PINNACLE WEST CAPITAL CORP, 10-Q filed on 10/31/2014
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2014
Oct. 24, 2014
Entity Information [Line Items]
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2014 
 
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
 
110,450,009 
Document Fiscal Year Focus
2014 
 
Document Fiscal Period Focus
Q3 
 
Arizona Public Service Company
 
 
Entity Information [Line Items]
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY  
 
Entity Central Index Key
0000007286  
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2014 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
71,264,947 
Document Fiscal Year Focus
2014 
 
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, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
OPERATING REVENUES
$ 1,172,667 
$ 1,152,392 
$ 2,765,182 
$ 2,754,866 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
382,361 
350,953 
923,001 
859,216 
Operations and maintenance
223,418 
233,323 
647,522 
685,873 
Depreciation and amortization
103,660 
107,388 
310,582 
317,410 
Taxes other than income taxes
40,850 
43,256 
130,699 
124,091 
Other expenses
603 
1,784 
2,320 
5,853 
Total
750,892 
736,704 
2,014,124 
1,992,443 
OPERATING INCOME
421,775 
415,688 
751,058 
762,423 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
7,038 
5,569 
21,979 
18,698 
Other income
2,366 
160 
7,514 
1,387 
Other expense
(4,193)
(7,435)
(9,385)
(13,421)
Total
5,211 
(1,706)
20,108 
6,664 
INTEREST EXPENSE
 
 
 
 
Interest charges
47,626 
50,587 
152,346 
151,372 
Allowance for borrowed funds used during construction
(3,479)
(3,235)
(11,039)
(10,861)
Total
44,147 
47,352 
141,307 
140,511 
INCOME BEFORE INCOME TAXES
382,839 
366,630 
629,859 
628,576 
INCOME TAXES
134,753 
131,912 
215,698 
221,424 
NET INCOME
248,086 
234,718 
414,161 
407,152 
Less: Net income attributable to noncontrolling interests (Note 6)
4,125 
8,555 
21,976 
25,338 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
243,961 
226,163 
392,185 
381,814 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
110,686 
110,009 
110,579 
109,935 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
111,103 
111,053 
110,962 
110,913 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 2.20 
$ 2.06 
$ 3.55 
$ 3.47 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 2.20 
$ 2.04 
$ 3.53 
$ 3.44 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
 
 
$ 1.14 
$ 1.09 
Arizona Public Service Company
 
 
 
 
ELECTRIC OPERATING REVENUES
1,172,190 
1,151,535 
2,763,315 
2,752,427 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
382,362 
350,953 
923,001 
859,216 
Operations and maintenance
212,430 
222,617 
628,774 
668,319 
Depreciation and amortization
103,638 
107,364 
310,512 
317,338 
Income taxes
145,217 
143,335 
233,067 
241,347 
Taxes other than income taxes
40,615 
43,015 
130,002 
123,366 
Total
884,262 
867,284 
2,225,356 
2,209,586 
OPERATING INCOME
287,928 
284,251 
537,959 
542,841 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Income taxes
4,235 
4,123 
7,013 
9,555 
Allowance for equity funds used during construction
7,038 
5,569 
21,979 
18,698 
Other income
2,613 
721 
8,596 
3,012 
Other expense
(3,226)
(4,615)
(9,757)
(15,755)
Total
10,660 
5,798 
27,831 
15,510 
INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
44,440 
47,214 
141,799 
140,978 
Interest on short-term borrowings
1,435 
1,553 
4,485 
4,950 
Debt discount, premium and expense
1,020 
1,008 
3,085 
3,001 
Allowance for borrowed funds used during construction
(3,479)
(3,235)
(11,039)
(10,861)
Total
43,416 
46,540 
138,330 
138,068 
NET INCOME
255,172 
243,509 
427,460 
420,283 
Less: Net income attributable to noncontrolling interests (Note 6)
4,125 
8,555 
21,976 
25,338 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 251,047 
$ 234,954 
$ 405,484 
$ 394,945 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
NET INCOME
$ 248,086 
$ 234,718 
$ 414,161 
$ 407,152 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(91)
(145)
(472)
(247)
Reclassification of net realized loss, net of tax benefit
5,939 
14,310 
11,009 
23,685 
Pension and other postretirement benefits activity, net of tax benefit (expense)
5,967 
957 
5,114 
1,235 
Total other comprehensive income
11,815 
15,122 
15,651 
24,673 
COMPREHENSIVE INCOME
259,901 
249,840 
429,812 
431,825 
Less: Comprehensive income attributable to noncontrolling interests
4,125 
8,555 
21,976 
25,338 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
255,776 
241,285 
407,836 
406,487 
Arizona Public Service Company
 
 
 
 
NET INCOME
255,172 
243,509 
427,460 
420,283 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(91)
(145)
(472)
(247)
Reclassification of net realized loss, net of tax benefit
5,940 
14,310 
11,010 
23,684 
Pension and other postretirement benefits activity, net of tax benefit (expense)
735 
951 
18 
1,222 
Total other comprehensive income
6,584 
15,116 
10,556 
24,659 
COMPREHENSIVE INCOME
261,756 
258,625 
438,016 
444,942 
Less: Comprehensive income attributable to noncontrolling interests
4,125 
8,555 
21,976 
25,338 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 257,631 
$ 250,070 
$ 416,040 
$ 419,604 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Net unrealized gain (loss), tax benefit (expense)
$ 58 
$ 95 
$ (566)
$ 162 
Reclassification of net realized loss, tax benefit
3,833 
9,348 
6,417 
15,471 
Pension and other postretirement benefits activity, tax benefit (expense)
(3,852)
(625)
(3,724)
(807)
Arizona Public Service Company
 
 
 
 
Net unrealized gain (loss), tax benefit (expense)
58 
95 
(566)
162 
Reclassification of net realized loss, tax benefit
3,833 
9,348 
6,417 
15,471 
Pension and other postretirement benefits activity, tax benefit (expense)
$ (474)
$ (621)
$ (252)
$ (798)
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 10,471 
$ 9,526 
Customer and other receivables
391,179 
299,904 
Accrued unbilled revenues
156,036 
96,796 
Allowance for doubtful accounts
(3,462)
(3,203)
Materials and supplies (at average cost)
230,220 
221,682 
Fossil fuel (at average cost)
32,836 
38,028 
Deferred income taxes
61,201 
91,152 
Income tax receivable (Note 5)
0 
135,517 
Assets from risk management activities (Note 7)
11,863 
17,169 
Deferred fuel and purchased power regulatory asset (Note 3)
15,911 
20,755 
Other regulatory assets (Note 3)
94,004 
76,388 
Other current assets
40,673 
39,895 
Total current assets
1,040,932 
1,043,609 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
17,438 
23,815 
Nuclear decommissioning trust (Note 13)
690,226 
642,007 
Other assets
60,427 
60,875 
Total investments and other assets
768,091 
726,697 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
15,251,009 
15,200,464 
Accumulated depreciation and amortization
(5,308,661)
(5,300,219)
Net
9,942,348 
9,900,245 
Construction work in progress
673,265 
581,369 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
122,222 
125,125 
Intangible assets, net of accumulated amortization
127,560 
157,689 
Nuclear fuel, net of accumulated amortization
138,179 
124,557 
Total property, plant and equipment
11,003,574 
10,888,985 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
836,618 
711,712 
Assets for other postretirement benefits (Note 4)
180,527 
0 
Other
150,606 
137,683 
Total deferred debits
1,167,751 
849,395 
TOTAL ASSETS
13,980,348 
13,508,686 
CURRENT LIABILITIES
 
 
Accounts payable
278,835 
284,516 
Accrued taxes (Note 5)
249,932 
130,998 
Accrued interest
41,289 
48,351 
Common dividends payable
0 
62,528 
Short-term borrowings (Note 2)
19,150 
153,125 
Current maturities of long-term debt (Note 2)
368,841 
540,424 
Customer deposits
73,468 
76,101 
Liabilities from risk management activities (Note 7)
27,622 
31,892 
Liabilities for asset retirements
39,416 
32,896 
Regulatory liabilities (Note 3)
154,027 
99,273 
Other current liabilities
195,938 
158,540 
Total current liabilities
1,448,518 
1,618,644 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,037,801 
2,796,465 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,505,150 
2,351,882 
Regulatory liabilities (Note 3)
1,034,515 
801,297 
Liabilities for asset retirements (Note 16)
350,211 
313,833 
Liabilities for pension and other postretirement benefits (Note 4)
233,292 
513,628 
Liabilities from risk management activities (Note 7)
24,385 
70,315 
Customer advances
123,136 
114,480 
Coal mine reclamation
209,695 
207,453 
Deferred investment tax credit
177,567 
152,361 
Unrecognized tax benefits (Note 5)
14,601 
42,209 
Other
177,464 
185,659 
Total deferred credits and other
4,850,016 
4,753,117 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 8)
 
 
Common stock, no par value; authorized 150,000,000 shares, 110,468,956 and 110,280,703 issued at respective dates
2,502,217 
2,491,558 
Treasury stock at cost; 22,293 and 98,944 shares at respective dates
(106)
(4,308)
Total common stock
2,502,111 
2,487,250 
Retained earnings
2,052,207 
1,785,273 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(49,881)
(54,995)
Derivative instruments
(12,521)
(23,058)
Total accumulated other comprehensive loss
(62,402)
(78,053)
Total shareholders’ equity
4,491,916 
4,194,470 
Noncontrolling interests (Note 6)
152,097 
145,990 
Total equity
4,644,013 
4,340,460 
TOTAL LIABILITIES AND EQUITY
13,980,348 
13,508,686 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
5,155 
3,725 
Customer and other receivables
391,002 
299,055 
Accrued unbilled revenues
156,036 
96,796 
Allowance for doubtful accounts
(3,462)
(3,203)
Materials and supplies (at average cost)
230,220 
221,682 
Fossil fuel (at average cost)
32,836 
38,028 
Income tax receivable (Note 5)
0 
135,179 
Assets from risk management activities (Note 7)
11,863 
17,169 
Deferred fuel and purchased power regulatory asset (Note 3)
15,911 
20,755 
Other regulatory assets (Note 3)
94,004 
76,388 
Deferred income taxes
54,746 
0 
Other current assets
40,078 
39,153 
Total current assets
1,028,389 
944,727 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
17,438 
23,815 
Nuclear decommissioning trust (Note 13)
690,226 
642,007 
Other assets
33,370 
33,709 
Total investments and other assets
741,034 
699,531 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
15,247,757 
15,196,598 
Accumulated depreciation and amortization
(5,305,566)
(5,296,501)
Net
9,942,191 
9,900,097 
Construction work in progress
673,265 
581,369 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
122,222 
125,125 
Intangible assets, net of accumulated amortization
127,405 
157,534 
Nuclear fuel, net of accumulated amortization
138,179 
124,557 
Total property, plant and equipment
11,003,262 
10,888,682 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
836,618 
711,712 
Assets for other postretirement benefits (Note 4)
177,455 
0 
Unamortized debt issue costs
24,599 
21,860 
Other
124,654 
114,865 
Total deferred debits
1,163,326 
848,437 
TOTAL ASSETS
13,936,011 
13,381,377 
CURRENT LIABILITIES
 
 
Accounts payable
272,672 
281,237 
Accrued taxes (Note 5)
300,646 
122,460 
Accrued interest
41,014 
48,132 
Common dividends payable
0 
62,500 
Short-term borrowings (Note 2)
19,150 
153,125 
Current maturities of long-term debt (Note 2)
368,841 
540,424 
Customer deposits
73,468 
76,101 
Deferred income taxes
0 
2,033 
Liabilities from risk management activities (Note 7)
27,622 
31,892 
Liabilities for asset retirements
39,416 
32,896 
Regulatory liabilities (Note 3)
154,027 
99,273 
Other current liabilities
174,950 
130,774 
Total current liabilities
1,471,806 
1,580,847 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,494,946 
2,347,724 
Regulatory liabilities (Note 3)
1,034,515 
801,297 
Liabilities for asset retirements (Note 16)
350,211 
313,833 
Liabilities for pension and other postretirement benefits (Note 4)
203,887 
476,017 
Liabilities from risk management activities (Note 7)
24,385 
70,315 
Customer advances
123,136 
114,480 
Coal mine reclamation
209,695 
207,453 
Deferred investment tax credit
177,567 
152,361 
Unrecognized tax benefits (Note 5)
44,559 
42,209 
Other
136,782 
148,502 
Total deferred credits and other
4,799,683 
4,674,191 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 8)
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
2,084,582 
1,804,398 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(30,295)
(30,313)
Derivative instruments
(12,521)
(23,059)
Total accumulated other comprehensive loss
(42,816)
(53,372)
Total shareholders’ equity
4,599,624 
4,308,884 
Noncontrolling interests (Note 6)
152,097 
145,990 
Total equity
4,751,721 
4,454,874 
Long-term debt less current maturities (Note 2)
2,912,801 
2,671,465 
Total capitalization
7,664,522 
7,126,339 
TOTAL LIABILITIES AND EQUITY
$ 13,936,011 
$ 13,381,377 
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
Sep. 30, 2014
Dec. 31, 2013
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
 
