
|
$ |
91,820 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
These amounts primarily include unrealized gains and losses on contracts used to
hedge our forecasted electricity and natural gas requirements to serve Native Load.
These changes are primarily due to changes in forward natural gas prices and wholesale
electricity prices. |
|
(b) |
|
These amounts primarily include the reclassification of unrealized gains and
losses to realized gains and losses for contracted commodities delivered during the
period. |
S-3. Other Income and Other Expense
The following table provides detail of APS other income and other expense for the three
months ended March 31, 2006 and 2005 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Other income: |
|
|
|
|
|
|
|
|
Interest income |
|
$ |
3,534 |
|
|
$ |
5,423 |
|
Asset sales |
|
|
361 |
|
|
|
241 |
|
Investment gains net |
|
|
875 |
|
|
|
|
|
Miscellaneous |
|
|
36 |
|
|
|
497 |
|
|
|
|
|
|
|
|
Total other income |
|
$ |
4,806 |
|
|
$ |
6,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense: |
|
|
|
|
|
|
|
|
Non-operating costs (a) |
|
$ |
(3,216 |
) |
|
$ |
(2,628 |
) |
Asset sales |
|
|
(196 |
) |
|
|
(64 |
) |
Investment losses net |
|
|
|
|
|
|
(502 |
) |
Miscellaneous |
|
|
(268 |
) |
|
|
(666 |
) |
|
|
|
|
|
|
|
Total other expense |
|
$ |
(3,680 |
) |
|
$ |
(3,860 |
) |
|
|
|
|
|
|
|
|
|
|
(a) |
|
As defined by the FERC, includes below-the-line non-operating utility costs
(primarily community relations and other costs excluded from utility rate recovery). |
38
ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-4. Related Party Transactions
From time to time, APS enters into transactions with Pinnacle West or Pinnacle Wests other
subsidiaries. The following table summarizes the amounts included in the APS Condensed Statements
of Income and Condensed Balance Sheets related to transactions with affiliated companies (dollars
in millions):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Electric operating revenues: |
|
|
|
|
|
|
|
|
Pinnacle West marketing and trading |
|
$ |
1 |
|
|
$ |
1 |
|
Pinnacle West Energy |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
Total |
|
$ |
1 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel and purchased power costs: |
|
|
|
|
|
|
|
|
Pinnacle West Energy |
|
$ |
|
|
|
$ |
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other: |
|
|
|
|
|
|
|
|
Pinnacle West Energy interest income |
|
$ |
|
|
|
$ |
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of |
|
|
As of |
|
|
|
March 31, 2006 |
|
|
December 31, 2005 |
|
Net intercompany receivables (payables): |
|
|
|
|
|
|
|
|
Pinnacle West marketing and
trading |
|
$ |
27 |
|
|
$ |
82 |
|
APS Energy Services |
|
|
1 |
|
|
|
2 |
|
Pinnacle West |
|
|
(17 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
11 |
|
|
$ |
82 |
|
|
|
|
|
|
|
|
Electric revenues include sales of electricity to affiliated companies at contract prices.
Purchased power includes purchases of electricity from affiliated companies at contract prices.
APS purchases electricity from and sells electricity to APS Energy Services; however, these
transactions are settled net and reported net in accordance with EITF 03-11, Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held
for Trading Purposes As Defined in EITF Issue No. 02-3.
Intercompany receivables primarily include amounts related to the intercompany sales of
electricity. Intercompany payables primarily include amounts related to the intercompany purchases
of electricity. Intercompany receivables and payables are generally settled on a current basis in
cash.
39
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle Wests Condensed
Consolidated Financial Statements and Arizona Public Service Companys Condensed Financial
Statements and the related Notes that appear in Item 1 of this report.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated
electric utility that provides retail and wholesale electric service to most of the state of
Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson
metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a
substantial part of our revenues and earnings, and is expected to continue to do so. Customer
growth in APS service territory is about three times the national average and remains a
fundamental driver of our revenues and earnings.
The ACC regulates APS retail electric rates. The key issue affecting Pinnacle Wests and
APS financial outlook is the satisfactory resolution of APS retail rate proceedings pending
before the ACC. As discussed in greater detail in Note 5, APS has pending before the ACC:
|
|
|
a general retail rate case pursuant to which APS is requesting a 21.3%, or $453.9
million, increase in its annual retail electricity revenues effective no later than
December 31, 2006; and |
|
|
|
|
an application for a temporary rate increase of approximately 1.9%, through a PSA
surcharge, to recover $45 million in retail fuel and purchased
power costs relating to Palo Verdes 2005 unplanned outages, which were deferred by
APS in 2005 under the PSA. |
See Deferred Fuel and Purchased Power Costs below for a discussion of Palo Verde Unit 1s
current outage to remedy an operating condition, the units previous reduced power levels resulting
from that condition, and the associated economic impact.
SunCor, our real estate development subsidiary, has been and is expected to be an important
source of earnings and cash flow. Our subsidiary, APS Energy Services, provides competitive
commodity-related energy services and energy-related products and services to commercial and
industrial retail customers in the western United States. El Dorado, our investment subsidiary,
owns minority interests in several energy-related investments and Arizona community-based ventures.
Pinnacle West Energy is our subsidiary that previously owned and operated unregulated
generating plants. Pursuant to the ACCs April 7, 2005 order in APS 2003 rate case, on July 29,
2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. See APS 2003 Rate Case
in Note 5. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006.
See Note 17 for discussion of discontinued operations. As a result, Pinnacle West Energy no longer
owns any generating plants and has ceased operations.
We continue to focus on solid operational performance in our electricity generation and
delivery activities. In the delivery area, we focus on superior reliability and customer
satisfaction.
40
We plan to expand long-term resources and our transmission and distribution systems to meet
the electricity needs of our growing retail customers and sustain reliability.
See Pinnacle West Consolidated Factors Affecting Our Financial Outlook below for a
discussion of several factors that could affect our future financial results.
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
Pinnacle West has three principal business segments (determined by products, services and the
regulatory environment):
|
|
|
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electric service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution; |
|
|
|
|
our real estate segment, which consists of SunCors real estate development and
investment activities; and |
|
|
|
|
our marketing and trading segment, which consists of our competitive energy business
activities, including wholesale marketing and trading and APS Energy Services
commodity-related energy services. |
The following table summarizes net income for the three months ended March 31, 2006 and 2005
(dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
Regulated electricity |
|
$ |
(12 |
) |
|
$ |
14 |
|
Real estate |
|
|
21 |
|
|
|
8 |
|
Marketing and trading |
|
|
2 |
|
|
|
7 |
|
Other |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
12 |
|
|
|
30 |
|
Discontinued operations net of tax: |
|
|
|
|
|
|
|
|
Real estate (a) |
|
|
|
|
|
|
1 |
|
Marketing and trading (b) |
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
Net income |
|
$ |
12 |
|
|
$ |
24 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Primarily relates to sales of commercial properties. |
|
(b) |
|
Primarily relates to the operations of Silverhawk. |
41
PINNACLE WEST CONSOLIDATED RESULTS OF OPERATIONS
General
Throughout the following explanations of our results of operations, we refer to gross
margin. With respect to our regulated electricity segment and our marketing and trading segment,
gross margin refers to operating revenues less fuel and purchased power costs. Gross margin is a
non-GAAP financial measure, as defined in accordance with SEC rules. Exhibit 99.1 reconciles
this non-GAAP financial measure to operating income, which is the most directly comparable
financial measure calculated and presented in accordance with GAAP. We view gross margin as an
important performance measure of the core profitability of our operations. This measure is a key
component of our internal financial reporting and is used by our management in analyzing our
business segments. We believe that investors benefit from having access to the same financial
measures that our management uses. In addition, we have reclassified certain prior-period amounts
to conform to our current-period presentation.
