PINNACLE WEST CAPITAL CORP, 10-Q filed on 4/29/2011
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2011
Apr. 25, 2011
Jun. 30, 2010
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
 
Entity Central Index Key
0000764622 
 
 
Document Type
10-Q 
 
 
Document Period End Date
2011-03-31 
 
 
Amendment Flag
FALSE 
 
 
Document Fiscal Year Focus
2011 
 
 
Document Fiscal Period Focus
Q1 
 
 
Current Fiscal Year End Date
12/31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Public Float
 
 
3,935,855,234 
Entity Common Stock, Shares Outstanding
 
109,016,655 
 
Arizona Public Service Company [Member]
 
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE CO 
 
 
Entity Central Index Key
0000007286 
 
 
Document Type
10-Q 
 
 
Document Period End Date
2011-03-31 
 
 
Amendment Flag
FALSE 
 
 
Document Fiscal Year Focus
2011 
 
 
Document Fiscal Period Focus
Q1 
 
 
Current Fiscal Year End Date
12/31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Non-accelerated Filer 
 
 
Entity Public Float
 
 
Entity Common Stock, Shares Outstanding
 
71,264,947 
 
Condensed Consolidated Statements of Income (Unaudited) (USD $)
In Thousands, except Per Share data
3 Months Ended
Mar. 31,
2011
2010
OPERATING REVENUES
 
 
Regulated electricity segment
$ 647,974 
$ 611,425 
Other revenues
11,601 
8,930 
Total
659,575 
620,355 
OPERATING EXPENSES
 
 
Regulated electricity segment fuel and purchased power
212,007 
215,540 
Operations and maintenance
256,486 
207,842 
Depreciation and amortization
106,601 
100,653 
Taxes other than income taxes
37,624 
31,724 
Other expenses
9,716 
6,928 
Total
622,434 
562,687 
OPERATING INCOME
37,141 
57,668 
OTHER INCOME (DEDUCTIONS)
 
 
Allowance for equity funds used during construction
5,395 
5,389 
Other income (Note 11)
1,690 
2,108 
Other expense (Note 11)
(1,699)
(2,696)
Total
5,386 
4,801 
INTEREST EXPENSE
 
 
Interest charges
61,077 
60,705 
Allowance for borrowed funds used during construction
(3,576)
(3,047)
Total
57,501 
57,658 
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(14,974)
4,811 
INCOME TAXES
(5,649)
(7,172)
INCOME (LOSS) FROM CONTINUING OPERATIONS
(9,325)
11,983 
LOSS FROM DISCONTINUED OPERATIONS
 
 
Net of income tax benefit of $222 and $8,389 (Note 14)
(349)
(12,880)
NET LOSS
(9,674)
(897)
Less: Net income attributable to noncontrolling interests (Note 7)
5,461 
5,117 
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS
(15,135)
(6,014)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC
108,832 
101,474 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED
108,832 
101,474 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
Income (loss) from continuing operations attributable to common shareholders - basic
(0.14)
0.07 
Net loss attributable to common shareholders - basic
(0.14)
(0.06)
Income (loss) from continuing operations attributable to common shareholders - diluted
(0.14)
0.07 
Net loss attributable to common shareholders - diluted
(0.14)
(0.06)
DIVIDENDS DECLARED PER SHARE
0.525 
0.525 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
Income (loss) from continuing operations, net of tax
(14,795)
6,855 
Discontinued operations, net of tax
(340)
(12,869)
Net loss attributable to common shareholders
$ (15,135)
$ (6,014)
Condensed Consolidated Statements of Income (Unaudited) (Parenthetical) (USD $)
In Thousands
3 Months Ended
Mar. 31,
2011
2010
LOSS FROM DISCONTINUED OPERATIONS
 
 
Income tax benefit on discontinued operations
$ 222 
$ 8,389 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Thousands
3 Months Ended
Mar. 31, 2011
Year Ended
Dec. 31, 2010
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 114,193 
$ 110,188 
Customer and other receivables
309,854 
324,207 
Accrued unbilled revenues
93,659 
103,292 
Allowance for doubtful accounts
(7,691)
(7,981)
Materials and supplies (at average cost)
161,063 
181,414 
Fossil fuel (at average cost)
20,505 
21,575 
Deferred income taxes
124,244 
124,897 
Income tax receivable (Note 6)
2,483 
Assets from risk management activities (Note 8)
54,579 
73,788 
Regulatory assets (Note 3)
55,743 
62,286 
Other current assets
31,868 
28,362 
Total current assets
958,017 
1,024,511 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 8)
38,520 
39,032 
Nuclear decommissioning trust (Note 15)
486,737 
469,886 
Other assets
64,429 
116,216 
Total investments and other assets
589,686 
625,134 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
13,270,775 
13,201,960 
Accumulated depreciation and amortization
(4,580,344)
(4,514,204)
Net
8,690,431 
8,687,756 
Construction work in progress
441,683 
459,361 
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)
135,766 
137,956 
Intangible assets, net of accumulated amortization
182,855 
184,952 
Nuclear fuel, net of accumulated amortization
129,554 
108,794 
Total property, plant and equipment
9,580,289 
9,578,819 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
979,854 
986,370 
Income tax receivable (Note 6)
67,738 
65,103 
Other
127,306 
113,061 
Total deferred debits
1,174,898 
1,164,534 
TOTAL ASSETS
12,302,890 
12,392,998 
CURRENT LIABILITIES
 
 
Accounts payable
215,968 
236,354 
Accrued taxes (Note 6)
155,172 
104,711 
Accrued interest
54,948 
54,831 
Short-term borrowings
17,300 
16,600 
Current maturities of long-term debt (Note 2)
832,275 
631,879 
Customer deposits
68,821 
68,322 
Liabilities from risk management activities (Note 8)
71,047 
58,976 
Deferred fuel and purchased power regulatory liability (Note 3)
77,151 
58,442 
Other regulatory liabilities (Note 3)
78,167 
80,526 
Other current liabilities
103,363 
139,063 
Total current liabilities
1,674,212 
1,449,704 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
 
 
Long-term debt less current maturities
2,748,676 
2,948,991 
Palo Verde sale leaseback lessor notes less current maturities (Note 7)
96,803 
96,803 
Total long-term debt less current maturities
2,845,479 
3,045,794 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
1,775,368 
1,863,861 
Regulatory liabilities (Note 3)
689,942 
614,063 
Liability for asset retirements (Note 16)
244,483 
328,571 
Liabilities for pension and other postretirement benefits (Note 4)
824,502 
813,121 
Liabilities from risk management activities (Note 8)
56,517 
65,390 
Customer advances
118,778 
121,645 
Coal mine reclamation
117,455 
117,243 
Unrecognized tax benefits (Note 6)
82,613 
66,349 
Other
144,770 
132,031 
Total deferred credits and other
4,054,428 
4,122,274 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
 
 
EQUITY (Note 9)
 
 
Common stock, no par value
2,434,784 
2,421,372 
Treasury stock
(5,768)
(2,239)
Total common stock
2,429,016 
2,419,133 
Retained earnings
1,351,716 
1,423,961 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(58,554)
(59,420)
Derivative instruments
(90,767)
(100,347)
Total accumulated other comprehensive loss
(149,321)
(159,767)
Total shareholders' equity
3,631,411 
3,683,327 
Noncontrolling interests (Note 7)
97,360 
91,899 
Total equity
3,728,771 
3,775,226 
TOTAL LIABILITIES AND EQUITY
$ 12,302,890 
$ 12,392,998 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Thousands
3 Months Ended
Mar. 31,
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET LOSS
$ (9,674)
$ (897)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
123,298 
114,122 
Deferred fuel and purchased power
49,947 
44,040 
Deferred fuel and purchased power amortization
(31,238)
(25,953)
Allowance for equity funds used during construction
(5,395)
(5,389)
Real estate impairment charges
15,112 
Deferred income taxes
(41,005)
50,845 
Change in mark-to-market valuations
(284)
1,842 
Changes in current assets and liabilities:
 