 
Common stock, par value (in dollars per share)
$ 0 
$ 0 
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
110,468,956 
110,280,703 
Treasury stock at cost, shares
22,293 
98,944 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 414,161,000 
$ 407,152,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
371,722,000 
377,971,000 
Deferred fuel and purchased power
(26,880,000)
13,093,000 
Deferred fuel and purchased power amortization
31,724,000 
23,158,000 
Allowance for equity funds used during construction
(21,979,000)
(18,698,000)
Deferred income taxes
136,777,000 
256,132,000 
Deferred investment tax credit
25,206,000 
16,164,000 
Change in derivative instruments fair value
300,000 
537,000 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(149,053,000)
(178,029,000)
Accrued unbilled revenues
(59,240,000)
(37,710,000)
Materials, supplies and fossil fuel
(3,346,000)
(8,914,000)
Income tax receivable
135,517,000 
(131,128,000)
Other current assets
(4,428,000)
(12,246,000)
Accounts payable
(7,171,000)
44,704,000 
Accrued taxes
118,934,000 
58,919,000 
Other current liabilities
48,407,000 
4,096,000 
Change in margin and collateral accounts — assets
(475,000)
(327,000)
Change in margin and collateral accounts — liabilities
(20,875,000)
15,000,000 
Change in long-term income tax receivable
0 
137,270,000 
Change in unrecognized tax benefits
1,744,000 
(57,585,000)
Change in other long-term assets
(50,005,000)
(24,345,000)
Change in other long-term liabilities
(54,122,000)
(2,884,000)
Net cash flow provided by operating activities
886,918,000 
882,330,000 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(618,658,000)
(581,515,000)
Contributions in aid of construction
8,537,000 
34,910,000 
Allowance for borrowed funds used during construction
(11,039,000)
(10,861,000)
Proceeds from nuclear decommissioning trust sales
269,276,000 
363,944,000 
Investment in nuclear decommissioning trust
(282,212,000)
(376,881,000)
Other
339,000 
(1,553,000)
Net cash flow used for investing activities
(633,757,000)
(571,956,000)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
574,126,000 
136,307,000 
Repayment of long-term debt
(503,583,000)
(72,777,000)
Short-term borrowings and payments — net
(133,975,000)
(92,175,000)
Dividends paid on common stock
(187,778,000)
(174,485,000)
Dividends paid on common stock
14,860,000 
10,396,000 
Distributions to noncontrolling interests
(15,869,000)
(9,197,000)
Other
3,000 
812,000 
Net cash flow used for financing activities
(252,216,000)
(201,119,000)
NET INCREASE IN CASH AND CASH EQUIVALENTS
945,000 
109,255,000 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
9,526,000 
26,202,000 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
10,471,000 
135,457,000 
Cash paid (received) during the period for:
 
 
Income taxes, net of refunds
(131,154,000)
3,412,000 
Interest, net of amounts capitalized
145,285,000 
141,047,000 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
24,135,000 
11,377,000 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
427,460,000 
420,283,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
371,651,000 
377,899,000 
Deferred fuel and purchased power
(26,880,000)
13,093,000 
Deferred fuel and purchased power amortization
31,724,000 
23,158,000 
Allowance for equity funds used during construction
(21,979,000)
(18,698,000)
Deferred income taxes
77,435,000 
256,253,000 
Deferred investment tax credit
25,206,000 
16,164,000 
Change in derivative instruments fair value
300,000 
537,000 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(149,725,000)
(179,494,000)
Accrued unbilled revenues
(59,240,000)
(37,710,000)
Materials, supplies and fossil fuel
(3,346,000)
(8,914,000)
Income tax receivable
135,179,000 
(125,509,000)
Other current assets
(4,575,000)
(11,449,000)
Accounts payable
(10,055,000)
43,886,000 
Accrued taxes
178,186,000 
61,649,000 
Other current liabilities
55,127,000 
1,073,000 
Change in margin and collateral accounts — assets
(474,000)
(327,000)
Change in margin and collateral accounts — liabilities
(20,875,000)
15,000,000 
Change in long-term income tax receivable
0 
137,665,000 
Change in unrecognized tax benefits
1,744,000 
(57,585,000)
Change in other long-term assets
(49,635,000)
(28,686,000)
Change in other long-term liabilities
(54,940,000)
691,000 
Net cash flow provided by operating activities
902,288,000 
898,979,000 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(618,658,000)
(581,515,000)
Contributions in aid of construction
8,537,000 
34,910,000 
Allowance for borrowed funds used during construction
(11,039,000)
(10,861,000)
Proceeds from nuclear decommissioning trust sales
269,276,000 
363,944,000 
Investment in nuclear decommissioning trust
(282,212,000)
(376,881,000)
Other
339,000 
(1,561,000)
Net cash flow used for investing activities
(633,757,000)
(571,964,000)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
574,126,000 
136,307,000 
Repayment of long-term debt
(503,583,000)
(72,777,000)
Short-term borrowings and payments — net
(133,975,000)
(92,175,000)
Dividends paid on common stock
(187,800,000)
(179,600,000)
Distributions to noncontrolling interests
(15,869,000)
(9,197,000)
Net cash flow used for financing activities
(267,101,000)
(217,442,000)
NET INCREASE IN CASH AND CASH EQUIVALENTS
1,430,000 
109,573,000 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
3,725,000 
3,499,000 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
5,155,000 
113,072,000 
Cash paid (received) during the period for:
 
 
Income taxes, net of refunds
(119,440,000)
3,412,000 
Interest, net of amounts capitalized
142,364,000 
138,626,000 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 24,135,000 
$ 11,377,000 
Consolidation and Nature of Operations
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, Bright Canyon Energy Corporation ("BCE") 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 Nuclear Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”) (see Note 6 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 have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).  Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading.
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Cash paid (received) during the period for:
 
 
 
Income taxes, net of refunds
$
(131,154
)
 
$
3,412

Interest, net of amounts capitalized
145,285

 
141,047

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
24,135

 
$
11,377

Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters
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
 
On May 9, 2014, Pinnacle West replaced its $200 million revolving credit facility that would have matured in November 2016, with a new $200 million facility that matures in May 2019.  At September 30, 2014, the facility 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, 2014, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS
 
On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029.  On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024.  On January 15, 2014, both of these series of bonds were canceled and refinanced as described below.
 
On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of Southern California Edison’s (“SCE”) 48% ownership interest in each of Units 4 and 5 of the Four Corners Power Plant (“Four Corners”) and to replenish cash used in 2013 to re-acquire the two series of tax-exempt indebtedness listed above.
 
On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E, due 2029 in connection with the mandatory tender provisions for this indebtedness.  On May 14, 2014, APS remarketed all $36 million of the 2009 Series A Bonds, which are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2014.  We expect to remarket or refinance all $64 million of the 2009 Series D Bonds and 2009 Series E Bonds within the next twelve months, which were classified as current maturities of long-term debt at December 31, 2013.
 
On May 9, 2014, APS replaced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019.
 
On May 30, 2014, APS purchased all $38 million of the Navajo County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034, and on June 1, 2014, APS purchased a total of $64 million of the Navajo 2009 Series B Bonds and 2009 Series C Bonds, in each case, in connection with the mandatory tender provisions for this indebtedness.  On September 23, 2014, APS remarketed all $38 million of the 2009 Series A Bonds, which are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2014. On October 1, 2014, APS remarketed all $32 million of the 2009 Series C Bonds. We expect to remarket or refinance all $32 million of the 2009 Series B Bonds within the next twelve months.  These bonds were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2013.
 
On June 1, 2014, APS remarketed all $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2014.
 
On June 18, 2014, APS issued $250 million of 3.35% unsecured senior notes that mature on June 15, 2024.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $300 million aggregate principal amount of 5.80% senior notes due September 30, 2014.
 
At September 30, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and the $500 million facility that matures in May 2019 (see above).  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, 2014, APS had $19 million of commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.
 
See “Financial Assurances” in Note 9 for a 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.  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 estimated fair value of our long-term debt, including current maturities (dollars in millions):

 
As of September 30, 2014
 
As of December 31, 2013
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125

 
$
125

 
$
125

 
$
125

APS
3,282

 
3,662

 
3,212

 
3,454

Total
$
3,407

 
$
3,787

 
$
3,337

 
$
3,579


 
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 September 30, 2014, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.6 billion, and total capitalization was approximately $8.1 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.2 billion, assuming APS’s total capitalization remains the same.
Regulatory Matters
Regulatory Matters
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 by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “2012 Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
Settlement Agreement
 
The 2012 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 fuel and 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 2012 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 2012 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 2012 Settlement Agreement.
 
Other key provisions of the 2012 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 increases in property taxes 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 acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);
 
•
Implementation of a Lost Fixed Cost Recovery (“LFCR”) 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 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 APS’s 2009 retail rate case settlement agreement (the “2009 Settlement Agreement”);
 
•
Allowing a negative credit that existed in the PSA rate 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 2012 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 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs 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 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 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information.
 
In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program.  In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 20 MW of APS-owned residential solar. This matter is still pending with the ACC and the ACC staff has recommended that it be addressed in our 2015 RES implementation plan.
 
On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million.
 
Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan (“DSM Plan”) for review by and approval of the ACC.
 
On June 1, 2012, APS filed its 2013 DSM Plan.  In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.
 
On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015.
 
On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.
 
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 for 2014 and 2013 (dollars in millions):
 
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Beginning balance
$
21

 
$
73

Deferred fuel and purchased power costs — current period
27

 
(13
)
Amounts charged to customers
(32
)
 
(23
)
Ending balance
$
16

 
$
37


 
The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the United States Federal 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 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 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- or under-collected amounts.
 
Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014.
 
Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.
 
APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014.
 
Deregulation
 
On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and no future workshops are currently scheduled.

Net Metering
 
On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The new policy will be in effect until the next APS rate case.
 
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.  The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement.
 
In May 2014, the ACC began conducting a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.
 
On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015.  The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design. On August 12, 2014, the ACC Commissioners voted to lift the requirement that APS file its next general rate case by June 2015. On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. APS supports the concept of considering rate design outside of its  next rate case, but cannot predict whether the ACC will ultimately approve staff’s proposal.
   
Four Corners
 
On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  If approved, these adjustments would result in an average bill impact to residential customers of approximately 2%.  This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $67 million as of September 30, 2014.  ACC staff and other intervenors have filed testimony in this matter with the ACC, and APS has filed rebuttal testimony.  Both ACC staff and the Residential Utility Customer Office have proposed adjustments to the return to be applied to the Four Corners investments until APS’s next rate case, which would result in a lower level of recovery than proposed by APS.  Hearings on this matter are completed and we anticipate a decision by the end of 2014.  APS cannot predict the outcome of this matter.
 
As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  Both requests for rehearing were denied on August 14, 2014. Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Cholla

In the third quarter of 2014, after considering the costs to comply with environmental regulations, APS determined that it was probable that it will retire Unit 2 at the Cholla Power Plant ("Cholla") in April 2016. Specifically, on September 11, 2014, APS announced that it will close Unit 2 of Cholla by April 2016 and stop burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case.
If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($130 million as of September 30, 2014), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in millions):
 
 
Remaining
Amortization Period
 
September 30, 2014
 
December 31, 2013
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension and other postretirement benefits
(a)
 
$
—

 
$
286

 
$
—

 
$
314

Income taxes — allowance for funds used during construction (“AFUDC”) equity
2043
 
4

 
117

 
4

 
105

Deferred fuel and purchased power — mark-to-market (Note 7)
2016
 
14

 
20

 
5

 
29

Transmission vegetation management
2016
 
9

 
7

 
9

 
14

Coal reclamation
2038
 
8

 
12

 
8

 
18

Palo Verde VIEs (Note 6)
2046
 
—

 
39

 
—

 
41

Deferred compensation
2036
 
—

 
36

 
—

 
34

Deferred fuel and purchased power (b) (c)
2015
 
16

 
—

 
21

 
—

Tax expense of Medicare subsidy
2023
 
2

 
14

 
2

 
15

Loss on reacquired debt
2034
 
1

 
17

 
1

 
17

Income taxes — investment tax credit basis adjustment
2043
 
2

 
46

 
1

 
39

Pension and other postretirement benefits deferral
2015
 
6

 
—

 
8

 
4

Four Corners cost deferral
2024
 
—

 
67

 
—

 
37

Lost fixed cost recovery (b)
2015
 
33

 
—

 
25

 
—

Transmission cost adjustor (b)
2015
 
4

 
—

 
8

 
2

Retired power plant costs
2033
 
10

 
139

 
3

 
18

Deferred property taxes
(d)
 
—

 
26

 
—

 
11

Other
Various
 
1

 
11

 
2

 
14

Total regulatory assets (e)
 
 
$
110

 
$
837

 
$
97

 
$
712


(a)
This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income (“OCI”) and result in lower future revenues.  See Note 4 for further discussion.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
Per the provision of the 2012 Settlement Agreement.
(e)
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, Transmission Cost Adjustor and Other Transmission Matters.”

The detail of regulatory liabilities is as follows (dollars in millions):
 
 
Remaining
Amortization Period
 
September 30, 2014
 
December 31, 2013
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
31

 
$
284

 
$
28

 
$
303

Asset retirement obligations
(a)
 
—

 
277

 
—

 
266

Renewable energy standard (b)
2015
 
40

 
8

 
33

 
15

Income taxes — change in rates
2043
 
1

 
72

 
—

 
74

Spent nuclear fuel
2047
 
5

 
53

 
6

 
36

Deferred gains on utility property
2019
 
2

 
9

 
2

 
10

Income taxes — deferred investment tax credit
2043
 
3

 
92

 
3

 
79

Demand side management (b)
2015
 
39

 
—

 
27

 
—

Other postretirement benefits
(c)
 
33

 
221

 
—

 
—

Other
Various
 
—

 
19

 
—

 
18

Total regulatory liabilities
 
 
$
154

 
$
1,035

 
$
99

 
$
801


(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)
See Note 4.
Retirement Plans and Other Benefits
Retirement Plans and Other Benefits
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 plan 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.  On September 30, 2014 Pinnacle West announced plan design changes to the other postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan (see discussion below). The market-related value of our plan assets is their fair value at the measurement dates.
 
Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We amortized approximately $2 million for the three months ended September 30, 2014 and 2013 and $6 million for the nine months ended September 30, 2014 and 2013, respectively.  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,
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
Service cost — benefits earned during the period
$
13

 
$
16

 
$
40

 
$
48

 
$
5

 
$
6

 
$
14

 
$
18

Interest cost on benefit obligation
32

 
28

 
97

 
84

 
12

 
10

 
35

 
31

Expected return on plan assets
(39
)
 
(36
)
 
(119
)
 
(110
)
 
(13
)
 
(11
)
 
(38
)
 
(34
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost
—

 
—

 
—

 
1

 
—

 
—

 
—

 
—

Net actuarial loss
3

 
10

 
8

 
30

 
—

 
3

 
—

 
8

Net periodic benefit cost
$
9

 
$
18

 
$
26

 
$
53

 
$
4

 
$
8

 
$
11

 
$
23

Portion of cost charged to expense
$
5

 
$
10

 
$
16

 
$
29

 
$
3

 
$
5

 
$
8

 
$
14


 
Other Postretirement Benefit Plan Remeasurement

On September 30, 2014 Pinnacle West announced plan design changes to the other postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement (HRA). This will allow post-65 retirees to purchase a Medicare supplement plan on the private exchange network. The remeasurement of the benefit obligation included updating the assumptions listed in the table following and asset values. The remeasurement is expected to reduce net periodic benefit costs in 2014 by $10 million ($5 million of which will reduce expense), which will be recognized during the fourth quarter of 2014. The remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million which was offset by the related regulatory asset and accumulated other comprehensive income. As a result of this reduction, the other postretirement benefit obligation, and related regulatory asset, have been reduced to the extent that Pinnacle West will now reflect an asset for other postretirement benefits and a related regulatory liability with balances at September 30, 2014 of $181 million and $254 million, respectively.

The following table provides the assumptions used for the remeasurement at September 30, 2014:
Discount rate
 
4.41
%
Long-term rate of return
 
4.25
%
Initial healthcare cost trend rate (pre-65 participants)
 
7.50
%
Ultimate healthcare cost trend rate (pre-65 participants)
 
5.00
%
Number of years to ultimate trend rate
 
4

Medical cost subsidy trend rate (post-65 participants)
 
5.00
%


Because of the plan changes, the Company is currently in the process of seeking IRS and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new account to pay for active union employee medical costs.

Contributions
 
We have made voluntary contributions of $175 million to our pension plan in 2014. The minimum contributions for the pension plan total $141 million for the next three years under the Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016).  We expect to make contributions to the pension plan up to $100 million in 2015 and up to $25 million in 2016.
Income Taxes
Income Taxes
   Income Taxes
 
During the first quarter of 2014, a $135 million cash refund was received from the Internal Revenue Service (“IRS”) related to tax returns for the years ended December 31, 2008 and 2009.  This refund was classified as a current income tax receivable at December 31, 2013.
 
Net income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 6).  As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.
 
In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  As a result of this guidance, $30 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Condensed Consolidated Balance Sheets as of September 30, 2014. With regard to the APS Condensed Consolidated Balance Sheets, all unrecognized tax benefits are presented as a liability, as no deferred income tax assets for a net operating loss, a similar tax loss, or a tax credit carryforward are available to offset these liabilities as of September 30, 2014.
 
As of September 30, 2014, the tax year ended December 31, 2010 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 2008.
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
   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 during 2014 and 2015 related to these leases.  The lease agreements include fixed rate renewal periods, which give APS the ability to utilize the assets for a significant portion of the assets’ 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.
 
On July 7, 2014, APS notified the lessor trust entities of APS’s intent to exercise the fixed rate lease renewal options.  The length of the renewal options will result in APS retaining the assets through 2023 under one lease and 2033 under the other two leases.  APS will be required to make lease payments of approximately $23 million annually for the period 2016 through 2023, and about $16 million annually for the period 2024 through 2033.  At the end of the lease renewal periods, APS will  have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.
 
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, 2014 of $4 million and $22 million, respectively, and for the three and nine months ended September 30, 2013 of $9 million and $25 million, respectively, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders remains the same.  The July 7, 2014 lease extension results in the VIEs accounting for the transaction as a new lease agreement. 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, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):
 
 
September 30, 2014
 
December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
122

 
$
125

Current maturities of long-term debt
37

 
26

Long-term debt excluding current maturities
1

 
13

Equity — Noncontrolling interests
152

 
146


 
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 leases.
 
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, 2014, APS would have been required to pay the noncontrolling equity participants approximately $138 million and assume $38 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 will 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
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 cash flow 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 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.  When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA.  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 12 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.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses 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, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
4,167

 
GWh
Gas
 
131

 
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, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
 
2014
 
2013
 
2014
 
2013
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(149
)
 
$
(240
)
 
$
94

 
$
(409
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(9,772
)
 
(23,658
)
 
(17,426
)
 
(39,156
)

(a)
During the three and nine months ended September 30, 2014 and 2013, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $9 million before income taxes will be reclassified from accumulated OCI 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, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended September 30,
Commodity Contracts
 
 
2014
 
2013
 
2014
 
2013
Net Gain Recognized in Income
 
Operating revenues (a)
 
$
273

 
$
196

 
$
335

 
$
400

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(23,915
)
 
(1,341
)
 
(1,003
)
 
(11,750
)
Total
 
 
 
$
(23,642
)
 
$
(1,145
)
 
$
(668
)
 
$
(11,350
)

(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed Consolidated Balance Sheets
 
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
 
We do not offset counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
 
The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013, include gross liabilities of $4 million and $5 million, respectively, of derivative instruments designated as hedging instruments.
 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2014 and December 31, 2013.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.
As of September 30, 2014:
(Dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance  Sheet
Current Assets
 
$
16,172

 
$
(4,790
)
 
$
11,382

 
$
481

 
$
11,863

Investments and Other Assets
 
20,712

 
(3,274
)
 
17,438

 
—

 
17,438

Total Assets
 
36,884

 
(8,064
)
 
28,820

 
481

 
29,301

 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
(39,236
)
 
19,357

 
(19,879
)
 
(7,743
)
 
(27,622
)
Deferred Credits and Other
 
(53,193
)
 
28,808

 
(24,385
)
 
—

 
(24,385
)
Total Liabilities
 
(92,429
)
 
48,165

 
(44,264
)
 
(7,743
)
 
(52,007
)
Total
 
$
(55,545
)
 
$
40,101

 
$
(15,444
)
 
$
(7,262
)
 
$
(22,706
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $40,101.
(c)
Represents option premiums, and cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,743 and cash margin provided to counterparties of $481.
 
As of December 31, 2013:
(Dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance  Sheet
Current Assets
 
$
24,587

 
$
(7,425
)
 
$
17,162

 
$
7

 
$
17,169

Investments and Other Assets
 
25,364

 
(1,549
)
 
23,815

 
—

 
23,815

Total Assets
 
49,951

 
(8,974
)
 
40,977

 
7

 
40,984

 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
(50,540
)
 
26,166

 
(24,374
)
 
(7,518
)
 
(31,892
)
Deferred Credits and Other
 
(72,123
)
 
1,808

 
(70,315
)
 
—

 
(70,315
)
Total Liabilities
 
(122,663
)
 
27,974

 
(94,689
)
 
(7,518
)
 
(102,207
)
Total
 
$
(72,712
)
 
$
19,000

 
$
(53,712
)
 
$
(7,511
)
 
$
(61,223
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $19,000.
(c)
Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.

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 89% of Pinnacle West’s $29 million of risk management assets as of September 30, 2014.  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 counterparties 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, 2014 (dollars in millions):
 
September 30, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position
$
92

Cash Collateral Posted
40

Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)
52


(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 $175 million if our debt credit ratings were to fall below investment grade.
Changes in Equity
Changes in Equity 
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, 2014 and 2013 (dollars in thousands):
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
Beginning balance, July 1
$
4,233,890

 
$
147,972

 
$
4,381,862

 
$
4,032,165

 
$
137,069

 
$
4,169,234

Net income
243,961

 
4,125

 
248,086

 
226,163

 
8,555

 
234,718

Other comprehensive income
11,815

 
—

 
11,815

 
15,122

 
—

 
15,122

Total comprehensive income
255,776

 
4,125

 
259,901

 
241,285

 
8,555

 
249,840

Issuance of capital stock
2,152

 
—

 
2,152

 
2,331

 
—

 
2,331

Reissuance of treasury stock — net
83

 
—

 
83

 
37

 
—

 
37

Other (primarily stock compensation)
—

 
—

 
—

 
(22
)
 
—

 
(22
)
Dividends on common stock
15

 
—

 
15

 
8

 
—

 
8

Ending balance, September 30
$
4,491,916

 
$
152,097

 
$
4,644,013

 
$
4,275,804

 
$
145,624

 
$
4,421,428

 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
Beginning balance, January 1
$
4,194,470

 
$
145,990

 
$
4,340,460

 
$
3,972,806

 
$
129,483

 
$
4,102,289

Net income
392,185

 
21,976

 
414,161

 
381,814

 
25,338

 
407,152

Other comprehensive income
15,651

 
—

 
15,651

 
24,673

 
—

 
24,673

Total comprehensive income
407,836

 
21,976

 
429,812

 
406,487

 
25,338

 
431,825

Issuance of capital stock
7,024

 
—

 
7,024

 
7,268

 
—

 
7,268

Reissuance (purchase) of treasury stock — net
4,202

 
—

 
4,202

 
(5,868
)
 
—

 
(5,868
)
Other (primarily stock compensation)
3,634

 
—

 
3,634

 
14,988

 
—

 
14,988

Dividends on common stock
(125,250
)
 
—

 
(125,250
)
 
(119,877
)
 
—

 
(119,877
)
Net capital activities by noncontrolling interests
—

 
(15,869
)
 
(15,869
)
 
—

 
(9,197
)
 
(9,197
)
Ending balance, September 30
$
4,491,916

 
$
152,097

 
$
4,644,013

 
$
4,275,804

 
$
145,624

 
$
4,421,428

Changes in Equity 
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 September 30, 2014 and 2013 (dollars in thousands): 
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
Beginning balance, July 1
$
4,342,093

 
$
147,972

 
$
4,490,065

 
$
4,142,726

 
$
137,070

 
$
4,279,796

Net income
251,047

 
4,125

 
255,172

 
234,954

 
8,555

 
243,509

OCI
6,584

 
—

 
6,584

 
15,116

 
—

 
15,116

Total comprehensive income
257,631

 
4,125

 
261,756

 
250,070

 
8,555

 
258,625

Dividends on common stock
(100
)
 
—

 
(100
)
 
—

 
—

 
—

Other
—

 
—

 
—

 
1

 
(1
)
 
—

Ending balance, September 30
$
4,599,624

 
$
152,097

 
$
4,751,721

 
$
4,392,797

 
$
145,624

 
$
4,538,421

 
 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
Beginning balance, January 1
$
4,308,884

 
$
145,990

 
$
4,454,874

 
$
4,093,000

 
$
129,483

 
$
4,222,483

Net income
405,484

 
21,976

 
427,460

 
394,945

 
25,338

 
420,283

OCI
10,556

 
—

 
10,556

 
24,659

 
—

 
24,659

Total comprehensive income
416,040

 
21,976

 
438,016

 
419,604

 
25,338

 
444,942

Dividends on common stock
(125,300
)
 
—

 
(125,300
)
 
(119,800
)
 
—

 
(119,800
)
Net capital activities by noncontrolling interests
—

 
(15,869
)
 
(15,869
)
 
—

 
(9,197
)
 
(9,197
)
Other
—

 
—

 
—

 
(7
)
 
—

 
(7
)
Ending balance, September 30
$
4,599,624

 
$
152,097

 
$
4,751,721

 
$
4,392,797

 
$
145,624

 
$
4,538,421

Commitments and Contingencies
Commitments and Contingencies
  Commitments and Contingencies
 
Palo Verde Nuclear Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy (“DOE”) in the United States Court of Federal Claims (“Court of Federal Claims”).  The lawsuit seeks to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Protection Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million, which was recorded as an adjustment to a regulatory liability and had no impact on current income.

 Nuclear Insurance
 
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.6 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers.  The remaining balance of $13.2 billion of liability coverage 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 retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment of approximately $16.5 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 replacement 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 premium 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 $20 million for each retrospective premium 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 $53 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, sublimits and exclusions.

Contractual Obligations
  
On July 7, 2014, APS notified the Palo Verde Sale Leaseback lessor trust entities of APS’s intent to exercise fixed rate lease renewal options.  Under the extended lease terms, APS will be required to make lease payments to the lessors of approximately $23 million annually for the period 2016 through 2023, and about $16 million annually for the period 2024 through 2033.  See Note 6.

During the quarter our purchase obligations have increased by about $230 million primarily relating to gas generation projects. The expected payments to be made are $57 million in 2015, $122 million in 2016, $18 million in 2017, and $31 million in 2018.

Other than the items described above, there have been no material changes, as of September 30, 2014, outside the normal course of business in contractual obligations from the information provided in our 2013 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.
 