Deferred Fuel and Purchased Power Costs
APS retail rate settlement became effective April 1, 2005. As part of the settlement, the
ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel
and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers
for future rate recovery 90% of the difference between actual retail fuel and purchased power costs
and the amount of such costs currently included in base rates. APS recovery of PSA deferrals from
its customers is subject to the ACCs approval of annual PSA adjustments and periodic surcharge
applications.
The balance of APS pretax deferred fuel and purchased power regulatory asset (PSA
deferrals) at March 31, 2006 was $169 million. Based on the ACCs approval of the May 1, 2006
interim adjustor and $15 million PSA surcharge (see Interim Rate Increase and
Application for PSA Surcharges in Note 5), APS estimates that its pretax PSA deferral balance at
December 31, 2006 will be approximately $160 million to $180 million assuming no additional interim
rate relief and based on APS hedged positions for fuel and purchased power at March 31, 2006;
recent forward market prices for natural gas and purchased power (which are subject to change);
strong performance from APS fossil-fueled generating units during the three months ended
March 31, 2006; and the operating performance at Palo Verde Unit 1 discussed below.
The PSA deferral balances at March 31, 2006 and estimated at December 31, 2006 each include
$45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages.
APS has requested the recovery of these deferrals through a PSA surcharge upon the ACCs completion
of an inquiry regarding the outages.
APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18,
2006 due to vibration levels in one of the Units shutdown cooling lines. APS began a planned
outage of Unit 1 on March 18, 2006 and, based on early inspections and testing during that outage,
determined to perform the necessary work and modifications to remedy the situation prior to
returning the Unit to service. APS believes that performing the work during the current Unit 1
outage will provide greater assurance that Unit 1 will be operating during the peak summer months
and somewhat accelerate returning the Unit to full power (which is currently expected in the June
timeframe).
42
APS
estimates that pretax incremental replacement power costs resulting
from Unit 1s current outage and reduced power levels were
approximately $36 million during the three months ended
March 31, 2006 and that such costs will be approximately
$47 million in the second quarter of 2006. The
related PSA deferrals were approximately $32 million in the three months ended March 31, 2006 and
are estimated to be approximately $42 million in the second quarter of 2006.
The Palo Verde replacement power costs were partially offset by
$17 million of lower replacement power costs related to strong
performance from APS fossil-fueled generating units
during the three months ended March 31,
2006. As a result, the corresponding deferrals were reduced in the
quarter by $15 million. As noted under
Interim Rate Increase under Note 5, the ACC has directed
the ACC staff to undertake a
prudence audit of all unplanned 2006 Palo Verde outage costs.
See Note 5 for further information regarding the PSA and APS pending PSA surcharge
application.
Operating Results Three-month period ended March 31, 2006 compared with three-month period ended
March 31, 2005
Our
consolidated net income for the three months ended March 31, 2006 was $12 million compared
with $24 million for the comparable prior-year period. The three months ended March 31, 2005
included an after-tax net loss from discontinued operations of
$6 million, which was related
primarily to the operations of Silverhawk, partially offset by sales of commercial properties at
SunCor. Income from continuing operations decreased $18 million in the period-to-period
comparison, reflecting the following changes in earnings by segment:
|
|
|
Regulated Electricity Segment Income from continuing operations decreased
approximately $26 million primarily due to higher fuel and
purchased power costs (as discussed above) and higher prices, and higher operations and
maintenance expense related to generation and customer service costs. These negative
factors were partially offset by deferred fuel and purchased power costs; higher retail
sales volumes due to customer growth; a retail price increase effective April 1, 2005;
and higher interest income. |
|
|
|
|
Real Estate Segment Income from continuing operations increased approximately $13
million primarily due to increased parcel and home sales. |
|
|
|
|
Marketing and Trading Segment Income from continuing operations decreased
approximately $5 million primarily due to lower mark-to-market gains on contracts for
future delivery and the absence of Off-System Sales that we began reporting in the
regulated electricity segment in April 2005. |
43
Additional details on the major factors that increased (decreased) net income are contained in the
following table (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Pretax |
|
|
After Tax |
|
Regulated electricity segment gross margin: |
|
|
|
|
|
|
|
|
Higher fuel and purchased power costs |
|
$ |
(55 |
) |
|
$ |
(34 |
) |
Deferred fuel and purchased power costs (fuel deferrals began
April 1, 2005) |
|
|
13 |
|
|
|
8 |
|
Higher retail sales volumes due to customer growth,
excluding weather effects |
|
|
13 |
|
|
|
8 |
|
Retail price increase effective April 1, 2005 |
|
|
7 |
|
|
|
4 |
|
Effects of weather on retail sales |
|
|
(3 |
) |
|
|
(2 |
) |
Miscellaneous items, net |
|
|
(4 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
Net decrease in regulated electricity segment gross margin |
|
|
(29 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
Marketing and trading segment gross margin: |
|
|
|
|
|
|
|
|
Lower mark-to-market gains on contracts for future delivery
due to changes in forward prices |
|
|
(9 |
) |
|
|
(6 |
) |
Lower realized margins on wholesale sales primarily
due to the absence of sales that we began reporting in the
regulated segment in April 2005 |
|
|
(5 |
) |
|
|
(3 |
) |
Miscellaneous items, net |
|
|
6 |
|
|
|
4 |
|
|
|
|
|
|
|
|
Net decrease in marketing and trading segment
gross margin |
|
|
(8 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
Net decrease in gross margin for regulated electricity
and marketing and trading segments |
|
|
(37 |
) |
|
|
(23 |
) |
Higher real estate segment contribution primarily related to
increased parcel and home sales |
|
|
22 |
|
|
|
13 |
|
Operations and maintenance increases primarily due to: |
|
|
|
|
|
|
|
|
Generation costs, including maintenance and overhauls |
|
|
(18 |
) |
|
|
(11 |
) |
Customer service costs, including regulatory demand-side
management programs and planned maintenance |
|
|
(5 |
) |
|
|
(3 |
) |
Depreciation and amortization decreases primarily due to lower
depreciation rates, partially offset by increased depreciable
assets |
|
|
3 |
|
|
|
2 |
|
Higher other income, net of expense primarily due to increased
interest income |
|
|
5 |
|
|
|
3 |
|
Miscellaneous items, net |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
Net decrease in income from continuing operations |
|
$ |
(30 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
|
Discontinued operations related to: |
|
|
|
|
|
|
|
|
Silverhawk operations in 2005 |
|
|
|
|
|
|
7 |
|
Sales of real estate assets |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
Net decrease in net income |
|
|
|
|
|
$ |
(12 |
) |
|
|
|
|
|
|
|
|
44
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $50 million higher for the three months ended
March 31, 2006 compared with the prior-year period primarily as a result of:
|
|
|
a $19 million increase in retail revenues related to customer growth,
excluding weather effects; |
