PINNACLE WEST CAPITAL CORP, 10-Q filed on 11/2/2012
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2012
Oct. 29, 2012
Document and Entity Information
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2012 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
109,699,804 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q3 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
OPERATING REVENUES
$ 1,109,475 
$ 1,124,841 
$ 2,608,682 
$ 2,573,487 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
302,894 
337,896 
783,926 
793,952 
Operations and maintenance
220,729 
210,035 
647,628 
675,654 
Depreciation and amortization
100,353 
106,350 
301,068 
319,550 
Taxes other than income taxes
36,507 
34,223 
120,271 
112,002 
Other expenses
1,022 
1,320 
5,323 
4,536 
Total
661,505 
689,824 
1,858,216 
1,905,694 
OPERATING INCOME
447,970 
435,017 
750,466 
667,793 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
5,708 
7,378 
15,639 
18,697 
Other income (Note 11)
420 
441 
1,357 
2,630 
Other expense (Note 11)
(5,696)
(3,052)
(12,433)
(7,921)
Total
432 
4,767 
4,563 
13,406 
INTEREST EXPENSE
 
 
 
 
Interest charges
52,242 
62,034 
162,209 
183,251 
Allowance for borrowed funds used during construction
(3,830)
(6,939)
(10,428)
(14,371)
Total
48,412 
55,095 
151,781 
168,880 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
399,990 
384,689 
603,248 
512,319 
INCOME TAXES
147,116 
131,416 
219,160 
176,229 
INCOME FROM CONTINUING OPERATIONS
252,874 
253,273 
384,088 
336,090 
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
 
 
 
 
Net of income tax expense (benefit) of $(7) and $6,216 for three months ended September 30, 2012 and 2011 and $(1,047) and $7,121 for nine months ended September 30, 2012 and 2011 (Note 13)
(11)
9,512 
(1,595)
10,860 
NET INCOME
252,863 
262,785 
382,493 
346,950 
Less: Net income attributable to noncontrolling interests (Note 7)
8,040 
7,426 
23,582 
20,041 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
244,823 
255,359 
358,911 
326,909 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
109,555 
109,128 
109,449 
109,003 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
110,655 
109,861 
110,420 
109,683 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Income from continuing operations attributable to common shareholders - basic (in dollars per share)
$ 2.23 
$ 2.25 
$ 3.29 
$ 2.90 
Net income attributable to common shareholders - basic (in dollars per share)
$ 2.23 
$ 2.34 
$ 3.28 
$ 3.00 
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)
$ 2.21 
$ 2.24 
$ 3.26 
$ 2.88 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 2.21 
$ 2.32 
$ 3.25 
$ 2.98 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
 
 
$ 1.575 
$ 1.575 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
 
Income from continuing operations, net of tax
244,834 
245,838 
360,515 
316,001 
Discontinued operations, net of tax
(11)
9,521 
(1,604)
10,908 
Net income attributable to common shareholders
$ 244,823 
$ 255,359 
$ 358,911 
$ 326,909 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
Income tax expense (benefit) on discontinued operations
$ (7)
$ 6,216 
$ (1,047)
$ 7,121 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
NET INCOME
$ 252,863 
$ 262,785 
$ 382,493 
$ 346,950 
Derivative instruments:
 
 
 
 
Net unrealized loss, net of tax benefit of $47 and $10,055 for three months ended September 30, 2012 and 2011 and $14,817 and $16,113 for nine months ended September 30, 2012 and 2011, respectively
(72)
(15,402)
(22,696)
(24,679)
Reclassification of net realized loss, net of tax benefit of $19,543 and $23,361 for three months ended September 30, 2012 and 2011 and $34,361 and $39,213 for nine months ended September 30, 2012 and 2011, respectively
29,935 
35,783 
52,632 
60,065 
Pension and other postretirement benefits activity, net of tax expense of $640 and $489 for three months ended September 30, 2012 and 2011 and $1,797 and $1,853 for nine months ended September 30, 2012 and 2011, respectively
980 
750 
2,752 
2,838 
Total other comprehensive income
30,843 
21,131 
32,688 
38,224 
COMPREHENSIVE INCOME
283,706 
283,916 
415,181 
385,174 
Less: Comprehensive income attributable to noncontrolling interests
8,040 
7,426 
23,582 
20,041 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 275,666 
$ 276,490 
$ 391,599 
$ 365,133 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
Net unrealized loss, tax benefit
$ 47 
$ 10,055 
$ 14,817 
$ 16,113 
Reclassification of net realized loss, tax benefit
19,543 
23,361 
34,361 
39,213 
Pension and other postretirement benefits activity, tax expense
$ 640 
$ 489 
$ 1,797 
$ 1,853 
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2012
Dec. 31, 2011
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 79,479 
$ 33,583 
Customer and other receivables
365,309 
284,183 
Accrued unbilled revenues
136,425 
125,239 
Allowance for doubtful accounts
(4,297)
(3,748)
Materials and supplies (at average cost)
219,026 
204,387 
Fossil fuel (at average cost)
31,234 
22,000 
Deferred income taxes
95,487 
130,571 
Income tax receivable (Note 6)
 