 
Customer and other receivables
75,528 
60,244 
Accrued unbilled revenues
9,633 
24,505 
Materials, supplies and fossil fuel
21,421 
6,240 
Other current assets
(636)
(8,148)
Accounts payable
(24,543)
(23,334)
Accrued taxes and income tax receivable-net
52,944 
30,004 
Other current liabilities
(37,406)
(39,572)
Expenditures for real estate investments
(40)
(443)
Gains and other changes in real estate assets
(3)
4,095 
Change in margin and collateral accounts - assets
4,220 
(11,280)
Change in margin and collateral accounts - liabilities
35,478 
(124,495)
Change in unrecognized tax benefits
18,959 
(62,062)
Change in other long-term assets
(33,129)
(26,593)
Change in other long-term liabilities
35,421 
(36,558)
Net cash flow provided by (used for) operating activities
243,496 
(13,675)
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(191,553)
(202,554)
Contributions in aid of construction
9,136 
2,949 
Allowance for borrowed funds used during construction
(3,576)
(3,080)
Proceeds from nuclear decommissioning trust sales
189,318 
158,448 
Investment in nuclear decommissioning trust
(194,241)
(164,552)
Other
(1,879)
(1,639)
Net cash flow used for investing activities
(192,795)
(210,428)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
175,000 
Repayment of long-term debt
(175,170)
(4,150)
Short-term borrowings and payments - net
700 
135,901 
Dividends paid on common stock
(55,300)
(51,421)
Common stock equity issuance
11,727 
844 
Other
(3,653)
1,079 
Net cash flow provided by (used for) financing activities
(46,696)
82,253 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
4,005 
(141,850)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
110,188 
145,378 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
114,193 
3,528 
Cash paid during the period for:
 
 
Income taxes, net of (refunds)
(5,547)
Interest, net of amounts capitalized
$ 55,997 
$ 58,679 
Consolidation and Nature of Operations
Consolidation and Nature of Operations
1. Consolidation and Nature of Operations
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor Development Company (“SunCor”), APS Energy Services Company, Inc. (“APSES”), and El Dorado Investment Company (“El Dorado”). Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde sale leaseback variable interest entities (“VIEs”) (see Note 7 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“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.
Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.
In preparing the condensed consolidated financial statements, we have evaluated the events that have occurred after March 31, 2011 through the date the financial statements were issued.
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These condensed consolidated financial statements and notes have been prepared consistently with the 2010 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income, Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 14), and the impacts related to the reclassification of regulatory assets and liabilities for the current portion (see Note 3).
The following tables show the impact of the reclassifications to prior year (previously reported) amounts (dollars in thousands):
                         
                    Amount  
                    reported after  
    As     Reclassifications     reclassification  
Statement of Income for the Three   previously     for discontinued     for discontinued  
Months Ended March 31, 2010   reported     operations     operations  
Operating Revenues
                       
Real estate segment
  $ 9,416     $ (9,416 )   $  
Other revenues
    12,750       (3,820 )     8,930  
Operating Expenses
                       
Real estate segment operations
    13,890       (13,890 )      
Real estate impairment charge
    15,112       (15,112 )      
Operations and maintenance
    209,991       (2,149 )     207,842  
Depreciation and amortization
    101,536       (883 )     100,653  
Taxes other than income taxes
    31,827       (103 )     31,724  
Other expenses
    8,061       (1,133 )     6,928  
Other
                       
Other income
    2,395       (287 )     2,108  
Interest Expense
                       
Interest charges
    62,054       (1,349 )     60,705  
Allowance for borrowed funds used during construction
    (3,080 )     33       (3,047 )
Income Taxes
    (15,480 )     8,308       (7,172 )
Income (Loss) From Continuing Operations
    (772 )     12,755       11,983  
Loss From Discontinued Operations
    (125 )     (12,755 )     (12,880 )
                         
                    Amount  
                    reported after  
            Reclassifications     reclassification  
    As     for regulatory     for regulatory  
    previously     assets and     assets and  
Balance Sheets — December 31, 2010   reported     liabilities     liabilities  
Current Assets — Regulatory assets
  $     $ 62,286     $ 62,286  
Current Assets — Deferred income taxes
    94,602       30,295       124,897  
Deferred Debits — Regulatory assets
    1,048,656       (62,286 )     986,370  
Current Liabilities — Deferred fuel and purchased power regulatory liability
          58,442       58,442  
Current Liabilities — Other regulatory liabilities
          80,526       80,526  
Deferred Credits and Other — Deferred income taxes
    1,833,566       30,295       1,863,861  
Deferred Credits and Other — Deferred fuel and purchased power regulatory liability
    58,442       (58,442 )      
Deferred Credits and Other — Regulatory liabilities
    694,589       (80,526 )     614,063  
                         
                    Amount  
                    reported after  
            Reclassifications     reclassification  
    As     for regulatory     for regulatory  
Statement of Cash Flows for the   previously     assets and     assets and  
Three Months Ended March 31, 2010   reported     liabilities     liabilities  
Cash Flows from Operating Activities
                       
Other current assets
  $ (8,836 )   $ 688     $ (8,148 )
Other current liabilities
    (36,582 )     (2,990 )     (39,572 )
Change in other long-term assets
    (25,903 )     (690 )     (26,593 )
Change in other long-term liabilities
    (39,550 )     2,992       (36,558 )
Long-term Debt and Liquidity Matters
Long-term Debt and Liquidity Matters
2. Long-term Debt and Liquidity Matters
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt and capitalized lease requirements as of March 31, 2011 (dollars in millions):
                 
    Consolidated     Consolidated  
Year   Pinnacle West     APS  
2011
  $ 457     $ 457  
2012
    477       477  
2013
    140       140  
2014
    502       502  
2015
    488       313  
Thereafter
    1,620       1,620  
 
           
Total
  $ 3,684     $ 3,509  
 
           
Credit Facilities and Debt Issuances
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs. During the first quarter of 2011, APS refinanced an existing revolving credit facility (as discussed below) that would have otherwise matured in September 2011.
Pinnacle West
On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings, or if unavailable, its long-term issuer ratings.
At March 31, 2011, Pinnacle West’s $200 million credit facility, which matures in 2013, was available for general corporate purposes, support of its $200 million commercial paper program, or for issuances of letters of credit. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At March 31, 2011, Pinnacle West had no outstanding borrowings under this credit facility, no outstanding letters of credit and commercial paper borrowings of $17 million.
APS
On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, with a new $500 million facility. The new revolving credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.
At March 31, 2011, APS had two credit facilities totaling $1 billion, including the $500 million credit facility described above and a $500 million facility that matures in February 2013. These facilities are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. See Note 12 for discussion of APS’s letters of credit. At March 31, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was outstanding under APS’s 2011 $500 million credit facility described above.
Debt Provisions
An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At March 31, 2011, APS was in compliance with the common equity ratio requirements established by the ACC. Its total shareholder equity was approximately $3.8 billion, and total capitalization was approximately $7.1 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
Regulatory Matters
Regulatory Matters
3. Regulatory Matters
2008 General Retail Rate Case Impacts
On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties to its general retail rate case, which was originally filed in March 2008. The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were effective January 1, 2010. The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:
    Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);
    An authorized return on common equity of 11%;
    A capital structure comprised of 46.2% debt and 53.8% common equity;
    A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;
    Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and
    Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.
The parties also agreed to a rate case filing plan in which APS is prohibited from filing its next two general rate cases until on or after June 1, 2011 and June 1, 2013, respectively, unless certain extraordinary events occur. Subject to the foregoing, APS may not request its next general retail rate increase to be effective prior to July 1, 2012. On February 1, 2011, APS filed a 120-day advanced notice of its intent to file its next rate case on June 1, 2011. The parties agreed to use good faith efforts to process these subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.
Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
Renewable Energy Standard. In 2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (“RES”). Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provided for the acquisition of renewable generation in compliance with requirements through 2014, and requested RES funding of $87 million for 2010, which was later approved by the ACC. APS also sought various other determinations in its plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff, Arizona described below.
On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100 megawatts (“MW”) of APS-owned solar resources through 2014. Through this program, APS plans to invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire through competitive procurement processes. The costs associated with the first 50 MW under this program will be recovered initially through the RES until such time as the costs are recovered in base rates or other mechanisms. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’s next retail rate case.
On April 1, 2010, the ACC approved the Community Power Project, a pilot program in which APS will own, operate and receive energy from approximately 1.5 MW of solar panels on the rooftops of up to 200 residential and business customers located within a certain test area in Flagstaff, Arizona. The capital carrying costs of the program will be recovered through the RES until such time as these costs are recovered in base rates.
On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015 timeframe and requesting 2011 RES funding of $96 million. The 2011 Plan addressed enhancements to the residential distributed energy incentive program based on high customer participation, among other things. On October 13, 2010, APS filed an adjusted RES implementation plan to reflect the following items, among others: 1) increased clarity relating to customer project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) the addition of 10 MW of biomass capacity. On December 10, 2010, the ACC approved the 2011 Plan and associated funding request. In January 2011, the ACC voted to reconsider four aspects of the approved 2011 Plan, including: (a) approval to proceed with a feed-in tariff filing; (b) approval for APS to participate in the ownership of distributed energy facilities in the Schools and Government program; (c) denial of a Rapid Reservation program that allows customers to receive priority in the incentive reservation process in exchange for receipt of a reduced incentive amount; and (d) allocation of the budget among various programs and studies. Hearings were held on January 24, 2011 and January 28, 2011. The ACC amended its original decision that approved the 2011 Plan as follows: the ACC (a) reversed its approval of a feed-in tariff program; (b) restricted APS’s ownership of facilities to only economically challenged, rural schools and only after a school has received a bid from a third-party solar installer; (c) approved the Rapid Reservation program; and (d) maintained the original approved budget with some timing modifications.
Demand-Side Management Adjustor Charge (“DSMAC”). The settlement agreement related to the 2008 retail rate case requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS had estimated a budget in the amount of $50 million for 2010. APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010. A surcharge was added to customer bills in order to recover these estimated amounts for use on certain demand-side management programs. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.
The ACC approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery is to be spread over a three-year period.
On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of $80 million was approved and when added to the amortization of 2009 costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve month period beginning March 1, 2011. These amounts do not include approximately $1 million for an electric vehicle charging station program submitted to the ACC for approval on September 30, 2010.
PSA Mechanism and Balance. The power supply adjustor (“PSA”) provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.
The following table shows the changes in the deferred fuel and purchased power regulatory liability for 2011 and 2010 (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Beginning balance
  $ (58 )   $ (87 )
Deferred fuel and purchased power costs-current period
    (50 )     (44 )
Amounts refunded through revenues
    31       26  
 