|
|
|
|
an $18 million increase in revenues related to the implementation of the
February 1, 2006 PSA adjustor, which has no earnings effect due
to the offset from amortization of deferred fuel in fuel and purchased power expense; |
|
|
|
|
a $12 million increase in Off-System Sales primarily resulting from
sales previously reported in the marketing and trading segment that were classified
beginning in April 2005 as sales in the regulated electricity segment in accordance
with the APS retail rate case settlement; |
|
|
|
|
a $7 million increase in retail revenues due to a price increase
effective April 1, 2005; |
|
|
|
|
a $4 million decrease in retail revenues related to weather; and |
|
|
|
|
a $2 million decrease due to miscellaneous factors. |
Marketing and Trading Segment Revenues
Marketing and trading segment revenues were $4 million lower for the three months ended March
31, 2006 compared with the prior-year period primarily as a result of:
|
|
|
a $22 million increase from higher volumes of competitive retail sales
in California; |
|
|
|
|
a $12 million decrease in Off-System Sales due to the absence of sales
previously reported in the marketing and trading segment that were classified beginning
in April 2005 as sales in the regulated electricity segment in accordance with the APS
retail rate case settlement; |
|
|
|
|
a $9 million decrease in mark-to-market gains on contracts for future
delivery due to changes in forward prices; and |
|
|
|
|
a $5 million decrease due to miscellaneous factors. |
Real Estate Revenues
Real estate revenues were $38 million higher for the three months ended March 31, 2006
compared with the prior-year period primarily due to increased parcel and home sales at SunCor.
45
LIQUIDITY AND CAPITAL RESOURCES
Capital Needs and Resources Pinnacle West Consolidated
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for the three months ended
March 31, 2006 and estimated capital expenditures for the next
three years:
CAPITAL EXPENDITURES
(dollars in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Estimated for the Year Ended |
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
APS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution |
|
$ |
86 |
|
|
$ |
322 |
|
|
$ |
323 |
|
|
$ |
362 |
|
Transmission |
|
|
25 |
|
|
|
120 |
|
|
|
169 |
|
|
|
203 |
|
Generation |
|
|
31 |
|
|
|
184 |
|
|
|
207 |
|
|
|
279 |
|
Other (a) |
|
|
6 |
|
|
|
23 |
|
|
|
16 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal |
|
|
148 |
|
|
|
649 |
|
|
|
715 |
|
|
|
857 |
|
SunCor (b) |
|
|
46 |
|
|
|
232 |
|
|
|
142 |
|
|
|
119 |
|
Other |
|
|
1 |
|
|
|
6 |
|
|
|
2 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
195 |
|
|
$ |
887 |
|
|
$ |
859 |
|
|
$ |
982 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Primarily information systems and facilities projects. |
|
(b) |
|
Consists primarily of capital expenditures for land development and retail and
office building construction reflected in Real estate investments on the Condensed
Consolidated Statements of Cash Flows. |
Distribution and transmission capital expenditures are comprised of 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 lines,
substations, line extensions to new residential and commercial developments and upgrades to
customer information systems. Major transmission projects are driven by strong regional customer
growth.
Generation capital expenditures are comprised of various improvements to APS existing fossil
and nuclear plants and the replacement of Palo Verde steam generators (see below). Examples of the
types of projects included in this category are additions, upgrades and capital replacements of
various power plant equipment such as turbines, boilers and environmental equipment. Generation
also includes nuclear fuel expenditures of approximately $35 million annually for 2006 through
2008.
Replacement of the steam generators at Palo Verde Unit 1 was completed during the fall 2005
outage at a cost to APS of approximately $70 million. The Palo Verde owners have approved the
manufacture of one additional set of steam generators. These generators will be installed in Unit
46
3 and are scheduled for completion in the fall of 2007 at an approximate cost of $75 million (APS
share). Approximately $20 million of the Unit 3 steam generator costs have been incurred through
2005 with the remaining $55 million included in future years in the capital expenditures table
above. Capital expenditures will be funded with internally generated cash and/or external
financings.
Contractual Obligations
Our future contractual obligations have not changed materially from the amounts disclosed in
Part II, Item 7 of the 2005 Form 10-K with the exception of our aggregate:
|
|
|
fuel and purchased power commitments, which increased from approximately $1.9
billion at December 31, 2005 to $3 billion at March 31, 2006 as follows (in billions): |
|
|
|
|
|
|
|
|
|
2006 |
|
2007-2008 |
|
2009-2010 |
|
Thereafter |
|
Total |
$0.4
|
|
$0.5
|
|
$0.4
|
|
$1.7
|
|
$3.0 |
See Note 4 for a list of payments due on total long-term debt and capitalized lease
requirements.
Off-Balance Sheet Arrangements
In 1986, APS entered into agreements with three separate VIE 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. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly,
do not consolidate them.
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of
certain events that APS does not consider to be reasonably likely to occur. Under certain
circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde
or the occurrence of specified nuclear events), APS would be required to assume the debt associated
with the transactions, make specified payments to the equity participants, and take title to the
leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If
such an event had occurred as of March 31, 2006, APS would have been required to assume
approximately $234 million of debt and pay the equity participants approximately $185 million.
Guarantees and Letters of Credit
We and certain of our subsidiaries have issued guarantees and letters of credit in support of
our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services.
We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to
these obligations. We generally agree to indemnification provisions related to liabilities arising
from or related to certain of our agreements, with limited exceptions depending on the particular
agreement. See Note 15 for additional information regarding guarantees and letters of credit.
Credit Ratings
The
ratings of securities of Pinnacle West and APS as of May 8, 2006 are shown below. The
ratings reflect the respective views of the rating agencies, from which an explanation of the
significance of their ratings may be obtained. There is no assurance that these ratings will
continue
47
for any given period of time. The ratings may be revised or withdrawn entirely by the rating
agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or
withdrawal may adversely affect the market price of Pinnacle Wests or APS securities and serve to
increase those companies cost of and access to capital. It may also require additional collateral
related to certain derivative instruments (see Note 10).
|
|
|
|
|
|
|
Moodys |
|
Standard & Poors |
Pinnacle West |
|
|
|
|
Senior unsecured1 |
|
(P) Baa3 |
|
BB+ (prelim) |
Commercial paper |
|
P-3 |
|
A-3 |
Outlook |
|
Negative |
|
Stable |
APS |
|
|
|
|
Senior unsecured |
|
Baa2 |
|
BBB- |
Secured lease
obligation bonds |
|
Baa2 |
|
BBB- |
Commercial paper |
|
P-2 |
|
A-3 |
Outlook |
|
Negative |
|
Stable |
1 Pinnacle West has a shelf registration under SEC rule 415. Moodys assigns a
provisional (P) rating and Standard & Poors assigns a preliminary (prelim) rating to such shelf
registrations. Pinnacle West currently has no outstanding, rated senior unsecured securities.