6,466 
Assets from risk management activities (Note 8)
26,257 
30,264 
Deferred fuel and purchased power regulatory asset (Note 3)
67,910 
27,549 
Other regulatory assets (Note 3)
53,960 
69,072 
Other current assets
28,062 
26,904 
Total current assets
1,098,852 
956,470 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 8)
38,449 
49,322 
Nuclear decommissioning trust (Note 15)
566,960 
513,733 
Other assets
62,428 
64,588 
Total investments and other assets
667,837 
627,643 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
14,116,015 
13,753,971 
Accumulated depreciation and amortization
(4,901,833)
(4,709,991)
Net
9,214,182 
9,043,980 
Construction work in progress
587,826 
496,745 
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)
129,962 
132,864 
Intangible assets, net of accumulated amortization
152,665 
170,571 
Nuclear fuel, net of accumulated amortization
139,873 
118,098 
Total property, plant and equipment
10,224,508 
9,962,258 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,250,792 
1,352,079 
Income tax receivable (Note 6)
69,953 
68,633 
Other
148,344 
143,935 
Total deferred debits
1,469,089 
1,564,647 
TOTAL ASSETS
13,460,286 
13,111,018 
CURRENT LIABILITIES
 
 
Accounts payable
231,151 
326,987 
Accrued taxes (Note 6)
190,188 
120,289 
Accrued interest
50,890 
54,872 
Current maturities of long-term debt
90,360 
477,435 
Customer deposits
76,853 
72,176 
Liabilities from risk management activities (Note 8)
56,263 
53,968 
Regulatory liabilities (Note 3)
96,362 
88,362 
Other current liabilities
157,281 
148,616 
Total current liabilities
949,348 
1,342,705 
LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
Long-term debt less current maturities
3,281,531 
2,953,507 
Palo Verde sale leaseback lessor notes less current maturities (Note 7)
57,420 
65,547 
Total long-term debt less current maturities
3,338,951 
3,019,054 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,115,316 
1,925,388 
Regulatory liabilities (Note 3)
746,754 
737,332 
Liability for asset retirements
294,524 
279,643 
Liabilities for pension and other postretirement benefits (Note 4)
1,206,150 
1,268,910 
Liabilities from risk management activities (Note 8)
81,244 
82,495 
Customer advances
105,941 
116,805 
Coal mine reclamation
118,601 
117,896 
Unrecognized tax benefits (Note 6)
69,791 
72,270 
Other
248,082 
217,934 
Total deferred credits and other
4,986,403 
4,818,673 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 9)
 
 
Common stock, no par value
2,456,107 
2,444,247 
Treasury stock
(1,440)
(4,717)
Total common stock
2,454,667 
2,439,530 
Retained earnings
1,721,050 
1,534,483 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(62,695)
(65,447)
Derivative instruments
(56,780)
(86,716)
Total accumulated other comprehensive loss
(119,475)
(152,163)
Total shareholders' equity
4,056,242 
3,821,850 
Noncontrolling interests (Note 7)
129,342 
108,736 
Total equity
4,185,584 
3,930,586 
TOTAL LIABILITIES AND EQUITY
$ 13,460,286 
$ 13,111,018 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 382,493 
$ 346,950 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Gain on sale of energy-related products and services business
 
(10,404)
Depreciation and amortization including nuclear fuel
360,570 
370,107 
Deferred fuel and purchased power
51,533 
30,965 
Deferred fuel and purchased power amortization
(91,894)
(121,018)
Allowance for equity funds used during construction
(15,639)
(18,697)
Deferred income taxes
206,501 
131,582 
Change in derivative instruments fair value
(943)
1,861 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(76,697)
(47,410)
Accrued unbilled revenues
(11,186)
(80,877)
Materials, supplies and fossil fuel
(23,873)
(25,532)
Other current assets
(10,035)
(1,581)
Accounts payable
(69,776)
29,340 
Accrued taxes and income tax receivable - net
76,365 
89,534 
Other current liabilities
17,071 
30,300 
Change in margin and collateral accounts - assets
1,980 
33,591 
Change in margin and collateral accounts - liabilities
114,579 
85,785 
Change in unrecognized tax benefits
(3,554)
12,123 
Change in other long-term assets
(15,205)
(10,678)
Change in other long-term liabilities
37,181 
74,565 
Net cash flow provided by operating activities
929,471 
920,506 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(670,684)
(643,261)
Contributions in aid of construction
41,451 
36,351 
Allowance for borrowed funds used during construction
(10,428)
(14,371)
Proceeds from sale of energy-related products and services business
 