           
Ending balance
  $ (77 )   $ (105 )
 
           
The PSA rate for the PSA year beginning February 1, 2011 is ($0.0057) per kWh as compared to ($0.0045) per kWh for the prior year. The regulatory liability at March 31, 2011 reflects lower average prices, primarily for natural gas and gas-based generation. Any uncollected (overcollected) deferrals during the 2011 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2012.
Transmission Rates and Transmission Cost Adjustor. In July 2008, the United States Federal Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the transmission cost adjustor (“TCA”).
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.
Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system will increase by approximately $44.3 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38.2 million of this revenue increase relates to transmission services used for APS’s retail customers. On April 22, 2011, APS filed with the ACC an application for the related increase of its TCA rate.
Regulatory Assets and Liabilities
As discussed in Note 1, as of March 31, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Condensed Consolidated Balance Sheets. This presentation is reflected in the tables below.
The detail of regulatory assets is as follows (dollars in millions):
                                 
    March 31, 2011     December 31, 2010  
    Current     Non-Current     Current     Non-Current  
Pension and other postretirement benefits
  $     $ 663     $     $ 669  
Deferred fuel and purchased power — mark-to-market (Note 8)
    38       38       42       35  
Deferred income taxes
    3       68       3       69  
Transmission vegetation management
          45             46  
Coal reclamation
    2       36       2       36  
Palo Verde VIE (Note 7)
          33             33  
Deferred compensation
          33             32  
Tax expense of Medicare subsidy
    2       22       2       21  
Loss on reacquired debt
    1       20       1       21  
Demand side management (a)
    9       5       12       6  
Other
    1       17             18  
 
                       
Total regulatory assets (b)
  $ 56     $ 980     $ 62     $ 986  
 
                       
     
(a)   See Cost Recovery Mechanisms discussion above.
 
(b)   There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”
Included in the balance of regulatory assets at March 31, 2011 and December 31, 2010 is a regulatory asset for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
The detail of regulatory liabilities is as follows (dollars in millions):
                                 
    March 31, 2011     December 31, 2010  
    Current     Non-Current     Current     Non-Current  
Removal costs (a)
  $ 20     $ 359     $ 22     $ 357  
Asset retirement obligations (Note 16)
          206             184  
Deferred fuel and purchased power (b)(c)
    77             58        
Renewable energy standard (b)
    50             50        
Income taxes — change in rates
          50              
Spent nuclear fuel
    5       41       4       41  
Deferred gains on utility property
    2       16       2       16  
Other
    1       18       3       16  
 
                       
Total regulatory liabilities
  $ 155     $ 690     $ 139     $ 614  
 
                       
     
(a)   In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
 
(b)   See Cost Recovery Mechanisms discussion above.
 
(c)   Subject to a carrying charge.
Retirement Plans and Other Benefits
Retirement Plans and Other Benefits
4. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified 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’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to a regulatory asset) (dollars in millions):
                                 
    Pension Benefits     Other Benefits  
    Three Months Ended     Three Months Ended  
    March 31,     March 31,  
    2011     2010     2011     2010  
Service cost — benefits earned during the period
  $ 16     $ 15     $ 6     $ 5  
Interest cost on benefit obligation
    31       31       12       11  
Expected return on plan assets
    (33 )     (31 )     (10 )     (10 )
Amortization of:
                               
Transition obligation
                      1  
Prior service cost
          1              
Net actuarial loss
    6       6       3       3  
 
                       
Net periodic benefit cost
  $ 20     $ 22     $ 11     $ 10  
 
                       
Portion of cost charged to expense
  $ 8     $ 11     $ 4     $ 5  
 
                       
APS’s share of cost charged to expense
  $ 8     $ 10     $ 4     $ 5  
 
                       
Contributions
The required minimum contribution to our pension plan is zero in 2011 and approximately $85 million in 2012. The contributions to our other postretirement benefit plans for 2011 and 2012 are expected to be approximately $20 million each year. APS and other subsidiaries fund their share of the contributions. APS’s share is approximately 99% of both plans.
Business Segments
Business Segments
5. Business Segments
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution.
Financial data for the three months ended March 31, 2011 and 2010 and at March 31, 2011 and December 31, 2010 is provided as follows (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Operating revenues:
               
Regulated electricity segment
  $ 648     $ 611  
All other (a)
    12       9  
 
           
Total
  $ 660     $ 620  
 
           
 
               
Net income (loss) attributable to common shareholders:
               
Regulated electricity segment
  $ (15 )   $ 7  
All other (b)
          (13 )
 
           
Total
  $ (15 )   $ (6 )
 
           
                 
    As of     As of  
    March 31, 2011     December 31, 2010  
Assets:
               
Regulated electricity segment
  $ 12,237     $ 12,285  
All other (b)
    66       108  
 
           
Total
  $ 12,303     $ 12,393  
 
           
     
(a)   All other activities relate to APSES and El Dorado.
 
(b)   All other activities relate to SunCor, APSES and El Dorado.
Income Taxes
Income Taxes
6. Income Taxes
The $68 million income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. This amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.
On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. In the first quarter of 2011, Pinnacle West increased regulatory liabilities by a total of $53 million, with a corresponding decrease in accumulated deferred income tax liabilities to reflect the impact of this change in tax law.
As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.
Variable-Interest Entities
Variable-Interest Entities
7. Variable-Interest Entities
Palo Verde Sale Leaseback Trusts
In 1986, APS entered into agreements with three separate variable-interest entity (“VIE”) lessor trusts in order to sell and lease back interests in Palo Verde Nuclear Generating Station (“Palo Verde”) Unit 2 and related common facilities. The VIE lessor trusts are single-asset leasing entities. APS will pay approximately $49 million per year for the years 2011 to 2015 related to these leases. The leases do not contain fixed price purchase options or residual value guarantees. However, the lease agreements include fixed rate renewal periods which may have a significant impact on the VIEs’ economic performance. We have concluded that these fixed rate renewal periods may give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. In addition to the fixed rate renewal periods, our primary beneficiary analysis also considered that APS is the operating agent for Palo Verde, is obligated to decommission the leased assets and has fair value purchase options.
For the reasons discussed above, APS consolidates these VIEs. Consolidation of these VIEs eliminates the lease accounting and results in changes in our consolidated assets, debt, equity, and net income. Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease. As a result of consolidation we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2011 of $5 million entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.
Our Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):
                 