Debt Provisions
Pinnacle Wests and APS debt covenants related to their respective bank financing
arrangements include a debt to capitalization ratio. Certain of APS bank financing arrangements
also include an interest coverage test. Pinnacle West and APS comply with these covenants and each
anticipates it will continue to meet these and other significant covenant requirements. For each
of Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total
consolidated capitalization cannot exceed 65%. At March 31, 2006, the ratio was approximately 50%
for Pinnacle West and 46% for APS. The provisions regarding interest coverage require a minimum
cash coverage of two times the interest requirements for APS. The interest coverage is
approximately 3.6 times under APS bank financing agreements as of March 31, 2006. 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 and could cross-default
other debt.
Neither Pinnacle Wests nor APS financing agreements contain rating triggers that would
result in an acceleration of the required interest and principal payments in the event of a rating
downgrade. However, in the event of a further rating downgrade, Pinnacle West and/or APS may be
subject to increased interest costs under certain financing agreements.
All of Pinnacle Wests bank agreements contain cross-default provisions that would result in
defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or
APS were to default under certain other material agreements. All of APS bank agreements contain
cross-default provisions that would result in defaults and the potential acceleration of payment
under
48
these bank agreements if APS were to default under certain other material agreements. Pinnacle
West and APS do not have a material adverse change restriction for revolver borrowings.
See Note 4 for further discussions.
Capital Needs and Resources By Company
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders and principal and interest
payments on our long-term debt. The level of our common stock dividends and future dividend growth
will be dependent on a number of factors including, but not limited to, payout ratio trends, free
cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external financings and cash distributions
from our other subsidiaries, primarily SunCor. An existing ACC order requires APS to maintain a
common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the
payment would reduce its common equity below that threshold. As defined in the ACC order, common
equity ratio is common equity divided by the sum of common equity and long-term debt, including
current maturities of long-term debt. At March 31, 2006, APS common equity ratio, as defined, was
approximately 54%.
Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our
subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no
more than the maximum tax-deductible amount. The minimum required funding takes into consideration
the value of the fund assets and our pension obligation. The assets in the plan are comprised of
common stocks, bonds, common and collective trusts and short-term investments. Future year
contribution amounts are dependent on fund performance and fund valuation assumptions. We
contributed $53 million in 2005. The contribution to our pension plan in 2006 is estimated to be
approximately $50 million, $14 million of which was contributed on April 14, 2006. The
contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29
million. APS and other subsidiaries fund their share of the contributions. APS share is
approximately 97% of both plans.
In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the
sale of Silverhawk. See Equity Infusions in Note 5 for more information.
On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with
Prudential Investment Management, Inc. (Prudential) and certain of its affiliates. The agreement
provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for
purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes
issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28,
2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal
amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the Series A Notes).
On March 22, 2006, the Pinnacle West Board of Directors declared a quarterly dividend of $0.50
per share of common stock, payable on June 1, 2006, to shareholders of record on May 1, 2006.
49
On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April, 2006.
Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds
to repay these notes.
APS
APS capital requirements consist primarily of capital expenditures and optional and mandatory
redemptions of long-term debt. APS pays for its capital requirements with cash from operations
and, to the extent necessary, external financings. APS has historically paid its dividends to
Pinnacle West with cash from operations. See Pinnacle West (Parent Company) above for a
discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle
West.
Although provisions in APS articles of incorporation and ACC financing orders establish
maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these
provisions to limit its ability to meet its capital requirements.
See Deferred Fuel and Purchased Power Costs above and Power Supply Adjustor in Note 5 for
information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and
purchased power costs on a current basis, APS recovery of the deferrals from its ratepayers is
subject to the ACCs approval of annual PSA adjustments and periodic surcharge applications.
See Cash Flow Hedges in Note 10 for information related to collateral provided to us by
counterparties.
Pinnacle West Energy
See Note 17 of Notes to Condensed Consolidated Financial Statements above for a discussion of
the sale of our 75% ownership interest in Silverhawk.
Other Subsidiaries
During the past three years, SunCor funded its cash requirements with cash from operations and
its own external financings. SunCors 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 during the three months ended March 31, 2006 and projected
capital expenditures for the next three years. SunCor expects to fund its future capital
requirements with cash from operations and external financings.
El Dorado expects minimal capital requirements over the next three years and intends to focus
on prudently realizing the value of its existing investments.
APS Energy Services expects minimal capital expenditures over the next three years.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses and related disclosures at the date of the financial statements and during the reporting
50
period. Some of those judgments can be subjective and complex, and actual results could
differ from those estimates. Our most critical accounting policies include the impacts of
regulatory accounting, the determination of the appropriate accounting for our pension and other
postretirement benefits and derivatives accounting. There have been no changes to our critical
accounting policies since our 2005 Form 10-K. See Critical Accounting Policies in Item 7 of the
2005 Form 10-K for further details about our critical accounting policies.
PINNACLE WEST CONSOLIDATED FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Fuel and Purchased Power Costs
General Electric operating revenues are derived from sales of electricity in regulated retail
markets in Arizona and from competitive retail and wholesale power markets in the western United
States. These revenues are affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer as well as electricity rates and tariffs and variations in
weather from period to period. Competitive sales of energy and energy-related products and
services are made by APS Energy Services in certain western states that have opened to competition.
Retail Rate Proceedings The key issue affecting Pinnacle Wests and APS financial outlook is
the satisfactory resolution of APS retail rate proceedings pending before the ACC. As discussed
in greater detail in Note 5, APS has pending before the ACC a general retail rate case and an
application for a surcharge under the PSA.
Fuel and Purchased Power Costs Fuel and purchased power costs are impacted by our electricity
sales volumes, existing contracts for purchased power and generation fuel, our power plant
performance, transmission availability or constraints, prevailing market prices, new generating
plants being placed in service, variances in deferrals and amortization of fuel and purchased power
beginning on April 1, 2005 and our hedging program for managing such costs. See Power Supply
Adjustor in Note 5 for information regarding the PSA approved by the ACC. See Natural Gas
Supply in Note 12 for more information on fuel costs. See Deferred Fuel and Purchased Power
Costs for information about Palo Verde Unit 1s current outage to remedy an operating condition,
the units previous reduced power levels resulting from that condition, and the associated economic
impact. APS recovery of PSA deferrals from its ratepayers is subject to the ACCs approval of
annual PSA adjustments and periodic surcharge applications.