45,111 
Proceeds from nuclear decommissioning trust sales
295,126 
405,637 
Investment in nuclear decommissioning trust
(308,063)
(417,957)
Proceeds from sale of life insurance policies
 
55,444 
Other
(520)
(1,246)
Net cash flow used for investing activities
(653,118)
(534,292)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
351,081 
470,353 
Repayment of long-term debt
(421,703)
(228,457)
Short-term borrowings and payments - net
 
(16,600)
Dividends paid on common stock
(167,074)
(166,197)
Common stock equity issuance
9,684 
14,953 
Distributions to noncontrolling interests
(2,630)
(2,610)
Other
185 
(3,132)
Net cash flow provided by (used for) financing activities
(230,457)
68,310 
NET INCREASE IN CASH AND CASH EQUIVALENTS
45,896 
454,524 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
33,583 
110,188 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
79,479 
564,712 
Cash paid during the period for:
 
 
Income taxes, net of (refunds)
(651)
5,676 
Interest, net of amounts capitalized
$ 152,582 
$ 163,250 
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 and El Dorado Investment Company (“El Dorado”) and formerly SunCor Development Company (“SunCor”) and APS Energy Services Company, Inc. (“APSES”).  See Note 13 for discussion of the bankruptcy filing of SunCor and the sale of APSES.  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 Nuclear Generating Station (“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.

 

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 2011 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

 

See Note 16 for discussion of amended guidance on the presentation of comprehensive income.

 

The following tables show the impact of the reclassifications to prior year (previously reported) amounts (dollars in thousands):

 

Statement of Income for the Three
Months Ended September 30, 2011

 

As
previously
reported

 

Reclassifications
to conform to
current year
presentation

 

Amount reported
after
reclassifications
to conform to
current year
presentation

 

Operating Revenues

 

 

 

 

 

 

 

Regulated electricity segment

 

$

1,124,049

 

$

(1,124,049

)

$

 

Other revenues

 

792

 

(792

)

 

Operating revenues

 

 

1,124,841

 

1,124,841

 

 

 

 

 

 

 

 

 

Statement of Income for the Nine
Months Ended September 30, 2011

 

As
previously
reported

 

Reclassifications
to conform to
current year
presentation

 

Amount reported
after
reclassifications
to conform to
current year
presentation

 

Operating Revenues

 

 

 

 

 

 

 

Regulated electricity segment

 

$

2,570,692

 

$

(2,570,692

)

$

 

Other revenues

 

2,795

 

(2,795

)

 

Operating revenues

 

 

2,573,487

 

2,573,487

 

 

 

 

 

 

 

 

 

Statement of Cash Flows for the Nine
Months Ended September 30, 2011

 

As
previously
reported

 

Reclassifications
to conform to
current year
presentation

 

Amount reported
after
reclassifications
to conform to
current year
presentation

 

Cash Flows from Investing Activities

 

 

 

 

 

 

 

Proceeds from sale of commercial real estate investments

 

$

1,100

 

$

(1,100

)

$

 

Other

 

(2,346

)

1,100

 

(1,246

)

 

Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters

 

 

2.                                      Long-Term Debt and Liquidity Matters

 

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

 

Pinnacle West

 

At September 30, 2012, Pinnacle West’s $200 million credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  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 September 30, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

 

APS

 

On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

 

On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029.  On June 1, 2012 we remarketed these bonds.  Currently, the interest rate on these bonds is reset daily by a remarketing agent.  The daily rate at September 30, 2012 was 0.20% per annum.  Additionally, the bonds are supported by a letter of credit.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

 

On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A.  The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014.  During this time, the bonds will bear interest at a rate of 1.25% per annum.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

 

On November 1, 2012 APS redeemed at par all $90 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029.  The bonds were reflected as long-term debt on our Condensed Consolidated Balance Sheets as of September 30, 2012.

 

At September 30, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, and a $500 million facility that matures in November 2016.  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At September 30, 2012, APS had no outstanding borrowings or outstanding letters of credit under these credit facilities, nor did it have any commercial paper borrowings.