    March 31, 2011     December 31, 2010  
Property plant and equipment, net of accumulated depreciation
  $ 136     $ 138  
Long-term debt including current maturities
    126       126  
Equity- Noncontrolling interests
    97       91  
For regulatory ratemaking purposes the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset of $33 million as of March 31, 2011 and December 31, 2010.
APS is exposed to losses relating to these lessor trust VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, 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, 2011, APS would have been required to pay the noncontrolling equity participants approximately $146 million and assume $126 million of debt. Since APS consolidates the VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.
Derivative Accounting
Derivative Accounting
8. Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances, and in interest rates. We manage risks associated with these market fluctuations by utilizing various derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. Derivative instruments that are designated as cash flow hedges are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We may also invest in derivative instruments for trading purposes; however, for the period ended March 31, 2011, there was no material trading activity.
Our derivative instruments are accounted for at fair value; see Note 15 for a discussion of fair value measurements. Derivative instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting. Due to the scope exception, these derivative instruments are excluded from our derivative instrument discussion and disclosures below.
We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Economic hedges not designated as accounting hedges are recorded at fair value on our balance sheet with changes in fair value recognized in the statement of income as incurred. These instruments are included in the “non-designated hedges” discussion and disclosure below.
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of accumulated other comprehensive income (“AOCI”) and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As of March 31, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.
In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but this does not impact our financial condition, net income or cash flows.
For its regulated operations, APS defers for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the portion of APS’s base rates attributable to fuel and purchased power costs (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
As of March 31, 2011, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):
             
Commodity   Quantity
Power
    13,715,268     megawatt hours
Gas
    138,357,611     MMBTU (a)
     
(a)   “MMBTU” is one million British thermal units.
Derivative Instruments in Designated Accounting Hedging Relationships
The following table provides information about gains and losses from derivative instruments in designated accounting hedging relationships and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2011 and 2010 (dollars in thousands):
                     
        Three Months Ended  
    Financial Statement   March 31,  
Commodity Contracts   Location   2011     2010  
 
                   
Amount of Gain (Loss) Recognized in AOCI on Derivative Instruments (Effective Portion)
  Accumulated other comprehensive
loss-derivative instruments
  $ 988     $ (91,667 )
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)
  Regulated electricity segment fuel
and purchased power
    (14,846 )     (13,185 )
Amount of Gain (Loss) Recognized in Income from Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)
  Regulated electricity segment fuel
and purchased power
    12       (10,467 )
     
(a)   During the three months ended March 31, 2011 and 2010, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.
During the next twelve months, we estimate that a net loss of $102 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. Approximately 90% of the amounts related to derivatives subject to the PSA will be recorded as either a regulatory asset or liability and have no effect on earnings.
Derivative Instruments Not Designated as Accounting Hedges
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2011 and 2010 (dollars in thousands):
                     
        Three Months Ended  
    Financial Statement   March 31,  
Commodity Contracts   Location   2011     2010  
 
                   
Amount of Net Gain Recognized in Income from Derivative Instruments
  Regulated electricity segment revenue   $ 1,507     $ 170  
 
                   
Amount of Net Loss Recognized in Income from Derivative Instruments
  Regulated electricity segment fuel
and purchased power expense
    (9,026 )     (34,969 )
 
               
Total
      $ (7,519 )   $ (34,799 )
 
               
Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets
The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the Condensed Consolidated Balance Sheets. These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of March 31, 2011 (dollars in thousands):
                                         
            Investments     Current     Deferred Credits     Total Assets  
Commodity Contracts   Current Assets     and Other Assets     Liabilities     and Other     (Liabilities)  
Derivatives designated as accounting hedging instruments:
                                       
Assets
  $     $ 663     $ 9,583     $ 4,234     $ 14,480  
Liabilities
          (245 )     (98,821 )     (54,802 )     (153,868 )
 
                             
Total hedging instruments
          418       (89,238 )     (50,568 )     (139,388 )
 
                             
 
                                       
Derivatives not designated as accounting hedging instruments:
                                       
Assets
    22,278       38,188       35,863       18,394       114,723  
Liabilities
    (44 )     (86 )     (107,359 )     (90,530 )     (198,019 )
 
                             
Total non-hedging instruments
    22,234       38,102       (71,496 )     (72,136 )     (83,296 )
 
                             
 
                                       
Total derivatives
    22,234       38,520       (160,734 )     (122,704 )     (222,684 )
 
                                       
Margin account
    20,076             359             20,435  
Collateral provided to counterparties
    11,985             101,123       66,187       179,295  
Collateral provided from counterparties
                (11,795 )           (11,795 )
Prepaid option premiums and other
    284                         284  
 
                             
Balance Sheet Total
  $ 54,579     $ 38,520     $ (71,047 )   $ (56,517 )   $ (34,465 )
 
                             
The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis at December 31, 2010 (dollars in thousands):
                                         
            Investments     Current     Deferred Credits     Total Assets  
Commodity Contracts   Current Assets     and Other Assets     Liabilities     and Other     (Liabilities)  
Derivatives designated as accounting hedging instruments:
                                       
Assets
  $ 1,234     $ 142     $ 9,062     $ 4,913     $ 15,351  
Liabilities
    (602 )     (1,933 )     (107,784 )     (71,109 )     (181,428 )
 
                             
Total hedging instruments
    632       (1,791 )     (98,722 )     (66,196 )     (166,077 )
 
                             
 
                                       
Derivatives not designated as accounting hedging instruments:
                                       
Assets
    36,831       40,927       27,322       19,886       124,966  
Liabilities
    (312 )     (33 )     (112,535 )     (85,473 )     (198,353 )
 
                             
Total non-hedging instruments
    36,519       40,894       (85,213 )     (65,587 )     (73,387 )
 
                             
 
                                       
Total derivatives
    37,151       39,103       (183,935 )     (131,783 )     (239,464 )
 
                                       
Margin account
    24,579             997             25,576  
Collateral provided to counterparties
    11,556             125,367       66,393       203,316  
Collateral provided from counterparties
    (1,750 )           (1,250 )           (3,000 )
Prepaid option premiums and other
    2,252       (71 )     (155 )           2,026  
 
                             
Balance Sheet Total
  $ 73,788     $ 39,032     $ (58,976 )   $ (65,390 )   $ (11,546 )
 
                             
Credit Risk and Credit-Related Contingent Features
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 53% of Pinnacle West’s $93 million of risk management assets as of March 31, 2011. This exposure relates to long-term traditional wholesale contracts with counterparties that have very high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, 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 and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on March 31, 2011 was $328 million, for which we had posted collateral of $167 million in the normal course of business.
For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit ratings were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s), which would be a violation of the credit rating provisions. If the investment grade contingent features underlying these agreements had been fully triggered on March 31, 2011, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $122 million of collateral to our counterparties; this amount includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the above footnote. We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $196 million if our debt credit ratings were to fall below investment grade.
Changes in Equity
Changes in Equity
9. Changes in Equity
The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2011 and 2010 (dollars in thousands):
                                                 
    Three Months Ended March 31, 2011     Three Months Ended March 31, 2010  
    Common     Noncontrolling             Common     Noncontrolling        
    Shareholders     Interests     Total     Shareholders     Interests     Total  
 
                                               
Beginning balance, January 1
  $ 3,683,327     $ 91,899     $ 3,775,226     $ 3,316,109     $ 111,895     $ 3,428,004  
 
                                               
Net income (loss)
    (15,135 )     5,461       (9,674 )     (6,014 )     5,117       (897 )
 
                                   
Other comprehensive income (loss):
                                               
Net unrealized gains (losses) on derivative instruments (a)
    988             988       (91,667 )           (91,667 )
Net reclassification of realized losses to income (b)
    14,846             14,846       13,185             13,185  
Reclassification of pension and other postretirement benefits to income
    1,433             1,433       1,393             1,393  
Net income tax benefit (expense) related to items of other comprehensive income (loss)
    (6,821 )           (6,821 )     30,426             30,426  
 
                                   
Total other comprehensive income (loss)
    10,446             10,446       (46,663 )           (46,663 )
 