Customer and Sales Growth The customer and sales growth referred to in this paragraph applies
to Native Load customers and sales to them. Customer growth in APS service territory averaged
about 3.8% a year for the three years 2003 through 2005; we currently expect customer growth to
average about 3.8% per year from 2006 to 2008. We currently estimate that total retail electricity
sales in kilowatt-hours will grow 3.7% on average, from 2006 through 2008, before the effects of
weather variations. Customer growth for the three-month period ended March 31, 2006 compared with
the prior-year period was 4.5%.
Actual sales growth, excluding weather-related variations, may differ from our projections as
a result of numerous factors, such as economic conditions, customer growth, usage patterns and
responses to retail price changes. Our experience indicates that a reasonable range of variation
in our
51
kilowatt-hour sales projection attributable to such economic factors can result in increases or
decreases in annual net income of up to $10 million.
Weather In forecasting retail sales growth, we assume normal weather patterns based on
historical data. Historical extreme weather variations have resulted in annual variations in net
income in excess of $20 million. However, our experience indicates that the more typical
variations from normal weather can result in increases or decreases in annual net income of up to
$10 million.
Wholesale Power Market Conditions The marketing and trading division focuses primarily on
managing APS risks relating to fuel and purchased power costs in connection with its costs of
serving Native Load customer demand. The marketing and trading division, subject to specified
parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits.
Other Factors Affecting Financial Results
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by
growth, power plant additions and operations, inflation, outages, higher trending pension and other
postretirement benefit costs and other factors.
Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by
net additions to utility plant and other property, which include generation construction,
acquisition, the sale of generation (see discussion of the sale of Silverhawk Note 17), changes
in depreciation and amortization rates (see Note 5), and changes in regulatory asset amortization.
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are
affected by tax rates and the value of property in-service and under construction. The average
property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed
value for 2005 and 2004. We expect property taxes to increase as new power plants, the acquisition
of the Sundance Plant in 2005 and our additions to transmission and distribution facilities are
included in the property tax base.
Interest Expense Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels in the next several
years are expected to be our capital requirements and our internally generated cash flow.
Capitalized interest offsets a portion of interest expense while capital projects are under
construction. We stop accruing capitalized interest on a project when it is placed in commercial
operation.
Retail Competition Although some very limited retail competition existed in Arizona in 1999
and 2000, there are currently no active retail competitors providing unbundled energy or other
utility services to APS customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter APS service territory.
Subsidiaries SunCors net income was $56 million in 2003, $45 million in 2004 and $56 million
in 2005. See Note 17 for further discussion.
APS Energy Services and El Dorados historical results are not indicative of future
performance.
52
General Our financial results may be affected by a number of broad factors. See
Forward-Looking Statements for further information on such factors, which may cause our actual
future results to differ from those we currently seek or anticipate.
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.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest
paid on variable-rate debt and the market value of debt securities
held by our nuclear decommissioning trust fund. The
nuclear decommissioning trust fund also has risk associated with the changing market value of its
investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with
these market fluctuations by utilizing various commodity instruments that qualify as derivatives,
including exchange-traded futures and options and over-the-counter forwards, options and swaps.
Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk
management activities and monitors the results of marketing and trading activities to ensure
compliance with our stated energy risk management and trading policies. As part of our risk
management program, we use such instruments to hedge purchases and sales of electricity, fuels and
emissions allowances and credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodities. In addition, subject to specified risk
parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit
from market price movements.
The mark-to-market value of derivative instruments related to our risk management and trading
activities are presented in two categories consistent with our business segments:
|
|
|
Regulated Electricity non-trading derivative instruments that hedge our purchases
and sales of electricity and fuel for APS Native Load requirements of our regulated
electricity business segment; and |
|
|
|
|
Marketing and Trading non-trading and trading derivative instruments of our
competitive business segment. |
The following tables show the pretax changes in mark-to-market of our non-trading and trading
derivative positions for the three months ended March 31, 2006 and 2005 (dollars in millions):
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
March 31, 2006 |
|
|
March 31, 2005 |
|
|
|
Regulated |
|
|
Marketing |
|
|
Regulated |
|
|
Marketing |
|
|
|
Electricity |
|
|
and Trading |
|
|
Electricity |
|
|
and Trading |
|
Mark-to-market of net positions
at beginning of period |
|
$ |
335 |
|
|
$ |
181 |
|
|
$ |
33 |
|
|
$ |
107 |
|
Recognized in earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in mark-to-market
for future period
deliveries gains (losses) |
|
|
(5 |
) |
|
|
|
|
|
|
13 |
|
|
|
14 |
|
Mark-to-market
gains realized
including ineffectiveness
during the period |
|
|
(4 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(8 |
) |
Deferred as a regulatory asset |
|
|
(49 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Recognized in OCI: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in mark-to-market
for future period
deliveries gains (losses) (a) |
|
|
(163 |
) |
|
|
(42 |
) |
|
|
108 |
|
|
|
52 |
|
Mark-to-market
gains realized
during the period |
|
|
(10 |
) |
|
|
(7 |
) |
|
|
(1 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market of net positions
at end of period |
|
$ |
104 |
|
|
$ |
131 |
|
|
$ |
153 |
|
|
$ |
160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The increases (decreases) in regulated mark-to-market
recorded in OCI are due
primarily to increases (decreases) in forward natural gas prices. |
The tables below show the fair value of maturities of our non-trading and trading derivative
contracts (dollars in millions) at March 31, 2006 by maturities and by the type of valuation that
is performed to calculate the fair values. See Note 1, Derivative Accounting, in Item 8 of our