 

See “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

 

Debt Fair Value

 

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy.  See Note 14 for discussion of the fair value hierarchy.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 

 

 

As of
September 30, 2012

 

As of
December 31, 2011

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Pinnacle West

 

$

125

 

$

125

 

$

125

 

$

123

 

APS

 

3,304

 

3,817

 

3,371

 

3,803

 

Total

 

$

3,429

 

$

3,942

 

$

3,496

 

$

3,926

 

 

Debt Provisions

 

An 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 September 30, 2012, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.2 billion, and total capitalization was approximately $7.4 billion.  APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same.  Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

 

Regulatory Matters
Regulatory Matters

 

 

3.                                      Regulatory Matters

 

Retail Rate Case Filing with the Arizona Corporation Commission

 

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.

 

Settlement Agreement

 

The Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for purchased power costs (“Base Fuel Rate”)) from $0.03757 to $0.03207 per kilowatt-hour (“kWh”); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff (“RES”) surcharge to base rates in an estimated amount of $36.8 million.

 

APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016.  The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest.  Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement.

 

Other key provisions of the Settlement Agreement include the following:

 

·                                          An authorized return on common equity of 10.0%;

 

·                                          A capital structure comprised of 46.1% debt and 53.9% common equity;

 

·                                          A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

 

·                                          Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

 

·                                          Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

 

·                                          Deferral of 100% in all years if Arizona property tax rates decrease;

 

·                                          A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant (“Four Corners”);

 

·                                          Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

 

·                                          Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

 

·                                          Modifications to the Power Supply Adjustor (“PSA”), including the elimination of the current 90/10 sharing provision;

 

·                                          A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge (“DSMAC”) to recoup capital expenditures not required under the terms of the 2008 rate case settlement agreement discussed below.

 

·                                          Allowing a negative credit that currently exists in the PSA to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

 

·                                          Modification of the transmission cost adjustor (“TCA”) to streamline the process for future transmission-related rate changes; and

 

·                                          Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.

 

The Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2008 rate case settlement to process 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.

 

2008 General Retail Rate Case On-Going Impacts

 

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008.  The settlement agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

 

·                                          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 through 2012 and its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand side management costs and incentives.

 

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 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.

 

On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million.  On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million.  Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 megawatts (“MW”) under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility-owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015.  In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications.  Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

 

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $92.8 million to $102.4 million.  The budget range stems from options related to distributed energy.  The first option involves no new incentives for distributed energy.  The second option would offer incentives for residential photovoltaic distributed energy beginning where 2012 incentives end and stepping down gradually based upon market participation.  APS’s filing also proposed a system of establishing compliance with distributed energy requirements that depends upon tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  Further, APS described its Community Solar program, a utility-owned 25 MW program that will be split into 3 to 7 separate projects throughout communities in APS’s service territory (this is the 25 MW program described in clause (iv) of the preceding paragraph).  APS expects a decision from the ACC around year end.

 

Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC.  In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand side management programs over the current year.  Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis.  The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives.

 

The ACC previously 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 2008 retail rate case 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 amortized over a three-year period, which ends in 2012.

 

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011.  The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year.  This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (2.75% of total energy resources for the same two-year period).  The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates.

 

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later this year, APS intends to file a supplement to its plan that will include a proposed budget for 2013.

 

PSA Mechanism and Balance.  The 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 asset (liability) for 2012 and 2011 (dollars in millions):

 

 

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

Beginning balance

 

$

28

 

$

(58

)

Deferred fuel and purchased power costs — current period

 

(52

)

(31

)

Amounts credited to customers

 

92

 

121

 

Ending balance

 

$

68

 

$

32

 

 

The PSA rate for the PSA year beginning February 1, 2012 is negative $0.0042 per kWh as compared to negative $0.0057 per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

 

Transmission Rates and Transmission Cost AdjustorIn 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 was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 and will go into effect automatically unless suspended by the ACC.

 

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 increased by approximately $44 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 million of this revenue increase relates to Retail Transmission Charges.  The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

 

Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula.  Because of higher relative system demand by APS’s retail customers, the approximately $16 million increase reflects roughly a $2 million decrease for wholesale customers and an $18 million increase for APS retail customers.

 

On May 14, 2012, APS filed an application with the ACC to implement the FERC-approved transmission rates for retail customers.  On July 18, 2012, the ACC approved the application authorizing the implementation of the FERC-approved transmission rates for retail customers, which became effective August 2012.

 

As part of APS’s proposed acquisition of Southern California Edison’s (“SCE”) interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing agreement that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California.  On October 1, 2012, APS filed a request with FERC seeking authorization to cancel the existing agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 29-year period.  APS expects a decision from FERC before the end of 2012.  We believe these costs are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance.