Superfund-Related Matters
 
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 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 EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with 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 expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  We are unable to predict the outcome of this matter; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
 
Southwest Power Outage
 
Regulatory.  On September 8, 2011 at approximately 3:30 PM, 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.  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 9:15 PM on September 8.  Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9.
 
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 included 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 did not address potential reliability violations or an assessment of responsibility of the parties involved.
 
On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS.  FERC Staff alleged that each of the named entities violated varying numbers of NERC Reliability Standards.  APS was alleged to have violated seven Reliability Standard Requirements.  The allegations of violations were preliminary determinations by FERC Staff and did not constitute findings by FERC itself that any violations had occurred.
 
On July 7, 2014, FERC approved a Stipulation and Consent Agreement among FERC’s Office of Enforcement, NERC and APS which resolves all civil and administrative disputes within the jurisdiction of FERC concerning the September 8 event, including FERC’s and NERC’s investigations.  In the settlement, APS neither admitted nor denied alleged violations of four Reliability Standard Requirements.  APS agreed to pay a civil penalty of $3.25 million, of which $2 million is to be paid in equal parts to the Department of the Treasury and NERC and $1.25 million will be credited as a partial civil penalty offset in exchange for APS completing certain reliability enhancements.
 
Litigation.  On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service.  APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.  The appeal is now pending before the Ninth Circuit Court of Appeals.  We are unable to predict the outcome of this matter.
 
Clean Air Act Citizen 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 New Source Review (“NSR”) 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 environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR 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.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss.  We are unable to predict the outcome of this matter.

Environmental Matters
 
APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCRs”).  These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.  Associated capital expenditures or operating costs could be material.  APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery.  The following proposed and final rules involve material compliance costs to APS.
 
Regional Haze Rules.  APS has received the final rulemakings imposing new requirements on Four Corners, Cholla and the Navajo Generating Station (“Navajo Plant”).  EPA and Arizona Department of Environmental Quality (“ADEQ”) will require these plants to install pollution control equipment that constitutes the “best available retrofit technology” (“BART”) to lessen the impacts of emissions on visibility surrounding the plants.  Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be at least $350 million.  APS estimates that its share of costs for upgrades at Navajo, based on EPA’s Federal Implementation Plan (“FIP”), could be up to approximately $200 million.  In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process. As described under "Regional Haze Rules - Cholla" below, APS filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million. However, in September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved.
 
Mercury and Air Toxic Standards.  In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants.  APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS's compromise proposal discussed above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  Salt River Project Agricultural Improvement and Power District (“SRP”), the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.
 
Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, greenhouse gas (“GHG”) emissions (such as the EPA’s proposed “Clean Power Plan” rule issued in accordance with President Obama’s Climate Action Plan), and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.
 
Regional Haze Rules — Cholla
 
APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan (“SIP”) and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  Briefing in the case was completed in February 2014, and the parties are waiting for the court to schedule oral argument.
 
New Mexico Tax Matter
 
On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”).  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013.  The New Mexico Taxation and Revenue Department denied the refund claim.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  We cannot predict the timing or outcome of this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
 
Financial Assurances
 
APS has entered into various agreements that require letters of credit for financial assurance purposes.  At September 30, 2014, approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount.  The letters of credit are available to fund the payment of principal and interest of 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 certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $23 million at September 30, 2014.  Additionally, APS has issued a letter of credit to support collateral obligations under a natural gas tolling contract entered into with a third party.  At September 30, 2014, that letter of credit totaled $5 million and 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.
 
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at September 30, 2014.
Other Income and Other Expense
Other Income and Other Expense 
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, 2014 and 2013 (dollars in thousands):

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Other income:
 

 
 

 
 

 
 

Interest income
$
103

 
$
116

 
$
849

 
$
1,291

Miscellaneous
2,263

 
44

 
6,665

 
96

Total other income
$
2,366

 
$
160

 
$
7,514

 
$
1,387

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(1,985
)
 
$
(2,028
)
 
$
(6,976
)
 
$
(5,951
)
Investment losses — net
(118
)
 
(3,435
)
 
(364
)
 
(3,643
)
Miscellaneous
(2,090
)
 
(1,972
)
 
(2,045
)
 
(3,827
)
Total other expense
$
(4,193
)
 
$
(7,435
)
 
$
(9,385
)
 
$
(13,421
)
Other Income and Other Expense 
Other Income and Other Expense
 
The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2014 and 2013 (dollars in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Other income:
 

 
 

 
 

 
 

Interest income
$
31

 
$
2

 
$
585

 
$
1,061

Miscellaneous
2,582

 
719

 
8,011

 
1,951

Total other income
$
2,613

 
$
721

 
$
8,596

 
$
3,012

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(2,298
)
 
$
(2,263
)
 
$
(7,753
)
 
$
(6,868
)
Asset dispositions
(98
)
 
(1,203
)
 
(565
)
 
(3,864
)
Miscellaneous
(830
)
 
(1,149
)
 
(1,439
)
 
(5,023
)
Total other expense
$
(3,226
)
 
$
(4,615
)
 
$
(9,757
)
 
$
(15,755
)

(a)  As defined by the FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).
Earnings Per Share
Earnings Per Share
  Earnings Per Share
 
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and nine months ended September 30, 2014 and 2013 (in thousands, except per share amounts):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Net income attributable to common shareholders
$
243,961

 
$
226,163

 
$
392,185

 
$
381,814

Average common shares outstanding — basic
110,686

 
110,009

 
110,579

 
109,935

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
417

 
1,044

 
383

 
978

Average common shares outstanding — diluted
111,103

 
111,053

 
110,962

 
110,913

Earnings per average common share attributable to common shareholders — basic
$
2.20

 
$
2.06

 
$
3.55

 
$
3.47

Earnings per average common share attributable to common shareholders — diluted
$
2.20

 
$
2.04

 
$
3.53

 
$
3.44

Fair Value Measurements
Fair Value Measurements
  Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the 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 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.  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 exchange traded equities, exchange traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.

Level 2 — Utilizes 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 (such as yield curves).  This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities.  This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on net asset value (“NAV”).
 
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
 
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and 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.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, 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 activity, 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 certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 8 in the 2013 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.
 
Cash Equivalents
 
Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.
 
Risk Management Activities — Derivative Instruments
 
Exchange traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange traded commodity contracts, we calculate fair 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.  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 net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.
 
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, 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.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.
 
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 the use of option valuation models with significant unobservable inputs.
 
Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies.  We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures.  The risk control function reports to the chief financial officer’s organization.
 
Investments Held in our Nuclear Decommissioning Trusts
 
The nuclear decommissioning trust invests in fixed income securities and equity securities.  Equity securities are held indirectly through commingled funds.  The commingled funds are valued based on the concept of NAV, which is a value primarily derived from the quoted active market prices of the underlying equity securities.  We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2.  The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.  Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.
 
Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.
 
Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.
 
We price securities using information provided by our trustee for our nuclear decommissioning trust assets.  Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value.  We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.  See Note 13 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables
 
The following table presents the fair value at September 30, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at September 30, 2014
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
7

 
$
30

 
$
(8
)
 
(b)
 
$
29

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
295

 
—

 
—

 
 
 
295

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
126

 
—

 
—

 
—

 
 
 
126

Cash and cash equivalent funds
—

 
8

 
—

 
(2
)
 
(c)
 
6

Corporate debt
—

 
109

 
—

 
—

 
 
 
109

Mortgage-backed securities
—

 
83

 
—

 
—

 
 
 
83

Municipality bonds
—

 
56

 
—

 
—

 
 
 
56

Other
—

 
15

 
—

 
—

 
 
 
15

Subtotal nuclear decommissioning trust
126

 
566

 
—

 
(2
)
 

 
690

Total
$
126

 
$
573

 
$
30

 
$
(10
)
 

 
$
719

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(24
)
 
$
(68
)
 
$
40

 
(b)
 
$
(52
)

(a)
Primarily consists of heat rate options and long-dated electricity contracts.
(b)
Primarily represents counterparty netting, margin and collateral (see Note 7).
(c)
Represents nuclear decommissioning trust net pending securities sales and purchases.

The following table presents the fair value at December 31, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at December 31, 2013
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
9

 
$
41

 
$
(9
)
 
(b)
 
$
41

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
272

 
—

 
—

 
 
 
272

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
107

 
—

 
—

 
—

 
 
 
107

Cash and cash equivalent funds
—

 
11

 
—

 
(3
)
 
(c)
 
8

Corporate debt
—

 
88

 
—

 
—

 
 
 
88

Mortgage-backed securities
—

 
85

 
—

 
—

 
 
 
85

Municipality bonds
—

 
71

 
—

 
—

 
 
 
71

Other
—

 
11

 
—

 
—

 
 
 
11

Subtotal nuclear decommissioning trust
107

 
538

 
—

 
(3
)
 

 
642

Total
$
107

 
$
547

 
$
41

 
$
(12
)
 

 
$
683

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(33
)
 
$
(90
)
 
$
21

 
(b)
 
$
(102
)

(a)
Primarily consists of heat rate options and long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral (see Note 7).
(c)
Represents nuclear decommissioning trust net pending securities sales and purchases.
 
Fair Value Measurements Classified as Level 3
 
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote and option model inputs.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Our option contracts classified as Level 3 primarily relate to purchase heat rate options.  The significant unobservable inputs for these instruments include electricity prices, gas prices and volatilities.  If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease.  If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase.  The commodity prices and volatilities do not always move in corresponding directions.  The options’ fair values are impacted by the net changes of these various inputs.
 
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
 
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at September 30, 2014 and December 31, 2013:
 
 
September 30, 2014
Fair Value (millions)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
27

 
$
50

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$24.89 - $63.85
 
$
40.42

Option Contracts (b)
—

 
15

 
Option model
 
Electricity forward price (per MWh)
 
$38.96 - $78.85
 
$
53.76

 
 

 
 

 
 
 
Natural gas forward price (per MMBtu)
 
$3.76 - $3.86
 
$
3.82

 
 

 
 

 
 
 
Electricity price volatilities
 
29% - 64%
 
46
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
21% - 67%
 
28
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
3

 
3

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$3.77 - $4.34
 
$
3.99

Total
$
30

 
$
68

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
 
December 31, 2013
Fair Value (millions)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
40

 
$
66

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$24.89 - $65.04
 
$
41.09

Option Contracts (b)
—

 
19

 
Option model
 
Electricity forward price (per MWh)
 
$39.91 - $85.41
 
$
58.70

 
 

 
 

 
 
 
Natural gas forward price (per MMBtu)
 
$3.57 - $3.80
 
$
3.71

 
 

 
 

 
 
 
Electricity price volatilities
 
35% - 94%
 
59
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
22% - 36%
 
27
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
1

 
5

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$3.47 - $4.31
 
$
3.87

Total
$
41

 
$
90

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and gas price volatilities are based on historical forward price movements due to lack of market quotes for implied volatilities.
 
The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2014 and 2013 (dollars in millions):
 
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
2014
 
2013
 
2014
 
2013
Net derivative balance at beginning of period
 
$
(41
)
 
$
(53
)
 
$
(49
)
 
$
(48
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 

 
 

Deferred as a regulatory asset or liability
 
(3
)
 
4

 
4

 
(2
)
Settlements
 
6

 
6

 
10

 
8

Transfers into Level 3 from Level 2
 
—

 
(1
)
 
(2
)
 
(1
)
Transfers from Level 3 into Level 2
 
(1
)
 
—

 
(2
)
 
(1
)
Net derivative balance at end of period
 
$
(39
)
 
$
(44
)
 
$
(39
)
 
$
(44
)
 
 
 
 
 
 
 
 
 
Net unrealized gains included in earnings related to instruments still held at end of period
 
$
—

 
$
—

 
$
—

 
$
—



Amounts included in earnings are either recorded in operating revenues or 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.
 
Financial Instruments Not Carried at Fair Value
 
The carrying value of our net accounts receivable, accounts payable and any short-term borrowings approximate fair value.  Our short-term borrowings are classified within Level 2 of the fair value hierarchy.  For our long-term debt fair values, see Note 2.
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts
 
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 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.  See Note 12 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  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 deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities.  The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2014 and December 31, 2013 (dollars in millions):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
September 30, 2014
 

 
 

 
 

Equity securities
$
295

 
$
147

 
$
—

Fixed income securities
397

 
15

 
(2
)
Net payables (a)
(2
)
 
—

 
—

Total
$
690

 
$
162

 
$
(2
)
(a)
Net payables relate to pending securities sales and purchases.
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
December 31, 2013
 

 
 

 
 

Equity securities
$
272

 
$
129

 
$
—

Fixed income securities
373

 
11

 
(6
)
Net payables (a)
(3
)
 
—

 
—

Total
$
642

 
$
140

 
$
(6
)
(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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Realized gains
$
2

 
$
1

 
$
4

 
$
4

Realized losses
(2
)
 
(3
)
 
(5
)
 
(5
)
Proceeds from the sale of securities (a)
70

 
110

 
269

 
364

(a)
Proceeds are reinvested in the trust.
 
The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2014 is as follows (dollars in millions):
 
Fair Value
Less than one year
$
15

1 year – 5 years
121

5 years – 10 years
115

Greater than 10 years
146

Total
$
397

New Accounting Standards
New Accounting Standards
New Accounting Standards
 
During 2014, we adopted, on a prospective basis, new guidance relating to the presentation of unrecognized tax benefits.  This guidance generally requires entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  Prior to adopting this guidance, we presented unrecognized tax benefits on a gross basis.  The adoption of this new guidance changed our balance sheet presentation of unrecognized tax benefits, but did not impact our operating results or cash flows.  See Note 5 for details regarding the impacts of adopting this guidance.
 