2005 Form 10-K for more discussion of our valuation methods.
Regulated Electricity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years |
|
|
fair |
|
Source of Fair Value |
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
thereafter |
|
|
value |
|
Prices actively quoted |
|
$ |
19 |
|
|
$ |
83 |
|
|
$ |
32 |
|
|
$ |
2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
136 |
|
Prices provided by
other external sources |
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
5 |
|
Prices based on models
and other valuation
methods |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
(4 |
) |
|
|
(1 |
) |
|
|
(3 |
) |
|
|
(23 |
) |
|
|
(37 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total by maturity |
|
$ |
16 |
|
|
$ |
86 |
|
|
$ |
28 |
|
|
$ |
|
|
|
$ |
(3 |
) |
|
$ |
(23 |
) |
|
$ |
104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
Marketing and Trading
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
fair |
|
Source of Fair Value |
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
value |
|
Prices actively quoted |
|
$ |
52 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
52 |
|
Prices provided by
other external sources |
|
|
|
|
|
|
70 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
89 |
|
Prices based on models
and other valuation
methods |
|
|
(21 |
) |
|
|
(3 |
) |
|
|
16 |
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total by maturity |
|
$ |
31 |
|
|
$ |
67 |
|
|
$ |
35 |
|
|
$ |
(1 |
) |
|
$ |
(1 |
) |
|
$ |
131 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Pinnacle Wests
Condensed Consolidated Balance Sheets at March 31, 2006 and December 31, 2005 (dollars in
millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2006 |
|
|
December 31, 2005 |
|
|
|
Gain (Loss) |
|
|
Gain (Loss) |
|
|
|
Price Up |
|
|
Price Down |
|
|
Price Up |
|
|
Price Down |
|
Commodity |
|
10% |
|
|
10% |
|
|
10% |
|
|
10% |
|
Mark-to-market changes
reported in earnings (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity |
|
$ |
(1 |
) |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
|
|
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market changes
reported in OCI (b): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity |
|
|
54 |
|
|
|
(54 |
) |
|
|
66 |
|
|
|
(66 |
) |
Natural gas |
|
|
90 |
|
|
|
(90 |
) |
|
|
103 |
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
143 |
|
|
$ |
(143 |
) |
|
$ |
169 |
|
|
$ |
(169 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
These contracts are primarily structured sales activities hedged with a
portfolio of forward purchases that protects the economic value of the sales
transactions. |
|
(b) |
|
These contracts are hedges of our forecasted purchases of natural gas and
electricity. The impact of these hypothetical price movements would substantially
offset the impact that these same price movements would have on the physical exposures
being hedged. |
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. We
have risk management and trading contracts with many counterparties, including one counterparty for
which a worst case exposure represents approximately 10% of Pinnacle Wests $887 million of risk
management and trading assets as of March 31, 2006. See Note 1, Derivative
55
Accounting in Item 8 of our 2005 Form 10-K for a discussion of our credit valuation
adjustment policy. See Note 10 for further discussion of credit risk.
ARIZONA PUBLIC SERVICE COMPANY RESULTS OF OPERATIONS
General
Throughout the following explanations of our results of operations, we refer to gross
margin. Gross margin refers to electric operating revenues less fuel and purchased power costs.
Gross margin is a non-GAAP financial measure, as defined in accordance with SEC rules. Exhibit
99.2 reconciles this non-GAAP financial measure to operating income, which is the most directly
comparable financial measure calculated and presented in accordance with GAAP. We view gross
margin as an important performance measure of the core profitability of our operations. This
measure is a key component of our internal financial reporting and is used by our management in
analyzing our business. We believe that investors benefit from having access to the same financial
measures that our management uses. In addition, we have reclassified certain prior-period amounts
to conform to our current-period presentation.
Deferred Fuel and Purchased Power Costs
APS retail rate settlement became effective April 1, 2005. As part of the settlement, the
ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel
and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers
for future rate recovery 90% of the difference between actual retail fuel and purchased power costs
and the amount of such costs currently included in base rates. APS recovery of PSA deferrals from
its customers is subject to the ACCs approval of annual PSA adjustments and periodic surcharge
applications.
The balance of APS pretax deferred fuel and purchased power regulatory asset (PSA
deferrals) at March 31, 2006 was $169 million. Based on the ACCs approval of the May 1, 2006
interim adjustor and $15 million PSA surcharge (see Interim Rate Increase and
Application for PSA Surcharges in Note 5), APS estimates that its pretax PSA deferral balance at
December 31, 2006 will be approximately $160 million to $180 million assuming no additional interim
rate relief and based on APS hedged positions for fuel and purchased power at March 31, 2006;
recent forward market prices for natural gas and purchased power (which are subject to change);
strong performance from APS fossil-fueled generating units during the three months ended
March 31, 2006; and the operating performance at Palo Verde Unit 1 discussed below.
The PSA deferral balances at March 31, 2006 and estimated at December 31, 2006 each include
$45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages.
APS has requested the recovery of these deferrals through a PSA surcharge upon the ACCs completion
of an inquiry regarding the outages.
APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18,
2006 due to vibration levels in one of the Units shutdown cooling lines. APS began a planned
outage of Unit 1 on March 18, 2006 and, based on early inspections and testing during that outage,
determined to perform the necessary work and modifications to remedy the situation prior to
returning the Unit to service. APS believes that performing the work during the current Unit 1
outage will provide greater assurance that Unit 1 will be operating during the peak summer months
56
and somewhat
accelerate returning the Unit to full power (which is currently expected in the June
timeframe). APS estimates that pretax incremental replacement
power costs resulting from Unit 1s current outage and
reduced power levels were approximately $36 million during the
three months ended March 31, 2006 and that such costs will be
approximately $47 million in the second quarter of 2006. The
related PSA deferrals were approximately $32 million in the three months ended March 31, 2006 and
are estimated to be approximately $42 million in the second
quarter of 2006. The Palo Verde replacement power costs were
partially offset by $17 million of lower replacement power costs
related to strong performance from APS fossil-fueled
generating units during the three months ended March 31, 2006.
As a result, the corresponding deferrals were reduced in the quarter
by $15 million. As noted under
Interim Rate Increase under Note 5, the ACC has directed
the ACC staff to undertake a
prudence audit of all unplanned 2006 Palo Verde outage costs.
See Note 5 for further information regarding the PSA and APS pending PSA surcharge
application.
Operating Results Three-month period ended March 31, 2006 compared with three-month period ended
March 31, 2005
APS
had a net loss of $6 million for the three-month period ended March 31, 2006 compared with
net income of $27 million for the comparable prior-year period. The $33 million decrease was
primarily due to higher fuel and purchased power costs (as discussed
above) and higher prices, and higher operations and maintenance expense related to generation (including
the PWEC Dedicated Assets APS acquired on July 29, 2005) and customer service costs. These
negative factors were partially offset by deferred fuel and purchased power costs; higher mark-to-market gains on contracts for future
delivery; higher retail sales volumes due to customer
growth; and a retail price increase effective April 1, 2005.