 

Regulatory Assets and Liabilities

 

The detail of regulatory assets is as follows (dollars in millions):

 

 

 

September 30, 2012

 

December 31, 2011

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

$

 

$

939

 

$

 

$

1,023

 

Income taxes — allowance for funds used during construction (“AFUDC”) equity

 

3

 

91

 

3

 

81

 

Deferred fuel and purchased power — mark-to-market (Note 8)

 

11

 

16

 

43

 

34

 

Transmission vegetation management

 

9

 

25

 

9

 

32

 

Coal reclamation

 

8

 

26

 

2

 

35

 

Palo Verde VIEs (Note 7)

 

 

37

 

 

35

 

Deferred compensation

 

 

35

 

 

33

 

Deferred fuel and purchased power (a)

 

68

 

 

28

 

 

Tax expense of Medicare subsidy

 

2

 

17

 

2

 

18

 

Loss on reacquired debt

 

1

 

18

 

1

 

19

 

Income taxes — investment tax credit basis adjustment

 

1

 

17

 

 

15

 

Pension and other postretirement benefits deferral

 

8

 

15

 

 

12

 

Demand side management (a)

 

 

 

7

 

1

 

Other

 

11

 

15

 

2

 

14

 

Total regulatory assets (b)

 

$

122

 

$

1,251

 

$

97

 

$

1,352

 

 

 

(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.”

 

The detail of regulatory liabilities is as follows (dollars in millions):

 

 

 

September 30, 2012

 

December 31, 2011

 

 

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs (a)

 

$

28

 

$

328

 

$

22

 

$

349

 

Asset retirement obligations

 

 

258

 

 

225

 

Renewable energy standard (b)

 

47

 

 

54

 

 

Income taxes — change in rates

 

 

59

 

 

59

 

Spent nuclear fuel

 

9

 

38

 

5

 

44

 

Deferred gains on utility property

 

2

 

13

 

2

 

14

 

Income taxes- deferred investment tax credit

 

1

 

35

 

1

 

30

 

Demand side management (b)

 

8

 

 

 

 

Other

 

1

 

16

 

4

 

16

 

Total regulatory liabilities

 

$

96

 

$

747

 

$

88

 

$

737

 

 

 

(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.

 

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.  See Note 14 for the fair value discussion of plan assets held in our retirement and other benefit plans.

 

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred as a regulatory asset for future recovery, pursuant to an ACC regulatory order.  We deferred pension and other postretirement benefit costs of approximately $3 million for the three months ended September 30, 2011, and approximately $14 million and $9 million for the nine months ended September 30, 2012 and 2011, respectively.  Pursuant to an ACC regulatory order, we began amortizing the regulatory asset in July 2012.  We amortized approximately $2 million for the three and nine months ended September 30, 2012. 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 or amortized to the regulatory asset) (dollars in millions):

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

Three Months
Ended
September 30,

 

Nine Months
Ended
September 30,

 

Three Months
Ended
September 30,

 

Nine Months
Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

2012

 

2011

 

2012

 

2011

 

Service cost - benefits earned during the period

 

$

16

 

$

14

 

$

48

 

$

43

 

$

7

 

$

5

 

$

20

 

$

17

 

Interest cost on benefit obligation

 

30

 

31

 

90

 

94

 

12

 

12

 

35

 

35

 

Expected return on plan assets

 

(35

)

(33

)

(106

)

(100

)

(12

)

(10

)

(34

)

(31

)

Amortization of:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prior service cost

 

 

 

1

 

1

 

 

 

 

 

Net actuarial loss

 

11

 

7

 

33

 

19

 

5

 

4

 

15

 

11

 

Net periodic benefit cost

 

$

22

 

$

19

 

$

66

 

$

57

 

$

12

 

$

11

 

$

36

 

$

32

 

Portion of cost charged to expense

 

$

12

 

$

7

 

$

25

 

$

22

 

$

7

 

$

4

 

$

13

 

$

12

 

 

Contributions

 

We have contributed $65 million to our pension plan year to date in 2012.  The minimum contributions for the pension plan due in 2013 and 2014 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero and $89 million, respectively.  However, we are currently evaluating future expected contributions considering the pension plan’s current funded status, discount rates, interest rates, investment returns and actual contributions made in prior years, among other factors, to determine the level to which future contributions may exceed these new minimum funding levels.  The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year.

 

Business Segments
Business Segments

 

 

5.             Business Segments

 

Pinnacle West’s only 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 and nine months ended September 30, 2012 and 2011 and at September 30, 2012 and December 31, 2011 is provided as follows (dollars in millions):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Regulated electricity segment

 

$

1,109

 

$

1,124

 

$

2,607

 

$

2,571

 

All other

 

 

1

 

2

 

2

 

Total

 

$

1,109

 

$

1,125

 

$

2,609

 

$

2,573

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to common shareholders:

 

 

 

 

 

 

 

 

 

Regulated electricity segment

 

$

246

 

$

246

 

$

364

 

$

318

 

All other (a)

 

(1

)

9

 

(5

)

9

 

Total

 

$

245

 

$

255

 

$

359

 

$

327

 

 

 

 

As of
September 30, 2012

 

As of
December 31, 2011

 

Assets:

 

 

 

 

 

Regulated electricity segment

 

$

13,426

 

$

13,068

 

All other (a)

 

34

 

43

 

Total

 

$

13,460

 

$

13,111

 

 

 

(a)           All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.  See Note 13 for discussion of discontinued operations.