In May 2014, new revenue recognition guidance was issued.  This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  The new guidance is effective for us on January 1, 2017, and may be adopted using full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.  We are currently evaluating this new guidance and the impacts it may have on our financial statements.
Changes in Accumulated Other Comprehensive Loss
Changes in Accumulated Other Comprehensive Loss 
Changes in Accumulated Other Comprehensive Loss
 
The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2014 and 2013 (dollars in thousands):
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and  
Other
Postretirement
Benefits
 
Total
Beginning balance, July 1
$
(18,369
)

$
(55,848
)

$
(74,217
)
 
$
(40,319
)

$
(64,138
)

$
(104,457
)
OCI (loss) before reclassifications
(91
)
 
5,231


5,140

 
(145
)

—


(145
)
Amounts reclassified from accumulated other comprehensive loss
5,939

(a)
736

(b)
6,675

 
14,310

(a)
957

(b)
15,267

Net current period OCI
5,848

 
5,967


11,815

 
14,165

 
957


15,122

Ending balance, September 30
$
(12,521
)

$
(49,881
)

$
(62,402
)
 
$
(26,154
)

$
(63,181
)

$
(89,335
)

(a)
These amounts represent realized gains and losses, are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
 
 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
Beginning balance, January 1
$
(23,058
)

$
(54,995
)

$
(78,053
)
 
$
(49,592
)

$
(64,416
)

$
(114,008
)
OCI (loss) before reclassifications
(472
)

3,159


2,687

 
(247
)

(1,635
)

(1,882
)
Amounts reclassified from accumulated other comprehensive loss
11,009

(a)
1,955

(b)
12,964

 
23,685

(a)
2,870

(b)
26,555

Net current period OCI
10,537

 
5,114


15,651

 
23,438

 
1,235

 
24,673

Ending balance, September 30
$
(12,521
)

$
(49,881
)

$
(62,402
)
 
$
(26,154
)

$
(63,181
)

$
(89,335
)

(a)
These amounts represent realized gains and losses, are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
Changes in Accumulated Other Comprehensive Loss 
Changes in Accumulated Other Comprehensive Loss
 
The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2014 and 2013 (dollars in thousands):
 
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and  
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
Beginning balance, July 1
$
(18,370
)

$
(31,030
)

$
(49,400
)
 
$
(40,320
)

$
(39,232
)

$
(79,552
)
OCI (loss) before reclassifications
(91
)
 
—


(91
)
 
(145
)

—


(145
)
Amounts reclassified from accumulated other comprehensive loss
5,940

(a)
735

(b)
6,675

 
14,310

(a)
951

(b)
15,261

Net current period OCI
5,849

 
735


6,584

 
14,165

 
951


15,116

Ending balance, September 30
$
(12,521
)

$
(30,295
)

$
(42,816
)
 
$
(26,155
)
 
$
(38,281
)

$
(64,436
)

(a)   These amounts represent realized gains and losses, are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)   These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 4.
 
 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
Beginning balance, January 1
$
(23,059
)

$
(30,313
)

$
(53,372
)
 
$
(49,592
)

$
(39,503
)

$
(89,095
)
OCI (loss) before reclassifications
(472
)

(2,041
)

(2,513
)
 
(247
)

(1,630
)

(1,877
)
Amounts reclassified from accumulated other comprehensive loss
11,010

(a)
2,059

(b)
13,069

 
23,684

(a)
2,852

(b)
26,536

Net current period OCI
10,538

 
18


10,556

 
23,437

 
1,222

 
24,659

Ending balance, September 30
$
(12,521
)

$
(30,295
)

$
(42,816
)
 
$
(26,155
)

$
(38,281
)

$
(64,436
)

(a)   These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)   These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
Asset Retirement Obligations
Asset Retirement Obligations
Asset Retirement Obligations
 
In the first quarter of 2014, an updated Four Corners Units 1-3 coal-fired power plant decommissioning study was finalized and approved and an adjustment to the asset retirement obligation was made in the amount of $24 million.
    
During the second quarter of 2014, an update to the 2013 decommissioning study was completed for Palo Verde nuclear generation facility to incorporate additional spent fuel related charges resulting in an adjustment to the asset retirement obligation in the amount of $20 million.
 
The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2014 (dollars in millions): 

Asset retirement obligations at January 1, 2014
$
347

Changes attributable to:
 

Accretion expense
18

Settlements
(19
)
Estimated cash flow revisions
44

Asset retirement obligations at September 30, 2014
$
390



Decommissioning activities for Four Corners Units 1-3 began in January 2014; thus, $39 million of the total asset retirement obligation of $390 million at September 30, 2014, is classified as a current liability on the balance sheet.
 
In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 3.
Consolidation and Nature of Operations (Tables)
Summary of supplemental cash flow information
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Cash paid (received) during the period for:
 
 
 
Income taxes, net of refunds
$
(131,154
)
 
$
3,412

Interest, net of amounts capitalized
145,285

 
141,047

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
24,135

 
$
11,377

Long-Term Debt and Liquidity Matters (Tables)
Schedule of estimated fair value of long-term debt, including current maturities
The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 
As of September 30, 2014
 
As of December 31, 2013
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125

 
$
125

 
$
125

 
$
125

APS
3,282

 
3,662

 
3,212

 
3,454

Total
$
3,407

 
$
3,787

 
$
3,337

 
$
3,579

Regulatory Matters (Tables)
Schedule of changes in the deferred fuel and purchased power regulatory asset 
The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions):
 
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Beginning balance
$
21

 
$
73

Deferred fuel and purchased power costs — current period
27

 
(13
)
Amounts charged to customers
(32
)
 
(23
)
Ending balance
$
16

 
$
37

Schedule of regulatory assets 
The detail of regulatory assets is as follows (dollars in millions):
 
 
Remaining
Amortization Period
 
September 30, 2014
 
December 31, 2013
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension and other postretirement benefits
(a)
 
$
—

 
$
286

 
$
—

 
$
314

Income taxes — allowance for funds used during construction (“AFUDC”) equity
2043
 
4

 
117

 
4

 
105

Deferred fuel and purchased power — mark-to-market (Note 7)
2016
 
14

 
20

 
5

 
29

Transmission vegetation management
2016
 
9

 
7

 
9

 
14

Coal reclamation
2038
 
8

 
12

 
8

 
18

Palo Verde VIEs (Note 6)
2046
 
—

 
39

 
—

 
41

Deferred compensation
2036
 
—

 
36

 
—

 
34

Deferred fuel and purchased power (b) (c)
2015
 
16

 
—

 
21

 
—

Tax expense of Medicare subsidy
2023
 
2

 
14

 
2

 
15

Loss on reacquired debt
2034
 
1

 
17

 
1

 
17

Income taxes — investment tax credit basis adjustment
2043
 
2

 
46

 
1

 
39

Pension and other postretirement benefits deferral
2015
 
6

 
—

 
8

 
4

Four Corners cost deferral
2024
 
—

 
67

 
—

 
37

Lost fixed cost recovery (b)
2015
 
33

 
—

 
25

 
—

Transmission cost adjustor (b)
2015
 
4

 
—

 
8

 
2

Retired power plant costs
2033
 
10

 
139

 
3

 
18

Deferred property taxes
(d)
 
—

 
26

 
—

 
11

Other
Various
 
1

 
11

 
2

 
14

Total regulatory assets (e)
 
 
$
110

 
$
837

 
$
97

 
$
712


(a)
This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income (“OCI”) and result in lower future revenues.  See Note 4 for further discussion.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
Per the provision of the 2012 Settlement Agreement.
(e)
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, Transmission Cost Adjustor and Other Transmission Matters.”
Schedule of regulatory liabilities 
The detail of regulatory liabilities is as follows (dollars in millions):
 
 
Remaining
Amortization Period
 
September 30, 2014
 
December 31, 2013
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
31

 
$
284

 
$
28

 
$
303

Asset retirement obligations
(a)
 
—

 
277

 
—

 
266

Renewable energy standard (b)
2015
 
40

 
8

 
33

 
15

Income taxes — change in rates
2043
 
1

 
72

 
—

 
74

Spent nuclear fuel
2047
 
5

 
53

 
6

 
36

Deferred gains on utility property
2019
 
2

 
9

 
2

 
10

Income taxes — deferred investment tax credit
2043
 
3

 
92

 
3

 
79

Demand side management (b)
2015
 
39

 
—

 
27

 
—

Other postretirement benefits
(c)
 
33

 
221

 
—

 
—

Other
Various
 
—

 
19

 
—

 
18

Total regulatory liabilities
 
 
$
154

 
$
1,035

 
$
99

 
$
801


(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)
See Note 4.
Retirement Plans and Other Benefits (Tables)
Schedule of 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) 
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,
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
Service cost — benefits earned during the period
$
13

 
$
16

 
$
40

 
$
48

 
$
5

 
$
6

 
$
14

 
$
18

Interest cost on benefit obligation
32

 
28

 
97

 
84

 
12

 
10

 
35

 
31

Expected return on plan assets
(39
)
 
(36
)
 
(119
)
 
(110
)
 
(13
)
 
(11
)
 
(38
)
 
(34
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost
—

 
—

 
—

 
1

 
—

 
—

 
—

 
—

Net actuarial loss
3

 
10

 
8

 
30

 
—

 
3

 
—

 
8

Net periodic benefit cost
$
9

 
$
18

 
$
26

 
$
53

 
$
4

 
$
8

 
$
11

 
$
23

Portion of cost charged to expense
$
5

 
$
10

 
$
16

 
$
29

 
$
3

 
$
5

 
$
8

 
$
14

Schedule of Assumptions Used 
The following table provides the assumptions used for the remeasurement at September 30, 2014:
Discount rate
 
4.41
%
Long-term rate of return
 
4.25
%
Initial healthcare cost trend rate (pre-65 participants)
 
7.50
%
Ultimate healthcare cost trend rate (pre-65 participants)
 
5.00
%
Number of years to ultimate trend rate
 
4

Medical cost subsidy trend rate (post-65 participants)
 
5.00
%
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Our Condensed Consolidated Balance Sheets at September 30, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):
 
 
September 30, 2014
 
December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
122

 
$
125

Current maturities of long-term debt
37

 
26

Long-term debt excluding current maturities
1

 
13

Equity — Noncontrolling interests
152

 
146

Derivative Accounting (Tables)
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) 
As of September 30, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
4,167

 
GWh
Gas
 
131

 
Billion cubic feet
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships 
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, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
 
2014
 
2013
 
2014
 
2013
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(149
)
 
$
(240
)
 
$
94

 
$
(409
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(9,772
)
 
(23,658
)
 
(17,426
)
 
(39,156
)

(a)
During the three and nine months ended September 30, 2014 and 2013, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments 
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, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended September 30,
Commodity Contracts
 
 
2014
 
2013
 
2014
 
2013
Net Gain Recognized in Income
 
Operating revenues (a)
 
$
273

 
$
196

 
$
335

 
$
400

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(23,915
)
 
(1,341
)
 
(1,003
)
 
(11,750
)
Total
 
 
 
$
(23,642
)
 
$
(1,145
)
 
$
(668
)
 
$
(11,350
)

(a)
Amounts are before the effect of PSA deferrals.
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts of offsetting 
As of September 30, 2014:
(Dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance  Sheet
Current Assets
 
$
16,172

 
$
(4,790
)
 
$
11,382

 
$
481

 
$
11,863

Investments and Other Assets
 
20,712

 
(3,274
)
 
17,438

 
—

 
17,438

Total Assets
 
36,884

 
(8,064
)
 
28,820

 
481

 
29,301

 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
(39,236
)
 
19,357

 
(19,879
)
 
(7,743
)
 
(27,622
)
Deferred Credits and Other
 
(53,193
)
 
28,808

 
(24,385
)
 
—

 
(24,385
)
Total Liabilities
 
(92,429
)
 
48,165

 
(44,264
)
 
(7,743
)
 
(52,007
)
Total
 
$
(55,545
)
 
$
40,101

 
$
(15,444
)
 
$
(7,262
)
 
$
(22,706
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $40,101.
(c)
Represents option premiums, and cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,743 and cash margin provided to counterparties of $481.
 
As of December 31, 2013:
(Dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance  Sheet
Current Assets
 
$
24,587

 
$
(7,425
)
 
$
17,162

 
$
7

 
$
17,169

Investments and Other Assets
 
25,364

 
(1,549
)
 
23,815

 
—

 
23,815

Total Assets
 
49,951

 
(8,974
)
 
40,977

 
7

 
40,984

 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
(50,540
)
 
26,166

 
(24,374
)
 
(7,518
)
 
(31,892
)
Deferred Credits and Other
 
(72,123
)
 
1,808

 
(70,315
)
 
—

 
(70,315
)
Total Liabilities
 
(122,663
)
 
27,974

 
(94,689
)
 
(7,518
)
 
(102,207
)
Total
 
$
(72,712
)
 
$
19,000

 
$
(53,712
)
 
$
(7,511
)
 
$
(61,223
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $19,000.
(c)
Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.