Additional details on the major factors that increased (decreased) net income are contained in
the following table (dollars in millions):
57
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Pretax |
|
|
After Tax |
|
Gross margin: |
|
|
|
|
|
|
|
|
Higher fuel and purchased power costs |
|
$ |
(53 |
) |
|
$ |
(32 |
) |
Deferred fuel and purchased power costs (fuel
deferrals began April 1, 2005) |
|
|
13 |
|
|
|
8 |
|
Higher mark-to-market gains on contracts for future delivery
due to changes in forward prices |
|
|
14 |
|
|
|
9 |
|
Higher retail sales volumes due to customer growth,
excluding weather effects |
|
|
13 |
|
|
|
8 |
|
Retail price increase effective April 1, 2005 |
|
|
7 |
|
|
|
4 |
|
Effects of weather on retail sales |
|
|
(3 |
) |
|
|
(2 |
) |
Miscellaneous items, net |
|
|
(5 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
Net decrease in gross margin |
|
|
(14 |
) |
|
|
(8 |
) |
Operations and maintenance increases primarily due to: |
|
|
|
|
|
|
|
|
Generation costs, including maintenance and overhauls |
|
|
(16 |
) |
|
|
(10 |
) |
Costs of PWEC Dedicated Assets not included in prior year period |
|
|
(8 |
) |
|
|
(5 |
) |
Customer service costs, including regulatory demand-side
management programs and planned maintenance |
|
|
(5 |
) |
|
|
(3 |
) |
Miscellaneous items, net |
|
|
(2 |
) |
|
|
(1 |
) |
Depreciation and amortization increases primarily due to
increased depreciable assets, partially offset by lower depreciation
rates |
|
|
(4 |
) |
|
|
(2 |
) |
Higher property taxes due to increased plant in service |
|
|
(4 |
) |
|
|
(2 |
) |
Miscellaneous items, net |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
Net decrease in net income |
|
$ |
(53 |
) |
|
$ |
(33 |
) |
|
|
|
|
|
|
|
Regulated Electricity Revenues
Regulated electricity revenues were $49 million higher for the three months ended March 31,
2006 compared with the prior-year period primarily as a result of:
|
|
|
a $19 million increase in retail revenues related to customer growth,
excluding weather effects; |
|
|
|
|
an $18 million increase in revenues related to the implementation of the
February 1, 2006 PSA adjustor which has no earnings effect due
to the offset from amortization of deferred fuel in fuel and purchased power expense; |
|
|
|
|
a $12 million increase in Off-System Sales primarily resulting from
sales previously reported in marketing and trading that were classified beginning in
April 2005 as sales in regulated electricity in accordance with the APS retail rate
case settlement; |
|
|
|
|
a $7 million increase in retail revenues due to a price increase
effective April 1, 2005; |
|
|
|
|
a $4 million decrease in retail revenues related to weather; and |
|
|
|
|
a $3 million decrease due to miscellaneous factors. |
58
Marketing and Trading Revenues
Marketing and trading revenues were $13 million lower for the three months ended March 31,
2006 compared with the prior-year period primarily as a result of:
|
|
|
a $15 million decrease in energy trading revenues on realized sales of
electricity primarily due to lower delivered electricity prices and lower volumes; |
|
|
|
|
a $14 million increase in mark-to-market gains on contracts for future
delivery due to changes in forward prices; and |
|
|
|
|
a $12 million decrease in Off-System Sales due to the absence of sales
previously reported in marketing and trading that were classified beginning in April
2005 as sales in regulated electricity in accordance with the APS retail rate case
settlement. |
ARIZONA PUBLIC SERVICE COMPANY LIQUIDITY AND CAPITAL RESOURCES
Contractual Obligations
APS future contractual obligations have not changed materially from the amounts disclosed in
Part II, Item 7 of the 2005 Form 10-K with the exception of our aggregate:
|
|
|
fuel and purchased power commitments, which increased from approximately $1.7
billion at December 31, 2005 to $2.9 billion at March 31, 2006 as follows (in
billions): |
|
|
|
|
|
|
|
|
|
2006 |
|
2007-2008 |
|
2009-2010 |
|
Thereafter |
|
Total |
$0.3
|
|
$0.5
|
|
$0.4
|
|
$1.7
|
|
$2.9 |
See Note 4 for a list of APS payments due on total long-term debt and capitalized lease
requirements.
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current expectations, and neither
Pinnacle West nor APS assumes any obligation to update these statements or make any further
statements on any of these issues, except as required by applicable law. These forward-looking
statements are often identified by words such as estimate, predict, hope, may, believe,
anticipate, plan, expect, require, intend, assume and similar words. 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 Pinnacle West or
APS. In addition to the Risk Factors described in Item 1A of the 2005 Form 10-K, these factors
include, but are not limited to:
|
|
|
state and federal regulatory and legislative decisions and actions, including the
outcome and timing of APS retail rate proceedings pending before the ACC; |
|
|
|
|
the timely recovery of PSA deferrals; |
59
|
|
|
the ongoing restructuring of the electric industry, including the introduction of
retail electric competition in Arizona and decisions impacting wholesale competition; |
|
|
|
|
the outcome of regulatory, legislative and judicial proceedings, both current and
future, relating to the restructuring; |
|
|
|
|
market prices for electricity and natural gas; |
|
|
|
|
power plant performance and outages; |
|
|
|
|
transmission outages and constraints; |
|
|
|
|
weather variations affecting local and regional customer energy usage; |
|
|
|
|
customer growth and energy usage; |
|
|
|
|
regional economic and market conditions, including the results of litigation and
other proceedings resulting from the California energy situation, volatile fuel and
purchased power costs and the completion of generation and transmission construction in
the region, which could affect customer growth and the cost of power supplies; |
|
|
|
|
the cost of debt and equity capital and access to capital markets; |
|
|
|
|
current credit ratings remaining in effect for any given period of time; |
|
|
|
|
our ability to compete successfully outside traditional regulated markets (including
the wholesale market); |
|
|
|
|
the performance of our marketing and trading activities due to volatile market
liquidity and any deteriorating counterparty credit and the use of derivative contracts
in our business (including the interpretation of the subjective and complex accounting
rules related to these contracts); |
|
|
|
|
changes in accounting principles generally accepted in the United States of America
and the interpretation of those principles; |
|
|
|
|
the performance of the stock market and the changing interest rate environment,
which affect the amount of required contributions to Pinnacle Wests pension plan and
APS nuclear decommissioning trust funds, as well as the reported costs of providing
pension and other postretirement benefits; |
|
|
|
|
technological developments in the electric industry; |
|
|
|
|
the strength of the real estate market in SunCors market areas, which include
Arizona, Idaho, New Mexico and Utah; and |
|
|
|
|
other uncertainties, all of which are difficult to predict and many of which are
beyond the control of Pinnacle West and APS. |
60
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Pinnacle West Consolidated Factors Affecting Our Financial Outlook in Item 2 above for
a discussion of quantitative and qualitative disclosures about market risks.
Item 4. CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures
The term disclosure controls and procedures means controls and other procedures of a company
that are designed to ensure that information required to be disclosed by a company in the reports
that it files or submits under the Securities Exchange Act of 1934 (the Exchange Act) (15 U.S.C.
78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in
the SECs rules and forms. Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information required to be disclosed by a company
in the reports that it files or submits under the Exchange Act is accumulated and communicated to a
companys management, including its principal executive and principal financial officers, or
persons performing similar functions, as appropriate to allow timely decisions regarding required
disclosure.
Pinnacle Wests management, with the participation of Pinnacle Wests Chief Executive Officer
and Chief Financial Officer, have evaluated the effectiveness of Pinnacle Wests disclosure
controls and procedures as of March 31, 2006. Based on that evaluation, Pinnacle Wests Chief
Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle Wests
disclosure controls and procedures were effective.
APS management, with the participation of APS Chief Executive Officer and Chief Financial
Officer, have evaluated the effectiveness of APS disclosure controls and procedures as of March
31, 2006. Based on that evaluation, APS Chief Executive Officer and Chief Financial Officer have
concluded that, as of that date, APS disclosure controls and procedures were effective.
(b) Changes In Internal Control Over Financial Reporting
The term internal control over financial reporting (defined in SEC Rule 13a-15(f)) refers to
the process of a company that is designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in
accordance with GAAP.