 

Income Taxes
Income Taxes

 

 

6.             Income Taxes

 

The $70 million long-term income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt.  Further clarification of the timing is expected from the IRS within the next twelve months.

 

Net Income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 7).  As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.

 

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009.  At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made.  However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

 

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.

 

As of September 30, 2012, 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 2007.

 

Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities

 

 

7.             Palo Verde Sale Leaseback Variable Interest Entities

 

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  APS will pay approximately $49 million per year for the years 2012 to 2015 related to these leases.  The lease agreements include fixed rate renewal periods, which gives 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.  Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

 

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 and nine months ended September 30, 2012 of $8 million and $24 million, respectively, 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 September 30, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

 

 

 

September 30,
2012

 

December 31,
2011

 

Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation

 

$

130

 

$

133

 

Current maturities of long-term debt

 

26

 

31

 

Palo Verde sale leaseback lessor notes long-term debt excluding current maturities

 

57

 

66

 

Equity — Noncontrolling interests

 

129

 

108

 

 

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.

 

APS is exposed to losses relating to these 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 September 30, 2012, APS would have been required to pay the noncontrolling equity participants approximately $142 million and assume $83 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

 

For regulatory ratemaking purposes the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

 

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 market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

 

On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as accounting hedges.  This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts.  For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through other comprehensive income (“OCI”), but are deferred through the PSA.  The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.

 

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 14 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures 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 OCI 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 cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.

 

Prior to the Settlement Agreement, for its regulated operations, APS deferred 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.  Due to the Settlement Agreement, for its regulated operations, APS now defers for future rate treatment 100% of the unrealized gains and losses for delivery periods after June 30, 2012 on 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 Base Fuel Rate (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 September 30, 2012, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

 

Commodity

 

Quantity

 

Power

 

8,517

 

gigawatt hours

 

Gas

 

155

 

Bcfs (a)

 

 

 

(a)           “Bcf” is Billion Cubic Feet.

 

Gains and Losses from Derivative Instruments

 

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Commodity Contracts

 

Location

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss Recognized in OCI on Derivative Instruments (Effective Portion)

 

Other comprehensive loss - derivative instruments

 

$

(119

)

$

(25,457

)

$

(37,513

)

$

(40,792

)

Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized) (a)

 

Fuel and purchased power

 

(49,478

)

(59,144

)

(86,993

)

(99,278

)

Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)

 

Fuel and purchased power

 

 

17

 

117

 

(147

)

 

 

(a)           During the nine months ended September 30, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges.  There were no amounts reclassified in the third quarter of 2012 and in the 2011 periods related to discontinued cash flow hedges.

 

During the next twelve months, we estimate that a net loss of $51 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

 

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

 

 

 

Financial Statement

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Commodity Contracts

 

Location

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Gain Recognized in Income

 

Operating revenues

 

$

258

 

$

81

 

$

19

 

$

1,085

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Gain (Loss) Recognized in Income

 

Fuel and purchased power

 

12,870

 

(13,219

)

13,860

 

(25,138

)

Total

 

 

 

$

13,128

 

$

(13,138

)

$

13,879

 

$

(24,053

)

 

Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

 

The following table provides information about the fair value of our risk management activities 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 September 30, 2012 (dollars in thousands):

 

Commodity Contracts

 

Designated
as Hedging
Instruments

 

Not
Designated
as Hedging
Instruments

 

Margin and
Collateral
Provided to
Counterparties

 

Collateral
Provided from
Counterparties

 

Other (b)

 

Total

 

Current Assets

 

$

 

$

57,165

 

$

320

 

$

 

$

(31,228

)

$

26,257

 

Investments and Other Assets

 

 

47,868

 

 

 

(9,419

)

38,449

 

Total Assets

 

 

105,033

 

320

 

 

(40,647

)

64,706

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(1,092

)

(117,325

)

43,480

 

(13,145

)(a)

31,819

 

(56,263

)

Deferred Credits and Other

 

(4,523

)

(103,173

)

17,033

 

 

9,419

 

(81,244

)

Total Liabilities

 

(5,615

)

(220,498

)

60,513

 

(13,145

)

41,238

 

(137,507

)

Total

 

$

(5,615

)

$

(115,465

)

$

60,833

 

$

(13,145

)

$

591

 

$

(72,801

)

 

 

(a)           Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)           Other represents derivative instrument netting, option premiums, and other risk management contracts.