Information about derivative instruments that have credit-risk-related contingent features 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2014 (dollars in millions):
 
September 30, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position
$
92

Cash Collateral Posted
40

Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)
52


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
Changes in Equity (Tables)
Schedule of changes in shareholder equity and changes in equity of noncontrolling interests 
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, 2014 and 2013 (dollars in thousands):
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
Beginning balance, July 1
$
4,233,890

 
$
147,972

 
$
4,381,862

 
$
4,032,165

 
$
137,069

 
$
4,169,234

Net income
243,961

 
4,125

 
248,086

 
226,163

 
8,555

 
234,718

Other comprehensive income
11,815

 
—

 
11,815

 
15,122

 
—

 
15,122

Total comprehensive income
255,776

 
4,125

 
259,901

 
241,285

 
8,555

 
249,840

Issuance of capital stock
2,152

 
—

 
2,152

 
2,331

 
—

 
2,331

Reissuance of treasury stock — net
83

 
—

 
83

 
37

 
—

 
37

Other (primarily stock compensation)
—

 
—

 
—

 
(22
)
 
—

 
(22
)
Dividends on common stock
15

 
—

 
15

 
8

 
—

 
8

Ending balance, September 30
$
4,491,916

 
$
152,097

 
$
4,644,013

 
$
4,275,804

 
$
145,624

 
$
4,421,428

 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
 
Common
Shareholders
 
Noncontrolling
Interests
 
Total
Beginning balance, January 1
$
4,194,470

 
$
145,990

 
$
4,340,460

 
$
3,972,806

 
$
129,483

 
$
4,102,289

Net income
392,185

 
21,976

 
414,161

 
381,814

 
25,338

 
407,152

Other comprehensive income
15,651

 
—

 
15,651

 
24,673

 
—

 
24,673

Total comprehensive income
407,836

 
21,976

 
429,812

 
406,487

 
25,338

 
431,825

Issuance of capital stock
7,024

 
—

 
7,024

 
7,268

 
—

 
7,268

Reissuance (purchase) of treasury stock — net
4,202

 
—

 
4,202

 
(5,868
)
 
—

 
(5,868
)
Other (primarily stock compensation)
3,634

 
—

 
3,634

 
14,988

 
—

 
14,988

Dividends on common stock
(125,250
)
 
—

 
(125,250
)
 
(119,877
)
 
—

 
(119,877
)
Net capital activities by noncontrolling interests
—

 
(15,869
)
 
(15,869
)
 
—

 
(9,197
)
 
(9,197
)
Ending balance, September 30
$
4,491,916

 
$
152,097

 
$
4,644,013

 
$
4,275,804

 
$
145,624

 
$
4,421,428

Schedule of changes in shareholder equity and changes in equity of noncontrolling interests 
The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2014 and 2013 (dollars in thousands): 
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
Beginning balance, July 1
$
4,342,093

 
$
147,972

 
$
4,490,065

 
$
4,142,726

 
$
137,070

 
$
4,279,796

Net income
251,047

 
4,125

 
255,172

 
234,954

 
8,555

 
243,509

OCI
6,584

 
—

 
6,584

 
15,116

 
—

 
15,116

Total comprehensive income
257,631

 
4,125

 
261,756

 
250,070

 
8,555

 
258,625

Dividends on common stock
(100
)
 
—

 
(100
)
 
—

 
—

 
—

Other
—

 
—

 
—

 
1

 
(1
)
 
—

Ending balance, September 30
$
4,599,624

 
$
152,097

 
$
4,751,721

 
$
4,392,797

 
$
145,624

 
$
4,538,421

 
 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
 
Shareholder
Equity
 
Noncontrolling
Interests
 
Total
Beginning balance, January 1
$
4,308,884

 
$
145,990

 
$
4,454,874

 
$
4,093,000

 
$
129,483

 
$
4,222,483

Net income
405,484

 
21,976

 
427,460

 
394,945

 
25,338

 
420,283

OCI
10,556

 
—

 
10,556

 
24,659

 
—

 
24,659

Total comprehensive income
416,040

 
21,976

 
438,016

 
419,604

 
25,338

 
444,942

Dividends on common stock
(125,300
)
 
—

 
(125,300
)
 
(119,800
)
 
—

 
(119,800
)
Net capital activities by noncontrolling interests
—

 
(15,869
)
 
(15,869
)
 
—

 
(9,197
)
 
(9,197
)
Other
—

 
—

 
—

 
(7
)
 
—

 
(7
)
Ending balance, September 30
$
4,599,624

 
$
152,097

 
$
4,751,721

 
$
4,392,797

 
$
145,624

 
$
4,538,421

Other Income and Other Expense (Tables)
Detail of 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, 2014 and 2013 (dollars in thousands):

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Other income:
 

 
 

 
 

 
 

Interest income
$
103

 
$
116

 
$
849

 
$
1,291

Miscellaneous
2,263

 
44

 
6,665

 
96

Total other income
$
2,366

 
$
160

 
$
7,514

 
$
1,387

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(1,985
)
 
$
(2,028
)
 
$
(6,976
)
 
$
(5,951
)
Investment losses — net
(118
)
 
(3,435
)
 
(364
)
 
(3,643
)
Miscellaneous
(2,090
)
 
(1,972
)
 
(2,045
)
 
(3,827
)
Total other expense
$
(4,193
)
 
$
(7,435
)
 
$
(9,385
)
 
$
(13,421
)
Detail of other income and other expense 
The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2014 and 2013 (dollars in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Other income:
 

 
 

 
 

 
 

Interest income
$
31

 
$
2

 
$
585

 
$
1,061

Miscellaneous
2,582

 
719

 
8,011

 
1,951

Total other income
$
2,613

 
$
721

 
$
8,596

 
$
3,012

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(2,298
)
 
$
(2,263
)
 
$
(7,753
)
 
$
(6,868
)
Asset dispositions
(98
)
 
(1,203
)
 
(565
)
 
(3,864
)
Miscellaneous
(830
)
 
(1,149
)
 
(1,439
)
 
(5,023
)
Total other expense
$
(3,226
)
 
$
(4,615
)
 
$
(9,757
)
 
$
(15,755
)

(a)  As defined by the FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).
Earnings Per Share (Tables)
Schedule of earnings per weighted average common share outstanding
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and nine months ended September 30, 2014 and 2013 (in thousands, except per share amounts):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Net income attributable to common shareholders
$
243,961

 
$
226,163

 
$
392,185

 
$
381,814

Average common shares outstanding — basic
110,686

 
110,009

 
110,579

 
109,935

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
417

 
1,044

 
383

 
978

Average common shares outstanding — diluted
111,103

 
111,053

 
110,962

 
110,913

Earnings per average common share attributable to common shareholders — basic
$
2.20

 
$
2.06

 
$
3.55

 
$
3.47

Earnings per average common share attributable to common shareholders — diluted
$
2.20

 
$
2.04

 
$
3.53

 
$
3.44

Fair Value Measurements (Tables)
Fair value of assets and liabilities that are measured at fair value on a recurring basis 
The following table presents the fair value at September 30, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at September 30, 2014
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
7

 
$
30

 
$
(8
)
 
(b)
 
$
29

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
295

 
—

 
—

 
 
 
295

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
126

 
—

 
—

 
—

 
 
 
126

Cash and cash equivalent funds
—

 
8

 
—

 
(2
)
 
(c)
 
6

Corporate debt
—

 
109

 
—

 
—

 
 
 
109

Mortgage-backed securities
—

 
83

 
—

 
—

 
 
 
83

Municipality bonds
—

 
56

 
—

 
—

 
 
 
56

Other
—

 
15

 
—

 
—

 
 
 
15

Subtotal nuclear decommissioning trust
126

 
566

 
—

 
(2
)
 

 
690

Total
$
126

 
$
573

 
$
30

 
$
(10
)
 

 
$
719

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(24
)
 
$
(68
)
 
$
40

 
(b)
 
$
(52
)

(a)
Primarily consists of heat rate options and long-dated electricity contracts.
(b)
Primarily represents counterparty netting, margin and collateral (see Note 7).
(c)
Represents nuclear decommissioning trust net pending securities sales and purchases.

The following table presents the fair value at December 31, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at December 31, 2013
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
9

 
$
41

 
$
(9
)
 
(b)
 
$
41

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
272

 
—

 
—

 
 
 
272

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
107

 
—

 
—

 
—

 
 
 
107

Cash and cash equivalent funds
—

 
11

 
—

 
(3
)
 
(c)
 
8

Corporate debt
—

 
88

 
—

 
—

 
 
 
88

Mortgage-backed securities
—

 
85

 
—

 
—

 
 
 
85

Municipality bonds
—

 
71

 
—

 
—

 
 
 
71

Other
—

 
11

 
—

 
—

 
 
 
11

Subtotal nuclear decommissioning trust
107

 
538

 
—

 
(3
)
 

 
642

Total
$
107

 
$
547

 
$
41

 
$
(12
)
 

 
$
683

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(33
)
 
$
(90
)
 
$
21

 
(b)
 
$
(102
)

(a)
Primarily consists of heat rate options and long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral (see Note 7).
(c)
Represents nuclear decommissioning trust net pending securities sales and purchases.
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments 
 
September 30, 2014
Fair Value (millions)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
27

 
$
50

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$24.89 - $63.85
 
$
40.42

Option Contracts (b)
—

 
15

 
Option model
 
Electricity forward price (per MWh)
 
$38.96 - $78.85
 
$
53.76

 
 

 
 

 
 
 
Natural gas forward price (per MMBtu)
 
$3.76 - $3.86
 
$
3.82

 
 

 
 

 
 
 
Electricity price volatilities
 
29% - 64%
 
46
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
21% - 67%
 
28
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
3

 
3

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$3.77 - $4.34
 
$
3.99

Total
$
30

 
$
68

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
 
December 31, 2013
Fair Value (millions)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
40

 
$
66

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$24.89 - $65.04
 
$
41.09

Option Contracts (b)
—

 
19

 
Option model
 
Electricity forward price (per MWh)
 
$39.91 - $85.41
 
$
58.70

 
 

 
 

 
 
 
Natural gas forward price (per MMBtu)
 
$3.57 - $3.80
 
$
3.71

 
 

 
 

 
 
 
Electricity price volatilities
 
35% - 94%
 
59
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
22% - 36%
 
27
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
1

 
5

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$3.47 - $4.31
 
$
3.87

Total
$
41

 
$
90

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and gas price volatilities are based on historical forward price movements due to lack of market quotes for implied volatilities.
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs 
The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2014 and 2013 (dollars in millions):
 
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
2014
 
2013
 
2014
 
2013
Net derivative balance at beginning of period
 
$
(41
)
 
$
(53
)
 
$
(49
)
 
$
(48
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 

 
 

Deferred as a regulatory asset or liability
 
(3
)
 
4

 
4

 
(2
)
Settlements
 
6

 
6

 
10

 
8

Transfers into Level 3 from Level 2
 
—

 
(1
)
 
(2
)
 
(1
)
Transfers from Level 3 into Level 2
 
(1
)
 
—

 
(2
)
 
(1
)
Net derivative balance at end of period
 
$
(39
)
 
$
(44
)
 
$
(39
)
 
$
(44
)
 
 
 
 
 
 
 
 
 
Net unrealized gains included in earnings related to instruments still held at end of period
 
$
—

 
$
—

 
$
—

 
$
—

Nuclear Decommissioning Trusts (Tables)
Fair value of APS's nuclear decommissioning trust fund assets 
The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2014 and December 31, 2013 (dollars in millions):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
September 30, 2014
 

 
 

 
 

Equity securities
$
295

 
$
147

 
$
—

Fixed income securities
397

 
15

 
(2
)
Net payables (a)
(2
)
 
—

 
—

Total
$
690

 
$
162

 
$
(2
)
(a)
Net payables relate to pending securities sales and purchases.
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
December 31, 2013
 

 
 

 
 

Equity securities
$
272

 
$
129

 
$
—

Fixed income securities
373

 
11

 
(6
)
Net payables (a)
(3
)
 
—

 
—

Total
$
642

 
$
140

 
$
(6
)
(a)
Net payables relate to pending securities sales and purchases.

Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds 
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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Realized gains
$
2

 
$
1

 
$
4

 
$
4

Realized losses
(2
)
 
(3
)
 
(5
)
 
(5
)
Proceeds from the sale of securities (a)
70

 
110

 
269

 
364

(a)
Proceeds are reinvested in the trust.
 