No change in Pinnacle Wests or APS internal control over financial reporting occurred during
the fiscal quarter ended March 31, 2006 that materially affected, or is reasonably likely to
materially affect, Pinnacle Wests or APS internal control over financial reporting.
61
Part II OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
See Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this
report in regard to pending or threatened litigation or other disputes.
Item 1A. RISK FACTORS
In addition to the other information set forth in this
report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors in
the 2005 Form 10-K, which could materially affect the business, financial condition or future
results of APS and Pinnacle West. The risks described in the 2005 Form 10-K are not the only risks
facing APS and Pinnacle West. Additional risks and uncertainties not currently known to us or that
we currently deem to be immaterial also may materially adversely affect the business, financial
condition and/or operating results of APS and Pinnacle West.
Item 5. OTHER INFORMATION
Construction and Financing Programs
See Liquidity and Capital Resources in Part I, Item 2 of this report for a discussion of
construction and financing programs of the Company and its subsidiaries.
Regulatory Matters
See Note 5 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this
report for a discussion of regulatory developments.
Environmental Matters
See Environmental Matters Superfund in Note 12 of Notes to Condensed Consolidated
Financial Statements in Part I, Item 1 of this report for a discussion of a Superfund site.
Navajo Nation Environmental Issues
On May 18,
2005, APS, Salt River Project and the Navajo Nation executed a Voluntary Compliance
Agreement (VCA) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention
and Control Act. See Navajo Nation Environmental Issues in Part I, Item 1 of the 2005 Form 10-K.
On March 21, 2006, the EPA determined that the Navajo Nation was eligible for treatment as a
state for the purpose of entering into a supplemental delegation agreement with the EPA to
administer the Clean Air Act Title V, Part 71 federal permit program over Four Corners. The EPA
entered into the supplemental delegation agreement with the Navajo Nation on the same day. Because
the EPAs approval was consistent with the requirements of the
VCA, APS sought dismissal
of the pending litigation in the Navajo Nation Supreme Court and the pending litigation in the
Navajo Nation District Court to the extent the claims relate to the
Clean Air Act, and the Courts have dismissed the claims accordingly. The agreement
does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently
predict the outcome of this matter.
62
Item 6. EXHIBITS
(a) Exhibits
|
|
|
|
|
Exhibit No. |
|
Registrant(s) |
|
Description |
12.1
|
|
Pinnacle West
|
|
Ratio of Earnings to Fixed Charges |
|
|
|
|
|
12.2
|
|
APS
|
|
Ratio of Earnings to Fixed Charges |
|
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|
|
|
12.3
|
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Pinnacle West
|
|
Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividend Requirements |
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31.1
|
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Pinnacle West
|
|
Certificate of William J. Post, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
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|
|
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31.2
|
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Pinnacle West
|
|
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
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|
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31.3
|
|
APS
|
|
Certificate of Jack E. Davis, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
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|
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31.4
|
|
APS
|
|
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
|
|
|
|
|
32.1
|
|
Pinnacle West
|
|
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002 |
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|
|
|
|
32.2
|
|
APS
|
|
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002 |
|
|
|
|
|
99.1
|
|
Pinnacle West
|
|
Reconciliation of Operating Income to Gross
Margin |
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|
|
|
|
99.2
|
|
APS
|
|
Reconciliation of Operating Income to Gross
Margin |
63
In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act
Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
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|
|
Exhibit |
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|
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|
|
|
Date |
No. |
|
Registrant(s) |
|
Description |
|
Previously Filed as Exhibita |
|
Effective |
3.1
|
|
Pinnacle West
|
|
Articles of
Incorporation,
restated as of July
29, 1988
|
|
19.1 to Pinnacle Wests September 1988
Form 10-Q Report, File No. 1-8962
|
|
11-14-88 |
|
|
|
|
|
|
|
|
|
3.2
|
|
Pinnacle West
|
|
Pinnacle West
Capital Corporation
Bylaws, amended as
of December 14, 2005
|
|
3.1 to Pinnacle West/APS
December 9, 2005 Form 8-K Report,
File Nos. 1-8962 and 1-4473
|
|
12-15-05 |
|
|
|
|
|
|
|
|
|
3.3
|
|
APS
|
|
Articles of
Incorporation,
restated as of May
25, 1988
|
|
4.2 to APS Form S-3 Registration Nos.
33-33910 and 33-55248 by means of
September 24, 1993 Form 8-K Report,
File No. 1-4473
|
|
9-29-93 |
|
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|
|
|
|
|
|
|
3.4
|
|
APS
|
|
Arizona Public
Service Company
Bylaws, amended as
of June 23, 2004
|
|
3.1 to APS June 30, 2004 Form 10-Q
Report, File No. 1-4473
|
|
8-9-04 |
a Reports filed under File Nos. 1-4473
and 1-8962 were filed in the office of the Securities and Exchange Commission
located in Washington, D.C.
64
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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|
PINNACLE WEST CAPITAL CORPORATION
(Registrant) |
|
|
|
|
|
Dated: May 9, 2006
|
|
By: |
|
/s/ Donald E. Brandt |
|
|
|
|
|
|
|
|
|
Donald E. Brandt |
|
|
|
|
Executive Vice President and Chief |
|
|
|
|
Financial Officer |
|
|
|
|
(Principal Financial Officer |
|
|
|
|
and Officer Duly Authorized to sign this Report) |
|
|
|
|
|
|
|
ARIZONA PUBLIC SERVICE COMPANY
(Registrant) |
|
|
|
|
|
Dated:
May 9, 2006
|
|
By: |
|
/s/ Donald E. Brandt |
|
|
|
|
|
|
|
|
|
Donald E. Brandt |
|
|
|
|
Executive Vice President and Chief |
|
|
|
|
Financial Officer |
|
|
|
|
(Principal Financial Officer and |
|
|
|
|
Officer Duly Authorized to sign this Report) |
65
Index to Exhibits
|
|
|
|
|
Exhibit No. |
|
Registrant(s) |
|
Description |
12.1
|
|
Pinnacle West
|
|
Ratio of Earnings to Fixed Charges |
|
|
|
|
|
12.2
|
|
APS
|
|
Ratio of Earnings to Fixed Charges |
|
|
|
|
|
12.3 |
|
Pinnacle West
|
|
Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividend Requirements |
|
|
|
|
|
31.1
|
|
Pinnacle West
|
|
Certificate of William J. Post, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
|
|
|
|
|
31.2
|
|
Pinnacle West
|
|
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
|
|
|
|
|
31.3
|
|
APS
|
|
Certificate of Jack E. Davis, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
|
|
|
|
|
31.4
|
|
APS
|
|
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended |
|
|
|
|
|
32.1
|
|
Pinnacle West
|
|
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002 |
|
|
|
|
|
32.2
|
|
APS
|
|
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002 |
|
|
|
|
|
99.1
|
|
Pinnacle West
|
|
Reconciliation of Operating Income to Gross
Margin |
|
|
|
|
|
99.2
|
|
APS
|
|
Reconciliation of Operating Income to Gross
Margin |
66