                                   
Total comprehensive income (loss)
    (4,689 )     5,461       772       (52,677 )     5,117       (47,560 )
 
                                   
 
                                               
Issuance of capital stock
    13,560             13,560       2,680             2,680  
Purchase of treasury stock, net of reissuances
    (3,530 )           (3,530 )     1,078             1,078  
Other (primarily stock compensation)
    (148 )           (148 )     2       (22 )     (20 )
Dividends on common stock
    (57,109 )           (57,109 )     (53,259 )           (53,259 )
Net capital activities by noncontrolling interests
                            (923 )     (923 )
 
                                   
Ending balance, March 31
  $ 3,631,411     $ 97,360     $ 3,728,771     $ 3,213,933     $ 116,067     $ 3,330,000  
 
                                   
     
(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.
Commitments and Contingencies
Commitments and Contingencies
10. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
APS currently estimates it will incur $122 million (in 2011 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2011, APS had a regulatory liability of $46 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
Nuclear Insurance
The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program 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 $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 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 NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $18 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $46 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
Contractual Obligations
Our future contractual purchase obligations have increased from approximately $456 million at December 31, 2010 as disclosed in the 2010 Form 10-K to $699 million at March 31, 2011. This increase is primarily related to an amended agreement for certain transmission rights-of-way and a new contract for the construction of a solar facility. Total contractual purchase obligations are as follows (dollars in millions):
                                                     
2011     2012     2013     2014     2015     Thereafter     Total  
$ 232     $ 116     $ 69     $ 6     $ 6     $ 270     $ 699  
Payments for the transmission rights-of-way are subject to change based on changes in the Consumer Price Index.
FERC Market Issues
On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act (“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 potentially responsible parties (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, the United States Environmental Protection Agency (“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. In addition, on September 23, 2009, APS agreed with the EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $1 million, which is reserved as a liability on our financial statements. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time we cannot accurately estimate our total expenditures.
Other Income and Other Expense
Other Income and Other Expense
11. Other Income and Other Expense
The following table provides detail of other income and other expense for the three months ended March 31, 2011 and 2010 (dollars in thousands):
                 
    Three Months Ended March 31,  
    2011     2010  
Other income:
               
Interest income
  $ 391     $ 874  
Investment gains — net
    1,293       1,222  
Miscellaneous
    6       12  
 
           
Total other income
  $ 1,690     $ 2,108  
 
           
 
               
Other expense:
               
Non-operating costs
  $ (1,444 )   $ (1,794 )
Miscellaneous
    (255 )     (902 )
 
           
Total other expense
  $ (1,699 )   $ (2,696 )
 
           
Guarantees and Surety Bonds
Guarantees and Surety Bonds
12. Guarantees and Surety Bonds
We have issued parental guarantees and obtained surety bonds on behalf of our subsidiaries, including credit support instruments enabling APSES to offer energy-related products and surety bonds at APS, principally related to self-insured workers’ compensation. Non-performance or non-payment under the underlying contract by our subsidiaries would result in a payment liability on our part under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to such instruments. At March 31, 2011, we had no outstanding claims for payment under any of these instruments. Our guarantees and surety bonds have no recourse or collateral provisions to allow us to recover amounts paid under these instruments. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2011 are as follows (dollars in millions):
                                 
    Guarantees     Surety Bonds  
            Term             Term  
    Amount     (in years)     Amount     (in years)  
APSES
  $ 5       1     $ 60       1  
APS
    4       1       9       1  
 
                           
Total
  $ 9             $ 69          
 
                           
APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2011, approximately $44 million of letters of credit were outstanding to support existing pollution control bonds of similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit expire in 2011 and 2013. APS has also entered into approximately $54 million of letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 7 for further details on the Palo Verde sale leaseback transactions). These letters of credit were amended and extended in April 2010, and will expire in 2013.
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, 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.
Earnings Per Share
Earnings Per Share
13. Earnings Per Share
The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2011 and 2010:
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Basic earnings per share:
               
Income (loss) from continuing operations attributable to common shareholders
  $ (0.14 )   $ 0.07  
Loss from discontinued operations
          (0.13 )
 
           
Earnings per share — basic
  $ (0.14 )   $ (0.06 )
 
           
 
               
Diluted earnings per share:
               
Income (loss) from continuing operations attributable to common shareholders
  $ (0.14 )   $ 0.07  
Loss from discontinued operations
          (0.13 )
 
           
Earnings per share — diluted
  $ (0.14 )   $ (0.06 )
 
           
For the three months ended March 31, 2011 and 2010, the weighted average common shares outstanding were the same for both basic and diluted shares. Options to purchase 45,500 shares of common stock for the three-month period ended March 31, 2011, and 387,800 shares for the three-month period ended March 31, 2010 were outstanding but were excluded from the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares.
Discontinued Operations
Discontinued Operations
14. Discontinued Operations
SunCor (real estate segment) In 2009, our real estate subsidiary, SunCor, began disposing of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce its outstanding debt. All activity for the income statement and prior comparative period income statement amounts are included in discontinued operations. In 2010, SunCor recorded real estate impairment charges of $15 million in the first quarter. SunCor’s asset sales resulted in no gain for 2010. SunCor has approximately $3 million of assets on its balance sheet classified as assets held for sale which are included in other current assets at March 31, 2011.
APSES (other) In 2010, our subsidiary, APSES, sold its district cooling business consisting of operations in downtown Phoenix, Tucson, and on certain Arizona State University campuses. As a result of the sale, we recorded an after-tax gain from discontinued operations of approximately $25 million in June 2010. Prior period income statement amounts related to this sale and the associated revenues and costs are reflected in discontinued operations in 2010.
The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2011 and 2010 (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Revenue:
               
SunCor
  $ 1     $ 9  
APSES
          4  
 
           
Total revenue
  $ 1     $ 13  
 
           
 
               
Loss before taxes:
  $ (1 )   $ (21 )
Loss after taxes (a):
  $       (13 )
     
(a)   Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $8 million for the three months ended March 31, 2010.
Fair Value Measurements
Fair Value Measurements
15. Fair Value Measurements
We disclose the fair value of certain assets and liabilities according to a fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:
Level 1 — Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes derivative instruments that are exchange-traded such as futures, cash equivalents invested in exchange-traded money market funds, exchange-traded equities, and nuclear decommissioning trust investments in Treasury securities.
Level 2 — Quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable. This category includes nonexchange-traded contracts such as forwards, options, and swaps. This category also includes investments in common and commingled funds that are redeemable and valued based on the funds’ net asset values.
Level 3 — Model-derived valuations with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where models are required due to the length of the transaction, options, transactions in locations where observable market data does not exist, and common and collective trusts with significant restrictions on our ability to transact in the fund. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We maximize the use of observable inputs and minimize the use of unobservable inputs. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market transactions, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
Recurring Fair Value Measurements
We apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans (see Note 8).
Cash Equivalents
Cash equivalents represent short-term investments in exchange-traded money market funds that are valued using quoted prices in active markets.
Risk Management Activities
Exchange-traded contracts are valued using quoted prices in active markets. For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.
The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.
Some of our derivative instrument transactions are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near term portion and unobservable valuations for the long-term portions of the transaction. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions, and is not reflective of material inactive markets.
Nuclear Decommissioning Trust
The nuclear decommissioning trust invests in fixed income securities directly and equity securities indirectly through commingled funds. The commingled funds are valued based on the fund’s net asset value and are classified within Level 2. We may transact in the equity commingled fund on a semi-monthly basis and the cash-equivalent commingled fund on a daily basis. Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. The trust fund investments have been established to satisfy APS’s nuclear decommissioning obligations.
Fair Value Tables
The following table presents the fair value at March 31, 2011 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
                                         
    Quoted Prices     Significant                    
    in Active     Other     Significant              
    Markets for     Observable     Unobservable     Counterparty     Balance at  
    Identical Assets     Inputs     Inputs (a)     Netting &     March 31,  
    (Level 1)     (Level 2)     (Level 3)     Other (b)     2011  
Assets
                                       
Risk management activities:
                                       
Commodity contracts
  $     $ 65     $ 64     $ (36 )   $ 93  
Nuclear decommissioning trust:
                                       
Equity securities:
                                       
U.S. commingled funds
          178                   178  
Fixed income securities:
                                       
U.S. Treasury
    69                         69  
Cash and cash equivalent funds (c)
          21                   21  
Corporate
          59                   59  
Mortgage-backed
          81                   81  
Municipality
          70                   70  
Other
          20             (11 )     9  
 
                             
Total
  $ 69     $ 494     $ 64     $ (47 )   $ 580  
 
                             
 
                                       
Liabilities
                                       
Risk management activities:
                                       
Commodity contracts
  $     $ (240 )   $ (112 )   $ 224     $ (128 )
 
                             
     
(a)   Primarily consists of long-dated electricity contracts.
 