 

The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2011 (dollars in thousands):

 

Commodity Contracts

 

Designated
as Hedging
Instruments

 

Not
Designated as
Hedging
Instruments

 

Margin and
Collateral
Provided to
Counterparties

 

Collateral
Provided from
Counterparties

 

Other (b)

 

Total

 

Current Assets

 

$

7,287

 

$

76,162

 

$

1,630

 

$

 

$

(54,815

)

$

30,264

 

Investments and Other Assets

 

3,804

 

58,273

 

 

 

(12,755

)

49,322

 

Total Assets

 

11,091

 

134,435

 

1,630

 

 

(67,570

)

79,586

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

(82,195

)

(124,028

)

107,228

 

(11,145

)(a)

56,172

 

(53,968

)

Deferred Credits and Other

 

(68,137

)

(92,880

)

65,768

 

 

12,754

 

(82,495

)

Total Liabilities

 

(150,332

)

(216,908

)

172,996

 

(11,145

)

68,926

 

(136,463

)

Total Derivative Instruments

 

$

(139,241

)

$

(82,473

)

$

174,626

 

$

(11,145

)

$

1,356

 

$

(56,877

)

 

 

(a)           Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)           Other represents derivative instrument netting, option premiums, and other risk management contracts.

 

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 82% of Pinnacle West’s $65 million of risk management assets as of September 30, 2012.  This exposure relates to long-term traditional wholesale contracts with counterparties that have 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.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

 

The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2012 (dollars in millions):

 

 

 

 

September 30,
2012

 

Aggregate Fair Value of Derivative Instruments in a Net Liability Position

 

$

226

 

Cash Collateral Posted

 

60

 

Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)

 

104

 

 

 

(a)   This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

 

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 $183 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 and nine months ended September 30, 2012 and 2011 (dollars in thousands):

 

 

 

Three Months Ended September 30, 2012

 

Three Months Ended September 30, 2011

 

 

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, July 1

 

$

3,778,035

 

$

121,302

 

$

3,899,337

 

$

3,613,705

 

$

101,905

 

$

3,715,610

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

244,823

 

8,040

 

252,863

 

255,359

 

7,426

 

262,785

 

Other comprehensive income

 

30,843

 

 

30,843

 

21,131

 

 

21,131

 

Total comprehensive income

 

275,666

 

8,040

 

283,706

 

276,490

 

7,426

 

283,916

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

2,365

 

 

2,365

 

3,789

 

 

3,789

 

Reissuance (purchase) of treasury stock - net

 

(82

)

 

(82

)

537

 

 

537

 

Other (primarily stock compensation)

 

258

 

 

258

 

(436

)

 

(436

)

Net capital activities by noncontrolling interests

 

 

 

 

 

(421

)

(421

)

Ending balance, September 30

 

$

4,056,242

 

$

129,342

 

$

4,185,584

 

$

3,894,085

 

$

108,910

 

$

4,002,995

 

 

 

 

Nine Months Ended September 30, 2012

 

Nine Months Ended September 30, 2011

 

 

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

Common
Shareholders

 

Noncontrolling
Interests

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance, January 1

 

$

3,821,850

 

$

108,736

 

$

3,930,586

 

$

3,683,327

 

$

91,899

 

$

3,775,226

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

358,911

 

23,582

 

382,493

 

326,909

 

20,041

 

346,950

 

Other comprehensive income

 

32,688

 

 

32,688

 

38,224

 

 

38,224

 

Total comprehensive income

 

391,599

 

23,582

 

415,181

 

365,133

 

20,041

 

385,174

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of capital stock

 

7,590

 

 

7,590

 

20,854

 

 

20,854

 

Reissuance (purchase) of treasury stock - net

 

3,277

 

 

3,277

 

(2,993

)

 

(2,993

)

Other (primarily stock compensation)

 

4,270

 

 

4,270

 

(606

)

 

(606

)

Dividends on common stock

 

(172,344

)

 

(172,344

)

(171,630

)

 

(171,630

)

Net capital activities by noncontrolling interests

 

 

(2,976

)

(2,976

)

 

(3,030

)

(3,030

)

Ending balance, September 30

 

$

4,056,242

 

$

129,342

 

$

4,185,584

 

$

3,894,085

 

$

108,910

 

$

4,002,995

 

 

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 2010 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 September 30, 2012, APS had a regulatory liability of $47 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 $48 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

 

As of September 30, 2012, our contractual obligations for renewable energy credits increased approximately $215 million from December 31, 2011 as discussed in the 2011 Form 10-K.  As of September 30, 2012, the updated contractual obligations related to our renewable energy credits are as follows (dollars in millions):

 

Year

 

2012

 

2013

 

2014

 

2015

 

2016

 

Thereafter

 

Total

 

Renewable Energy Credits

 

$

46

 

$

39

 

$

44

 

$

44

 

$

44

 

$

573

 

$

790

 

 

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 and ultimately remanded to the FERC for further consideration.  On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001.  FERC rejected a market-wide remedy approach and instead directed that buyers seeking refunds must demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.