Fair value of fixed income securities, summarized by contractual maturities 
The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2014 is as follows (dollars in millions):
 
Fair Value
Less than one year
$
15

1 year – 5 years
121

5 years – 10 years
115

Greater than 10 years
146

Total
$
397

Changes in Accumulated Other Comprehensive Loss (Tables)
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component 
The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2014 and 2013 (dollars in thousands):
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and  
Other
Postretirement
Benefits
 
Total
Beginning balance, July 1
$
(18,369
)

$
(55,848
)

$
(74,217
)
 
$
(40,319
)

$
(64,138
)

$
(104,457
)
OCI (loss) before reclassifications
(91
)
 
5,231


5,140

 
(145
)

—


(145
)
Amounts reclassified from accumulated other comprehensive loss
5,939

(a)
736

(b)
6,675

 
14,310

(a)
957

(b)
15,267

Net current period OCI
5,848

 
5,967


11,815

 
14,165

 
957


15,122

Ending balance, September 30
$
(12,521
)

$
(49,881
)

$
(62,402
)
 
$
(26,154
)

$
(63,181
)

$
(89,335
)

(a)
These amounts represent realized gains and losses, are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
 
 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
Beginning balance, January 1
$
(23,058
)

$
(54,995
)

$
(78,053
)
 
$
(49,592
)

$
(64,416
)

$
(114,008
)
OCI (loss) before reclassifications
(472
)

3,159


2,687

 
(247
)

(1,635
)

(1,882
)
Amounts reclassified from accumulated other comprehensive loss
11,009

(a)
1,955

(b)
12,964

 
23,685

(a)
2,870

(b)
26,555

Net current period OCI
10,537

 
5,114


15,651

 
23,438

 
1,235

 
24,673

Ending balance, September 30
$
(12,521
)

$
(49,881
)

$
(62,402
)
 
$
(26,154
)

$
(63,181
)

$
(89,335
)

(a)
These amounts represent realized gains and losses, are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component 
The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2014 and 2013 (dollars in thousands):
 
 
Three Months Ended September 30, 2014
 
Three Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and  
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
Beginning balance, July 1
$
(18,370
)

$
(31,030
)

$
(49,400
)
 
$
(40,320
)

$
(39,232
)

$
(79,552
)
OCI (loss) before reclassifications
(91
)
 
—


(91
)
 
(145
)

—


(145
)
Amounts reclassified from accumulated other comprehensive loss
5,940

(a)
735

(b)
6,675

 
14,310

(a)
951

(b)
15,261

Net current period OCI
5,849

 
735


6,584

 
14,165

 
951


15,116

Ending balance, September 30
$
(12,521
)

$
(30,295
)

$
(42,816
)
 
$
(26,155
)
 
$
(38,281
)

$
(64,436
)

(a)   These amounts represent realized gains and losses, are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)   These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 4.
 
 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
 
Derivative
Instruments
 
Pension and 
Other
Postretirement
Benefits
 
Total
Beginning balance, January 1
$
(23,059
)

$
(30,313
)

$
(53,372
)
 
$
(49,592
)

$
(39,503
)

$
(89,095
)
OCI (loss) before reclassifications
(472
)

(2,041
)

(2,513
)
 
(247
)

(1,630
)

(1,877
)
Amounts reclassified from accumulated other comprehensive loss
11,010

(a)
2,059

(b)
13,069

 
23,684

(a)
2,852

(b)
26,536

Net current period OCI
10,538

 
18


10,556

 
23,437

 
1,222

 
24,659

Ending balance, September 30
$
(12,521
)

$
(30,295
)

$
(42,816
)
 
$
(26,155
)

$
(38,281
)

$
(64,436
)

(a)   These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(b)   These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
Asset Retirement Obligations (Tables)
Change in asset retirement obligations
The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2014 (dollars in millions): 

Asset retirement obligations at January 1, 2014
$
347

Changes attributable to:
 

Accretion expense
18

Settlements
(19
)
Estimated cash flow revisions
44

Asset retirement obligations at September 30, 2014
$
390

Consolidation and Nature of Operations (Details) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Cash paid (received) during the period for:
 
 
Income taxes, net of refunds
$ (131,154)
$ 3,412 
Interest, net of amounts capitalized
145,285 
141,047 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 24,135 
$ 11,377 
Long-Term Debt and Liquidity Matters Narrative (Details) (USD $)
9 Months Ended 9 Months Ended 9 Months Ended 0 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
May 9, 2014
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing in 2016
Sep. 30, 2014
Pinnacle West
Line of Credit
New revolving credit facility maturing in 2019
May 9, 2014
Pinnacle West
Line of Credit
New revolving credit facility maturing in 2019
Sep. 30, 2014
Pinnacle West
Commercial Paper
New revolving credit facility maturing in 2019
Sep. 30, 2014
Pinnacle West
Letter of Credit
New revolving credit facility maturing in 2019
Sep. 30, 2014
APS
Sep. 30, 2013
APS
Dec. 31, 2013
APS
Sep. 30, 2014
APS
SCE
Four Corners Units 4 and 5
Series
Dec. 30, 2013
APS
SCE
Four Corners Units 4 and 5
Sep. 30, 2014
APS
ACC
Sep. 30, 2014
APS
ACC
Minimum
May 9, 2014
APS
Revolving Credit Facility
Revolving credit facility maturing in 2016
Sep. 30, 2014
APS
Line of Credit
Facility
Sep. 30, 2014
APS
Line of Credit
Revolving credit facility maturing in 2018
Sep. 30, 2014
APS
Line of Credit
New revolving credit facility maturing in 2019
May 9, 2014
APS
Line of Credit
New revolving credit facility maturing in 2019
Sep. 30, 2014
APS
Commercial Paper
Sep. 30, 2014
APS
Letter of Credit
Jul. 12, 2013
APS
Bond
Pollution Control Revenue Refunding Bonds, 1994 Series A
Oct. 11, 2013
APS
Bond
Pollution Control Revenue Refunding Bonds, 1994 Series C
May 1, 2014
APS
Bond
Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E
May 14, 2014
APS
Bond
2009 series A bonds
May 1, 2014
APS
Bond
2009 series D and series E bonds
Sep. 23, 2014
APS
Bond
Pollution Control Revenue Refunding Bonds, 2009 Series A
Jun. 1, 2014
APS
Bond
Pollution Control Revenue Refunding Bonds, 2009 Series A
May 30, 2014
APS
Bond
Pollution Control Revenue Refunding Bonds, 2009 Series A
Jun. 1, 2014
APS
Bond
2009 series B and series C bonds
Oct. 1, 2014
APS
Bond
Series C Bonds 2009
Sep. 30, 2014
APS
Bond
Series B Bonds 2009
Jan. 10, 2014
APS
Senior Notes
4.70% unsecured senior notes that mature on January 15, 2044
Jun. 18, 2014
APS
Senior Notes
3.35% unsecured senior note
Jun. 18, 2014
APS
Senior Notes
5.80% senior notes
Jun. 18, 2014
APS
Senior Notes
5.80% senior notes
Long-Term Debt and Liquidity Matters
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current borrowing capacity on credit facility
 
 
 
$ 200,000,000 
 
$ 200,000,000 
 
 
 
 
 
 
 
 
 
$ 500,000,000 
$ 1,000,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum commercial paper support available under credit facility
 
 
 
 
 
 
200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
250,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial Paper
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
19,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders
 
 
 
 
300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
700,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding borrowings
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
76,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument repurchased face amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
33,000,000 
32,000,000 
100,000,000 
 
 
 
 
38,000,000 
64,000,000 
 
 
 
 
 
 
Debt issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36,000,000 
 
38,000,000 
13,000,000 
 
 
32,000,000 
 
250,000,000 
250,000,000 
 
 
Interest rate (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.70% 
3.35% 
 
5.80% 
Ownership interest acquired
 
 
 
 
 
 
 
 
 
 
 
48.00% 
48.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of tax-exempt indebtedness series re-acquired
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt expected to be issued in the next 12 months
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
64,000,000 
 
 
 
 
 
32,000,000 
 
 
 
 
Repayment of long-term debt
503,583,000 
72,777,000 
 
 
 
 
 
 
503,583,000 
72,777,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
300,000,000 
 
Number of line of credit facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Provisions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Required common equity ratio ordered by ACC (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
40.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total shareholder equity
4,491,916,000 
 
4,194,470,000 
 
 
 
 
 
4,599,624,000 
 
4,308,884,000 
 
 
4,600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total capitalization
 
 
 
 
 
 
 
 
 
 
 
 
 
8,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 3,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt and Liquidity Matters Estimated Fair Value of Long-Term Debt (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Estimated fair value of long-term debt, including current maturities
 
 
Debt and Capital Lease Obligations
$ 3,407 
$ 3,337 
Long-term Debt, Fair Value
3,787 
3,579 
Pinnacle West
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Debt and Capital Lease Obligations
125 
125 
Long-term Debt, Fair Value
125 
125 
Arizona Public Service Company
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Debt and Capital Lease Obligations
3,282 
3,212 
Long-term Debt, Fair Value
$ 3,662 
$ 3,454 
Regulatory Matters (Details) (USD $)
9 Months Ended 0 Months Ended 0 Months Ended 1 Months Ended 1 Months Ended 0 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
APS
Sep. 30, 2013
APS
Sep. 30, 2014
APS
Lost Fixed Cost Recovery Mechanism
Dec. 3, 2013
APS
ACC
Net Metering
Apr. 15, 2014
Filing with the Arizona Corporation Commission
APS
2014 RES
MW
Jun. 1, 2011
Filing with the Arizona Corporation Commission
APS
ACC
Retail rate case filing
Jan. 31, 2012
Filing with the Arizona Corporation Commission
APS
ACC
Retail rate case filing
Jan. 6, 2012
Filing with the Arizona Corporation Commission
APS
ACC
Retail rate case filing
Jan. 31, 2012
Filing with the Arizona Corporation Commission
APS
ACC
Retail rate case filing
Maximum
Dec. 30, 2013
Filing with the Arizona Corporation Commission
APS
ACC
Residential customers rate case filing
Feb. 1, 2014
Cost Recovery Mechanisms
Power Supply Adjustor (PSA)
Sep. 30, 2014
Cost Recovery Mechanisms
APS
2013 DSMAC
Dec. 31, 2012
Cost Recovery Mechanisms
APS
2013 DSMAC
Sep. 30, 2014
Cost Recovery Mechanisms
APS
2014 DSMAC
Jan. 15, 2014
Cost Recovery Mechanisms
APS
Lost Fixed Cost Recovery Mechanism
Feb. 12, 2013
Cost Recovery Mechanisms
APS
Lost Fixed Cost Recovery Mechanism
Sep. 30, 2014
Cost Recovery Mechanisms
APS
Lost Fixed Cost Recovery Mechanism
Sep. 30, 2014
Cost Recovery Mechanisms
APS
ACC
RES
Jun. 2, 2012
Cost Recovery Mechanisms
APS
ACC
2013 DSMAC
Jul. 1, 2014
Cost Recovery Mechanisms
APS
ACC
RES implementation plan covering 2014-2018 timeframe
Jul. 12, 2013
Cost Recovery Mechanisms
APS
ACC
RES implementation plan covering 2014-2018 timeframe
Feb. 1, 2014
Cost Recovery Mechanisms
APS
ACC
Power Supply Adjustor (PSA)
Sep. 30, 2014
Cost Recovery Mechanisms
APS
ACC
Power Supply Adjustor (PSA)
Sep. 30, 2013
Cost Recovery Mechanisms
APS
ACC
Power Supply Adjustor (PSA)
Jun. 1, 2014
Cost Recovery Mechanisms
APS
FERC
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters
Regulatory Matters
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net retail rate increase
 
 
 
 
 
 
 
$ 95,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in the average retail customer bill
 
 
 
 
 
 
 
6.60% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Settlement Agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net change in base rates
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-fuel base rate increase
 
 
 
 
 
 
 
 
116,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel-related base rate decrease
 
 
 
 
 
 
 
 
153,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current base fuel rate (in dollars per kWh)
 
 
 
 
 
 
 
 
0.03757 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approved base fuel rate (in dollars per kWh)
 
 
 
 
 
 
 
 
0.03207 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates
 
 
 
 
 
 
 
 
36,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorized return on common equity (as a percent)
 
 
 
 
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of debt in capital structure
 
 
 
 
 
 
 
 
46.10% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of common equity in capital structure
 
 
 
 
 
 
 
 
53.90% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
 
 
 
25.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
 
 
 
75.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent)
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in the average retail customer bill under proposed Four Corners rate filing
 
 
 
 
 
 
 
 
 
 
 
2.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual cost recovery due to modifications to the Environmental Improvement Surcharge
 
 
 
 
 
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Elimination of the sharing provision of fuel and purchased power costs
 
 
 
 
 
 
 
 
9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Period to process the subsequent rate cases
 
 
 
 
 
 
 
 
12 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ACC staff sufficiency findings, general period of time
 
 
 
 
 
 
 
 
30 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plan term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
 
Amount of proposed budget
 
 
 
 
 
 
 
 
 
 
 
 
 
 
87,600,000 
 
 
 
 
 
 
154,000,000 
143,000,000 
 
 
 
 
Additional capacity from APS-owned AZ Sun projects (in MW)
 
 
 
 
 
 
20 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of approved budget
 
 
 
 
 
 
 
 
 
 
 
 
 
68,900,000 
 
68,900,000 
 
 
 
 
 
 
 
 
 
 
 
Percentage of cumulative energy savings for current year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.00% 
 
 
 
 
 
 
Beginning balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21,000,000 
73,000,000 
 
Deferred fuel and purchased power costs-current period
(26,880,000)
13,093,000 
(26,880,000)
13,093,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
27,000,000 
(13,000,000)
 
Amounts charged to customers
31,724,000 
23,158,000 
31,724,000 
23,158,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(32,000,000)
(23,000,000)
 
Ending balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
16,000,000 
37,000,000 
 
Charge on future customers who install rooftop solar panels (in dollars per kWh)
 
 
 
 
 
0.70 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated monthly collection due to charge on future customers who install rooftop solar panels
 
 
 
 
 
4.90 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001557 
 
 
 
PSA rate for prior year (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001329 
 
 
 
Forward component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
0.001277 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Historical component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
0.000280 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in annual wholesale transmission rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,900,000 
Fixed costs recoverable per residential power lost (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.031 
 
 
 
 
 
 
 
 
Fixed costs recoverable per non-residential power lost (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.023 
 
 
 
 
 
 
 
 
Percentage of retail revenues
 
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of adjustment approved representing prorated sales losses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 25,300,000 
$ 5,100,000 
 