(b)   Risk management activities represent netting under master netting agreements, including margin and collateral (see Note 8). Nuclear decommissioning trust represents net pending securities sales and purchases.
 
(c)   These cash equivalents are held in a commingled short-term investment fund that invests in short-term, highly liquid, fixed income instruments.
The following table presents the fair value at December 31, 2010 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
                                         
    Quoted Prices     Significant                    
    in Active     Other     Significant              
    Markets for     Observable     Unobservable     Counterparty     Balance at  
    Identical Assets     Inputs     Inputs (a)     Netting &     December 31,  
    (Level 1)     (Level 2)     (Level 3)     Other (b)     2010  
Assets
                                       
Cash equivalents
  $ 35     $     $     $     $ 35  
Risk management activities:
                                       
Commodity contracts
          80       61       (28 )     113  
Nuclear decommissioning trust:
                                       
Equity securities:
                                       
U.S. commingled funds
          168                   168  
Fixed income securities:
                                       
U.S. Treasury
    50                         50  
Cash and cash equivalent funds (c)
          22                   22  
Corporate
          60                   60  
Mortgage-backed
          81                   81  
Municipality
          79                   79  
Other
          20             (10 )     10  
 
                             
Total
  $ 85     $ 510     $ 61     $ (38 )   $ 618  
 
                             
 
                                       
Liabilities
                                       
Risk management activities:
                                       
Commodity contracts
  $ (1 )   $ (280 )   $ (99 )   $ 256     $ (124 )
 
                             
     
(a)   Primarily consists of long-dated electricity contracts.
 
(b)   Risk management activities represent netting under master netting arrangements, including margin and collateral. See Note 8. Nuclear decommissioning trust represents net pending securities sales and purchases.
 
(c)   These cash equivalents are held in a commingled short-term investment fund that invests in short-term, highly liquid, fixed income instruments.
The following table shows the changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2011 and 2010 (dollars in millions):
                 
    Three Months Ended  
    March 31,  
Commodity Contracts   2011     2010  
Net derivative balance at beginning of period
  $ (38 )   $ (10 )
Total net gains (losses) realized/unrealized:
               
Included in earnings
    1       (1 )
Included in OCI
    2       (6 )
Deferred as a regulatory asset or liability
    (7 )     (12 )
Transfers into Level 3 from Level 2
    (5 )      
Transfers from Level 3 into Level 2
    (1 )     (2 )
 
           
Net derivative balance at end of period
  $ (48 )   $ (31 )
 
           
 
               
Net unrealized gains (losses) included in earnings related to instruments still held at end of period
  $ 1     $ (1 )
Amounts included in earnings are recorded in either regulated electricity segment revenue or regulated electricity segment fuel and purchased power depending on the nature of the underlying contract.
Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.
Nonrecurring Fair Value Measurements
We may be required to record other assets at fair value on a nonrecurring basis. These nonrecurring fair value measurements typically involve write-downs of individual assets due to impairment.
Financial Instruments Not Carried at Fair Value
The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our long-term debt fair value estimates are based on quoted market prices of the same or similar issues. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.
The following table represents the carrying amount and estimated fair value of our long-term debt, including current maturities (dollars in millions):
                                 
    As of     As of  
    March 31, 2011     December 31, 2010  
    Carrying             Carrying        
    Amount     Fair Value     Amount     Fair Value  
 
Pinnacle West
  $ 175     $ 174     $ 175     $ 176  
APS
    3,503       3,735       3,503       3,737  
 
                       
Total
  $ 3,678     $ 3,909     $ 3,678     $ 3,913  
 
                       
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. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in fixed income securities and domestic equity securities. APS classifies investments in decommissioning trust funds 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, we have recorded the offsetting amount of gains or losses on investment securities in other regulatory liabilities or assets. The following table summarizes the fair value of APS’s nuclear decommissioning trust fund assets at March 31, 2011 and December 31, 2010 (dollars in millions):
                         
            Total     Total  
            Unrealized     Unrealized  
    Fair Value     Gains     Losses  
March 31, 2011
                       
Equity securities
  $ 178     $ 52     $  
Fixed income securities
    320       12       (1 )
Net payables (a)
    (11 )            
 
                 
Total
  $ 487     $ 64     $ (1 )
 
                 
     
(a)   Net payables relate to pending securities sales and purchases.
                         
            Total     Total  
            Unrealized     Unrealized  
    Fair Value     Gains     Losses  
December 31, 2010
                       
Equity securities
  $ 168     $ 43     $ (1 )
Fixed income securities
    312       12       (2 )
Net receivables (a)
    (10 )            
 
                 
Total
  $ 470     $ 55     $ (3 )
 
                 
     
(a)   Net payables relate to pending securities sales and purchases.
The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Realized gains
  $ 1     $ 12  
Realized losses
    (2 )     (2 )
Proceeds from the sale of securities (a)
    189       158  
     
(a)   Proceeds are reinvested in the trust.
The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2011 is as follows (dollars in millions):
         
    Fair Value  
Less than one year
  $ 24  
1 year - 5 years
    68  
5 years - 10 years
    98  
Greater than 10 years
    130  
 
     
Total
  $ 320  
 
     
Asset Retirement Obligations
Asset Retirement Obligations
16. Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. During the period ending March 31, 2011, a new decommissioning study with updated cash flow estimates was completed for Palo Verde. This study reflects the twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of decommissioning to 2045. The new study resulted in a $90 million decrease to the liability for asset retirements, a $78 million decrease to electric plant in service, and a $12 million increase to regulatory liabilities.
Condensed Consolidated Statements of Income (APSC) (Unaudited) (USD $)
In Thousands
3 Months Ended
Mar. 31,
2011
2010
ELECTRIC OPERATING REVENUES
$ 647,974 
$ 611,425 
OPERATING EXPENSES
 
 
Fuel and purchased power
212,007 
215,540 
Operations and maintenance
256,486 
207,842 
Depreciation and amortization
106,601 
100,653 
Taxes other than income taxes
37,624 
31,724 
Total
622,434 
562,687 
OPERATING INCOME
37,141 
57,668 
OTHER INCOME (DEDUCTIONS)
 
 
Allowance for equity funds used during construction
5,395 
5,389 
Other income (Note S-2)
1,690 
2,108 
Other expense (Note S-2)
(1,699)
(2,696)
Total
5,386 
4,801 
INTEREST EXPENSE
 
 
Allowance for borrowed funds used during construction
(3,576)
(3,047)
Total
57,501 
57,658 
NET INCOME (LOSS)
(9,674)
(897)
Less: Net income attributable to noncontrolling interests (Note 7)
5,461 
5,117 
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS
(15,135)
(6,014)
Arizona Public Service Company [Member]
 
 
ELECTRIC OPERATING REVENUES
647,994 
611,476 
OPERATING EXPENSES
 
 
Fuel and purchased power
212,007 
215,540 
Operations and maintenance
252,607 
203,881 
Depreciation and amortization
106,559 
100,609 
Income taxes
(6,003)
(5,440)
Taxes other than income taxes
37,250 
31,451 
Total
602,420 
546,041 
OPERATING INCOME
45,574 
65,435 
OTHER INCOME (DEDUCTIONS)
 
 
Income taxes
(1,340)
843 
Allowance for equity funds used during construction
5,395 
5,389 
Other income (Note S-2)
1,978 
1,783 
Other expense (Note S-2)
(3,592)
(3,626)
Total
2,441 
4,389 
INTEREST EXPENSE
 