 

The first phase of the hearing is currently expected to commence in April 2013.  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 $2 million.  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.

 

Climate Change Lawsuit

 

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law.  The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages.  In June 2008, the defendants filed motions to dismiss the action, which were granted.  The plaintiffs filed an appeal with the Ninth Circuit Court of Appeals in November 2009.  On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.

 

On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants.  However, the Court left open the issue of whether such claims may be available under state law.  On September 21, 2012, a three-judge panel of the Ninth Circuit affirmed the district court’s dismissal of the Kivalina plaintiffs’ federal common law public nuisance action.  The court declined to address any other issue raised by the parties, including the plaintiffs’ state nuisance law claim.  On October 4, 2012, the plaintiffs filed a petition for rehearing by the entire Ninth Circuit.  APS continues to believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

 

Southwest Power Outage

 

On September 8, 2011 at approximately 3:30PM, a 500 kilovolt (“kV”) transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS.  At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly.  Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.

 

Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico.  A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected.  Service to all affected APS customers was restored by 9:15PM on September 8.  Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9.  APS has an internal review of the September 8 events underway.

 

The FERC and the North American Electric Reliability Corporation (“NERC”) conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analysis and conclusions as to the causes of the events.  The report includes recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination.  The Joint Report does not address potential reliability violations or an assessment of responsibility of the parties involved.

 

APS cannot predict the timing, results or potential impacts of any further inquiries into the September 8 events, or any claims that may be made as a result of the outages.  If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that a violation is found to have been in existence.

 

Clean Air Act Lawsuit

 

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act.  Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards (“NSPS”) program.  Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the NSPS.  The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project.  On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss, which are pending.  APS believes the claims in this matter are without merit and will vigorously defend against them.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

 

Financial Assurances

 

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At September 30, 2012, approximately $76 million of letters of credit were outstanding to support existing variable interest rate pollution control bonds of a similar amount.  The letters of credit are available to fund the payment of principal of and interest on such debt obligations.  One of these letters of credit expires in 2015 and two expire in 2016.  APS has also entered into letters of credit to support obligations to 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 will expire in 2015 and totaled approximately $42 million at September 30, 2012.  Additionally, APS has issued letters of credit to support collateral obligations under certain natural gas tolling contracts and hedge contracts entered into with third parties. At September 30, 2012, $65 million of such letters of credit were outstanding.  Two of these letters of credit will expire in 2013 and one will expire in 2015.

 

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.

 

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 and nine months ended September 30, 2012 and 2011 (dollars in thousands):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Other income:

 

 

 

 

 

 

 

 

 

Interest income

 

$

307

 

$

429

 

$

1,018

 

$

1,364

 

Investment gains — net

 

 

 

 

1,249

 

Miscellaneous

 

113

 

12

 

339

 

17

 

Total other income

 

$

420

 

$

441

 

$

1,357

 

$

2,630

 

 

 

 

 

 

 

 

 

 

 

Other expense:

 

 

 

 

 

 

 

 

 

Non-operating costs

 

$

(1,645

)

$

(1,807

)

$

(5,885

)

$

(4,925

)

Investment losses — net

 

(2,254

)

(57

)

(2,366

)

 

Miscellaneous

 

(1,797

)

(1,188

)

(4,182

)

(2,996

)

Total other expense

 

$

(5,696

)

$

(3,052

)

$

(12,433

)

$

(7,921

)

 

Earnings Per Share
Earnings Per Share

 

 

12.          Earnings Per Share

 

The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2012 and 2011:

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Basic earnings per share:

 

 

 

 

 

 

 

 

 

Income from continuing operations attributable to common shareholders

 

$

2.23

 

$

2.25

 

$

3.29

 

$

2.90

 

Income (loss) from discontinued operations

 

 

0.09

 

(0.01

)

0.10

 

Earnings per share — basic

 

$

2.23

 

$

2.34

 

$

3.28

 

$

3.00

 

 

 

 

 

 

 

 

 

 

 

Diluted earnings per share:

 

 

 

 

 

 

 

 

 

Income from continuing operations attributable to common shareholders

 

$

2.21

 

$

2.24

 

$

3.26

 

$

2.88

 

Income (loss) from discontinued operations