 
Interest on long-term debt
54,737 
54,752 
Interest on short-term borrowings
2,308 
842 
Debt discount, premium and expense
1,157 
1,137 
Allowance for borrowed funds used during construction
(3,576)
(3,019)
Total
54,626 
53,712 
NET INCOME (LOSS)
(6,611)
16,112 
Less: Net income attributable to noncontrolling interests (Note 7)
5,470 
5,128 
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ (12,081)
$ 10,984 
Condensed Consolidated Balance Sheets (APSC) (Unaudited) (USD $)
In Thousands
3 Months Ended
Mar. 31, 2011
Year Ended
Dec. 31, 2010
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
$ 13,270,775 
$ 13,201,960 
Accumulated depreciation and amortization
(4,580,344)
(4,514,204)
Net
8,690,431 
8,687,756 
Construction work in progress
441,683 
459,361 
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)
135,766 
137,956 
Intangible assets, net of accumulated amortization
182,855 
184,952 
Nuclear fuel, net of accumulated amortization
129,554 
108,794 
Total property, plant and equipment
9,580,289 
9,578,819 
INVESTMENTS AND OTHER ASSETS
 
 
Nuclear decommissioning trust (Note 15)
486,737 
469,886 
Assets from risk management activities (Note 8)
38,520 
39,032 
Other assets
64,429 
116,216 
Total investments and other assets
589,686 
625,134 
CURRENT ASSETS
 
 
Cash and cash equivalents
114,193 
110,188 
Customer and other receivables
309,854 
324,207 
Accrued unbilled revenues
93,659 
103,292 
Allowance for doubtful accounts
(7,691)
(7,981)
Materials and supplies (at average cost)
161,063 
181,414 
Fossil fuel (at average cost)
20,505 
21,575 
Assets from risk management activities (Note 8)
54,579 
73,788 
Regulatory assets (Note 3)
55,743 
62,286 
Deferred income taxes
124,244 
124,897 
Other current assets
31,868 
28,362 
Total current assets
958,017 
1,024,511 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
979,854 
986,370 
Income tax receivable (Note 6)
67,738 
65,103 
Other
127,306 
113,061 
Total deferred debits
1,174,898 
1,164,534 
TOTAL ASSETS
12,302,890 
12,392,998 
CAPITALIZATION
 
 
Common stock
2,429,016 
2,419,133 
Retained earnings
1,351,716 
1,423,961 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(58,554)
(59,420)
Derivative instruments
(90,767)
(100,347)
Total shareholder equity
3,631,411 
3,683,327 
Noncontrolling interests (Note 7)
97,360 
91,899 
Total equity
3,728,771 
3,775,226 
Long-term debt less current maturities (Note 2)
2,748,676 
2,948,991 
Palo Verde sale leaseback lessor notes less current maturities (Note 7)
96,803 
96,803 
CURRENT LIABILITIES
 
 
Current maturities of long-term debt (Note 2)
832,275 
631,879 
Accounts payable
215,968 
236,354 
Accrued taxes
155,172 
104,711 
Accrued interest
54,948 
54,831 
Customer deposits
68,821 
68,322 
Liabilities from risk management activities (Note 8)
71,047 
58,976 
Deferred fuel and purchased power regulatory liability (Note 3)
77,151 
58,442 
Other regulatory liabilities (Note 3)
78,167 
80,526 
Other current liabilities
103,363 
139,063 
Total current liabilities
1,674,212 
1,449,704 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
1,775,368 
1,863,861 
Regulatory liabilities (Note 3)
689,942 
614,063 
Liability for asset retirements (Note 16)
244,483 
328,571 
Liabilities for pension and other postretirement benefits (Note 4)
824,502 
813,121 
Liabilities from risk management activities (Note 8)
56,517 
65,390 
Customer advances
118,778 
121,645 
Coal mine reclamation
117,455 
117,243 
Unrecognized tax benefits (Note 6)
82,613 
66,349 
Other
144,770 
132,031 
Total deferred credits and other
4,054,428 
4,122,274 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
 
 
TOTAL LIABILITIES AND EQUITY
12,302,890 
12,392,998 
Arizona Public Service Company [Member]
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
13,266,069 
13,197,254 
Accumulated depreciation and amortization
(4,576,692)
(4,510,591)
Net
8,689,377 
8,686,663 
Construction work in progress
441,683 
459,316 
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)
135,766 
137,956 
Intangible assets, net of accumulated amortization
182,673 
184,768 
Nuclear fuel, net of accumulated amortization
129,554 
108,794 
Total property, plant and equipment
9,579,053 
9,577,497 
INVESTMENTS AND OTHER ASSETS
 
 
Nuclear decommissioning trust (Note 15)
486,737 
469,886 
Assets from risk management activities (Note 8)
38,520 
39,032 
Other assets
29,124 
71,428 
Total investments and other assets
554,381 
580,346 
CURRENT ASSETS
 
 
Cash and cash equivalents
104,386 
99,937 
Customer and other receivables
276,698 
288,323 
Accrued unbilled revenues
93,659 
103,292 
Allowance for doubtful accounts
(7,489)
(7,646)
Materials and supplies (at average cost)
161,063 
181,414 
Fossil fuel (at average cost)
20,505 
21,575 
Assets from risk management activities (Note 8)
54,579 
73,788 
Regulatory assets (Note 3)
55,743 
62,286 
Deferred income taxes
104,389 
105,042 
Other current assets
27,756 
25,135 
Total current assets
891,289 
953,146 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
979,854 
986,370 
Income tax receivable (Note 6)
68,133 
65,498 
Unamortized debt issue costs
19,938 
20,530 
Other
103,759 
88,490 
Total deferred debits
1,171,684 
1,160,888 
TOTAL ASSETS
12,196,407 
12,271,877 
CAPITALIZATION
 
 
Common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
1,334,210 
1,403,390 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(35,182)
(35,961)
Derivative instruments
(90,755)
(100,334)
Total shareholder equity
3,766,131 
3,824,953 
Noncontrolling interests (Note 7)
96,554 
91,084 
Total equity
3,862,685 
3,916,037 
Long-term debt less current maturities (Note 2)
2,573,676 
2,948,991 
Palo Verde sale leaseback lessor notes less current maturities (Note 7)
96,803 
96,803 
Total capitalization
6,533,164 
6,961,831 
CURRENT LIABILITIES
 
 
Current maturities of long-term debt (Note 2)
832,275 
456,879 
Accounts payable
204,480 
218,491 
Accrued taxes
170,904 
106,431 
Accrued interest
54,471 
54,638 
Customer deposits
68,809 
68,312 
Liabilities from risk management activities (Note 8)
71,047 
58,976 
Deferred fuel and purchased power regulatory liability (Note 3)
77,151 
58,442 
Other regulatory liabilities (Note 3)
78,167 
80,526 
Other current liabilities
96,561 
132,170 
Total current liabilities
1,653,865 
1,234,865 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
1,800,146 
1,895,654 
Regulatory liabilities (Note 3)
689,942 
614,063 
Liability for asset retirements (Note 16)
244,483 
328,571 
Liabilities for pension and other postretirement benefits (Note 4)
782,556 
770,611 
Liabilities from risk management activities (Note 8)
56,517 
65,390 
Customer advances
118,778 
121,645 
Coal mine reclamation
117,455 
117,243 
Unrecognized tax benefits (Note 6)
81,640 
65,363 
Other
117,861 
96,641 
Total deferred credits and other
4,009,378 
4,075,181 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
 
 
TOTAL LIABILITIES AND EQUITY
$ 12,196,407 
$ 12,271,877 
Condensed Consolidated Statements of Cash Flows (APSC) (Unaudited) (USD $)
In Thousands
3 Months Ended
Mar. 31,
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net Income (Loss)
$ (9,674)
$ (897)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
123,298 
114,122 
Deferred fuel and purchased power
49,947 
44,040 
Deferred fuel and purchased power amortization
(31,238)
(25,953)
Allowance for equity funds used during construction
(5,395)
(5,389)
Deferred income taxes
(41,005)
50,845 
Change in mark-to-market valuations
(284)
1,842 
Changes in current assets and liabilities:
 
 
Customer and other receivables
75,528 
60,244 
Accrued unbilled revenues
9,633 
24,505 
Materials, supplies and fossil fuel
21,421 
6,240 
Other current assets
(636)
(8,148)
Accounts payable
(24,543)
(23,334)
Other current liabilities
(37,406)
(39,572)
Change in margin and collateral accounts - assets
4,220 
(11,280)
Change in margin and collateral accounts - liabilities
35,478 
(124,495)
Change in unrecognized tax benefits
18,959 
(62,062)
Change in other long-term assets
(33,129)
(26,593)
Change in other long-term liabilities
35,421 
(36,558)
Net cash flow provided by (used for) operating activities
243,496 
(13,675)
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(191,553)
(202,554)
Contributions in aid of construction
9,136 
2,949 
Allowance for borrowed funds used during construction
(3,576)
(3,080)
Proceeds from nuclear decommissioning trust sales
189,318 
158,448 
Investment in nuclear decommissioning trust
(194,241)
(164,552)
Other
(1,879)
(1,639)
Net cash flow used for investing activities
(192,795)
(210,428)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Repayment of long-term debt
(175,170)
(4,150)
Short-term borrowings and payments - net
700 
135,901 
Dividends paid on common stock
(55,300)
(51,421)
Net cash flow provided by (used for) financing activities
(46,696)
82,253 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
4,005 
(141,850)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
110,188 
145,378 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
114,193 
3,528 
Cash paid during the period for:
 
 
Income taxes, net of (refunds)
(5,547)
Interest, net of amounts capitalized
55,997 
58,679 
Arizona Public Service Company [Member]
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net Income (Loss)
(6,611)
16,112 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
123,256 
113,195 
Deferred fuel and purchased power
49,947 
44,040 
Deferred fuel and purchased power amortization
(31,238)
(25,953)
Allowance for equity funds used during construction
(5,395)
(5,389)
Deferred income taxes
(47,962)
47,754 
Change in mark-to-market valuations
(284)
1,842 
Changes in current assets and liabilities:
 
 
Customer and other receivables
61,973 
61,239 
Accrued unbilled revenues
9,633 
24,505 
Materials, supplies and fossil fuel
21,421 
6,240 
Other current assets
248 
(7,811)
Accounts payable
(18,168)
(22,275)
Other current liabilities
26,872 
(64,600)
Change in margin and collateral accounts - assets
4,220 
(11,280)
Change in margin and collateral accounts - liabilities
35,478 
(124,495)
Change in long-term income tax receivable
(2,635)
Change in unrecognized tax benefits
18,972 
(61,683)
Change in other long-term assets
(29,494)
(23,723)
Change in other long-term liabilities
44,324 
(31,926)
Net cash flow provided by (used for) operating activities
254,557 
(64,208)
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(191,596)
(199,276)
Contributions in aid of construction
9,136 
2,949 
Allowance for borrowed funds used during construction
(3,576)
(3,019)
Proceeds from nuclear decommissioning trust sales
189,318 
158,448 
Investment in nuclear decommissioning trust
(194,241)
(164,552)
Other
(1,879)
(1,639)
Net cash flow used for investing activities
(192,838)
(207,089)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Repayment of long-term debt
(170)
(357)
Short-term borrowings and payments - net
195,000 
Dividends paid on common stock
(57,100)
(42,500)
Net cash flow provided by (used for) financing activities
(57,270)
152,143 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
4,449 
(119,154)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
99,937 
120,798 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
104,386 
1,644 
Cash paid during the period for:
 
 
Income taxes, net of (refunds)
65,498 
Interest, net of amounts capitalized
$ 53,636 
$ 54,174 
S-1. Changes in Equity (APSC)
3 Months Ended
Mar. 31, 2011
S-1. Changes in Equity
Arizona Public Service Company [Member]
 
S-1. Changes in Equity
9. Changes in Equity
The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2011 and 2010 (dollars in thousands):
                                                 
    Three Months Ended March 31, 2011     Three Months Ended March 31, 2010  
    Common     Noncontrolling             Common     Noncontrolling        
    Shareholders     Interests     Total     Shareholders     Interests     Total  
 
                                               
Beginning balance, January 1
  $ 3,683,327     $ 91,899     $ 3,775,226     $ 3,316,109     $ 111,895     $ 3,428,004  
 
                                               
Net income (loss)
    (15,135 )     5,461       (9,674 )     (6,014 )     5,117       (897 )
 
                                   
Other comprehensive income (loss):
                                               
Net unrealized gains (losses) on derivative instruments (a)
    988             988       (91,667 )           (91,667 )
Net reclassification of realized losses to income (b)
    14,846             14,846       13,185             13,185  
Reclassification of pension and other postretirement benefits to income
    1,433             1,433       1,393             1,393  
Net income tax benefit (expense) related to items of other comprehensive income (loss)
    (6,821 )           (6,821 )     30,426             30,426  
 
                                   
Total other comprehensive income (loss)
    10,446             10,446       (46,663 )           (46,663 )
 
                                   
Total comprehensive income (loss)
    (4,689 )     5,461       772       (52,677 )     5,117       (47,560 )
 
                                   
 
                                               
Issuance of capital stock
    13,560             13,560       2,680             2,680  
Purchase of treasury stock, net of reissuances
    (3,530 )           (3,530 )     1,078             1,078  
Other (primarily stock compensation)
    (148 )           (148 )     2       (22 )     (20 )
Dividends on common stock
    (57,109 )           (57,109 )     (53,259 )           (53,259 )
Net capital activities by noncontrolling interests
                            (923 )     (923 )
 
                                   
Ending balance, March 31
  $ 3,631,411     $ 97,360     $ 3,728,771     $ 3,213,933     $ 116,067     $ 3,330,000  
 
                                   
     
(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-1. Changes in Equity
The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three and nine months ended March 31, 2011 and 2010 (dollars in thousands):
                                                 
    Three Months Ended March 31, 2011     Three Months Ended March 31, 2010  
    Shareholder     Noncontrolling             Shareholder     Noncontrolling        
    Equity     Interests     Total     Equity     Interests     Total  
 
                                               
Beginning balance, January 1
  $ 3,824,953     $ 91,084     $ 3,916,037     $ 3,445,355     $ 82,324     $ 3,527,679  
 
                                               
Net income (loss)
    (12,081 )     5,470       (6,611 )     10,984       5,128       16,112  
 
                                   
Other comprehensive income (loss):
                                               
Net unrealized gains (losses) on derivative instruments (a)
    988             988       (91,667 )           (91,667 )
Net reclassification of realized losses to income (b)
    14,846             14,846       13,185             13,185  
Reclassification of pension and other postretirement benefits to income
    1,288             1,288       1,064             1,064  
Net income tax benefit (expense) related to items of other comprehensive income (loss)
    (6,764 )           (6,764 )     30,565             30,565  
 
                                   
Total other comprehensive income (loss)
    10,358             10,358       (46,853 )           (46,853 )
 
                                   
Total comprehensive income (loss)
    (1,723 )     5,470       3,747       (35,869 )     5,128       (30,741 )
 
                                   
 
                                               
Dividends on common stock
    (57,100 )           (57,100 )     (42,500 )           (42,500 )
Other
    1             1                    
 
                                   
Ending balance, March 31
  $ 3,766,131     $ 96,554     $ 3,862,685     $ 3,366,986     $ 87,452     $ 3,454,438  
 
                                   
     
(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-2. Other Income and Other Expense (APSC)
3 Months Ended
Mar. 31, 2011
S-2. Other Income and Other Expense
Arizona Public Service Company [Member]
 
S-2. Other Income and Other Expense
11. Other Income and Other Expense
The following table provides detail of other income and other expense for the three months ended March 31, 2011 and 2010 (dollars in thousands):
                 
    Three Months Ended March 31,  
    2011     2010  
Other income:
               
Interest income
  $ 391     $ 874  
Investment gains — net
    1,293       1,222  
Miscellaneous
    6       12  
 
           
Total other income
  $ 1,690     $ 2,108  
 
           
 
               
Other expense:
               
Non-operating costs
  $ (1,444 )   $ (1,794 )
Miscellaneous
    (255 )     (902 )
 
           
Total other expense
  $ (1,699 )   $ (2,696 )
 
           
S-2. Other Income and Other Expense
The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2011 and 2010 (dollars in thousands):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Other income:
               
Interest income
  $ 130     $ 462  
Investment gains — net
    1,150       1,165  
Miscellaneous
    698       156  
 
           
Total other income
  $ 1,978     $ 1,783  
 
           
 
               
Other expense:
               
Non-operating costs (a)
  $ (1,899 )   $ (1,958 )
Asset dispositions
    (728 )     (39 )
Miscellaneous
    (965 )     (1,629 )
 
           
Total other expense
  $ (3,592 )   $ (3,626 )
 
           
     
(a)   As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).