 
 
 
 
 
 
 
 
Regulatory Matters - Four Corners (Details) (USD $)
0 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2014
APS
Dec. 31, 2013
APS
Dec. 30, 2013
APS
SCE
Four Corners Units 4 and 5
MW
Sep. 30, 2014
APS
SCE
Four Corners Units 4 and 5
Dec. 30, 2013
APS
SCE
Four Corners Units 4 and 5
Sep. 30, 2014
Four Corners cost deferral
Dec. 31, 2013
Four Corners cost deferral
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
Ownership interest acquired
 
 
 
 
 
48.00% 
48.00% 
 
 
Percentage of possible impact on average bill to residential customers
 
 
 
 
2.00% 
 
 
 
 
Regulatory assets (Note 3)
$ 836,618,000 
$ 711,712,000 
$ 836,618,000 
$ 711,712,000 
 
 
 
$ 67,000,000 
$ 37,000,000 
Net receipt due to negotiation of alternate arrangement
 
 
 
 
$ 40,000,000 
 
 
 
 
Capacity rights over the Arizona Transmission System assign to third-parties
 
 
 
 
1,555 
 
 
 
 
Capacity rights related to marketing and trading group for transmission of the additional power received assign to third-parties
 
 
 
 
300 
 
 
 
 
Regulatory Matters- Schedule of Regulatory Assets (Details) (USD $)
Sep. 30, 2014
Dec. 31, 2013
Detail of regulatory assets
 
 
Regulatory assets, current
$ 110,000,000 
$ 97,000,000 
Regulatory assets, non-current
836,618,000 
711,712,000 
Pension and other postretirement benefits
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
286,000,000 
314,000,000 
Income taxes — allowance for funds used during construction (“AFUDC”) equity
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
4,000,000 
4,000,000 
Regulatory assets, non-current
117,000,000 
105,000,000 
Deferred fuel and purchased power — mark-to-market (Note 7)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
14,000,000 
5,000,000 
Regulatory assets, non-current
20,000,000 
29,000,000 
Transmission vegetation management
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
9,000,000 
9,000,000 
Regulatory assets, non-current
7,000,000 
14,000,000 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,000,000 
8,000,000 
Regulatory assets, non-current
12,000,000 
18,000,000 
Palo Verde VIEs (Note 6)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
39,000,000 
41,000,000 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
36,000,000 
34,000,000 
Deferred fuel and purchased power
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
16,000,000 
21,000,000 
Regulatory assets, non-current
0 
0 
Tax expense of Medicare subsidy
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,000,000 
2,000,000 
Regulatory assets, non-current
14,000,000 
15,000,000 
Loss on reacquired debt
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,000,000 
1,000,000 
Regulatory assets, non-current
17,000,000 
17,000,000 
Income taxes — investment tax credit basis adjustment
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,000,000 
1,000,000 
Regulatory assets, non-current
46,000,000 
39,000,000 
Pension and other postretirement benefits deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,000,000 
8,000,000 
Regulatory assets, non-current
0 
4,000,000 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
67,000,000 
37,000,000 
Lost fixed cost recovery
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
33,000,000 
25,000,000 
Regulatory assets, non-current
0 
0 
Transmission cost adjustor
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
4,000,000 
8,000,000 
Regulatory assets, non-current
0 
2,000,000 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
10,000,000 
3,000,000 
Regulatory assets, non-current
139,000,000 
18,000,000 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
26,000,000 
11,000,000 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,000,000 
2,000,000 
Regulatory assets, non-current
11,000,000 
14,000,000 
Arizona Public Service Company
 
 
Detail of regulatory assets
 
 
Regulatory assets, non-current
836,618,000 
711,712,000 
Arizona Public Service Company |
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory Asset, Net Book Value
$ 130,000,000 
 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
Sep. 30, 2014
Dec. 31, 2013
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 154,000,000 
$ 99,000,000 
Regulatory liabilities, non-current
1,034,515,000 
801,297,000 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
31,000,000 
28,000,000 
Regulatory liabilities, non-current
284,000,000 
303,000,000 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
277,000,000 
266,000,000 
Renewable energy standard
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
40,000,000 
33,000,000 
Regulatory liabilities, non-current
8,000,000 
15,000,000 
Income taxes — change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
1,000,000 
0 
Regulatory liabilities, non-current
72,000,000 
74,000,000 
Spent nuclear fuel
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
5,000,000 
6,000,000 
Regulatory liabilities, non-current
53,000,000 
36,000,000 
Deferred gains on utility property
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,000,000 
2,000,000 
Regulatory liabilities, non-current
9,000,000 
10,000,000 
Income taxes — deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
3,000,000 
3,000,000 
Regulatory liabilities, non-current
92,000,000 
79,000,000 
Demand side management
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
39,000,000 
27,000,000 
Regulatory liabilities, non-current
0 
0 
Other postretirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
33,000,000 
0 
Regulatory liabilities, non-current
221,000,000 
0 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
$ 19,000,000 
$ 18,000,000 
Retirement Plans and Other Benefits - Narrative (Details) (USD $)
1 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended 7 Months Ended 9 Months Ended 9 Months Ended
Jul. 31, 2012
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Sep. 30, 2014
Other Benefits
Age
Jul. 31, 2014
Pension Benefits
Sep. 30, 2014
Pension Benefits
Dec. 31, 2014
Expected contributions
Other Benefits
Sep. 30, 2014
Maximum
Pension Benefits
Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
Regulatory asset amortization period
3 years 
 
 
 
 
 
 
 
 
 
 
Amortization of regulatory asset
 
$ 2,000,000 
$ 2,000,000 
$ 6,000,000 
$ 6,000,000 
 
 
 
 
 
 
Other Postretirement Benefit Plan Remeasurement
 
 
 
 
 
 
 
 
 
 
 
Age eligible for benefit
 
 
 
 
 
 
65 
 
 
 
 
Effect on net periodic benefit cost
 
 
 
 
 
 
 
 
 
10,000,000 
 
Decrease (increase) of expenses
 
 
 
 
 
 
 
 
 
5,000,000 
 
Effect on accumulated benefit obligation
 
 
 
 
 
 
316,000,000 
 
 
 
 
Defined benefit plan, assets for plan benefits, noncurrent
 
180,527,000 
 
180,527,000 
 
0 
181,000,000 
 
 
 
 
Other postretirement plan benefit remeasurement, regulatory liabilities
 
 
 
 
 
 
254,000,000 
 
 
 
 
Other postretirement plan benefit remeasurement, amount seeking approval to move to separate account to Pay Union employee medical costs
 
 
 
 
 
 
100,000,000 
 
 
 
 
Contributions
 
 
 
 
 
 
 
 
 
 
 
Voluntary employer contributions to pension plan
 
 
 
 
 
 
 
175,000,000 
 
 
 
Minimum employer contributions for the next three years
 
 
 
 
 
 
 
 
141,000,000 
 
 
Defined Benefit Plans Estimated Minimum Future Employer Contributions [Abstract]
 
 
 
 
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
 
 
0 
 
 
2015
 
 
 
 
 
 
 
 
19,000,000 
 
 
2016
 
 
 
 
 
 
 
 
122,000,000 
 
 
Maximum future employer contributions in 2015
 
 
 
 
 
 
 
 
 
 
100,000,000 
Maximum future employer contributions in 2016
 
 
 
 
 
 
 
 
 
 
$ 25,000,000 
Retirement Plans and Other Benefits - Schedule of Net Benefit Cost (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Pension Benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
$ 13 
$ 16 
$ 40 
$ 48 
Interest cost on benefit obligation
32 
28 
97 
84 
Expected return on plan assets
(39)
(36)
(119)
(110)
Amortization of:
 
 
 
 
Prior service cost
0 
0 
0 
1 
Net actuarial loss
3 
10 
8 
30 
Net periodic benefit cost
9 
18 
26 
53 
Portion of cost charged to expense
5 
10 
16 
29 
Other postretirement benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
5 
6 
14 
18 
Interest cost on benefit obligation
12 
10 
35 
31 
Expected return on plan assets
(13)
(11)
(38)
(34)
Amortization of:
 
 
 
 
Prior service cost
0 
0 
0 
0 
Net actuarial loss
0 
3 
0 
8 
Net periodic benefit cost
4 
8 
11 
23 
Portion of cost charged to expense
$ 3 
$ 5 
$ 8 
$ 14 
Retirement Plans and Other Benefits - Schedule of Assumptions Used (Details) (Other Benefits)
9 Months Ended
Sep. 30, 2014
Other Benefits
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
Discount rate
4.41% 
Long-term rate of return
4.25% 
Initial healthcare cost trend rate (pre-65 participants)
7.50% 
Ultimate healthcare cost trend rate (pre-65 participants)
5.00% 
Number of years to ultimate trend rate
4 years 
Medical cost subsidy trend rate (post-65 participants)
5.00% 
Income Taxes (Details) (USD $)
1 Months Ended 3 Months Ended 9 Months Ended
Jan. 31, 2014
Mar. 31, 2014
Sep. 30, 2014
Consolidation of VIEs
Income Taxes
 
 
 
Income tax refunds
 
$ 135,000,000 
 
Income tax expense associates with the VIE's
 
 
0 
Increase (decrease) in deferred income taxes due to adoption of regulations
$ 30,000,000 
 
 
Palo Verde Sale Leaseback Variable Interest Entities Schedule of VIEs (Details) (USD $)
Sep. 30, 2014
Dec. 31, 2013
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$ 122,222,000 
$ 125,125,000 
Current maturities of long-term debt
368,841,000 
540,424,000 
Equity — Noncontrolling interests
152,097,000 
145,990,000 
Arizona Public Service Company
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
122,222,000 
125,125,000 
Current maturities of long-term debt
368,841,000 
540,424,000 
Equity — Noncontrolling interests
152,097,000 
145,990,000 
Arizona Public Service Company |
Consolidation of VIEs
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
122,000,000 
125,000,000 
Current maturities of long-term debt
37,000,000 
26,000,000 
Long-term debt excluding current maturities
1,000,000 
13,000,000 
Equity — Noncontrolling interests
$ 152,000,000 
$ 146,000,000 
Palo Verde Sale Leaseback Variable Interest Entities Narrative (Details) (USD $)
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 0 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Arizona Public Service Company
item
Sep. 30, 2013
Arizona Public Service Company
Sep. 30, 2014
Arizona Public Service Company
item
Sep. 30, 2013
Arizona Public Service Company
Dec. 31, 1986
Arizona Public Service Company
Trust
Sep. 30, 2014
Arizona Public Service Company
Consolidation of VIEs
Sep. 30, 2013
Arizona Public Service Company
Consolidation of VIEs
Sep. 30, 2014
Arizona Public Service Company
Consolidation of VIEs
Sep. 30, 2013
Arizona Public Service Company
Consolidation of VIEs
Jul. 7, 2014
Arizona Public Service Company
Consolidation of VIEs
Through 2023
Lease
Jul. 7, 2014
Arizona Public Service Company
Consolidation of VIEs
Through 2033
Lease
Jul. 7, 2014
Arizona Public Service Company
Consolidation of VIEs
Period 2016 through 2023
Jul. 7, 2014
Arizona Public Service Company
Consolidation of VIEs
Period 2024 through 2033
Jul. 7, 2014
Maximum
Arizona Public Service Company
Consolidation of VIEs
Period 2024 through 2033
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of VIE lessor trusts
 
 
 
 
3 
 
3 
 
3 
 
 
 
 
 
 
 
 
 
Annual lease payments
 
 
 
 
 
 
$ 49,000,000 
 
 
 
 
 
 
 
 
$ 23,000,000 
$ 16,000,000 
 
Number of leases under which assets are retained
 
 
 
 
 
 
 
 
 
 
 
 
 
1 
2 
 
 
 
Lease period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 years 
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts
4,125,000 
8,555,000 
21,976,000 
25,338,000 
4,125,000 
8,555,000 
21,976,000 
25,338,000 
 
4,000,000 
9,000,000 
22,000,000 
25,000,000 
 
 
 
 
 
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events
 
 
 
 
 
 
 
 
 
 
 
138,000,000 
 
 
 
 
 
 
VIE debt to be assumed upon the occurrence of certain unlikely events
 
 
 
 
 
 
 
 
 
 
 
$ 38,000,000 
 
 
 
 
 
 
Derivative Accounting Narrative (Details) (USD $)
9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Arizona Public Service Company
Sep. 30, 2014
Designated as Hedging Instruments
Dec. 31, 2013
Designated as Hedging Instruments
Sep. 30, 2014
Commodity Contracts
Counterparty
Dec. 31, 2013
Commodity Contracts
Sep. 30, 2014
Commodity Contracts
Designated as Hedging Instruments
Sep. 30, 2013
Commodity Contracts
Designated as Hedging Instruments
Sep. 30, 2014
Commodity Contracts
Designated as Hedging Instruments
Sep. 30, 2013
Commodity Contracts
Designated as Hedging Instruments
Derivative Accounting
 
 
 
 
 
 
 
 
 
 
Percentage of deferred unrealized gains (losses) on contracts due to PSA recovery
100.00% 
 
 
 
 
 
 
 
 
 
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment
100.00% 
100.00% 
 
 
 
 
 
 
 
 
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges
 
 
 
 
 
 
$ 0 
$ 0 
$ 0 
$ 0 
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income
 
 
 
 
 
 
 
 
(9,000,000)
 
Gross recognized derivatives
 
 
4,000,000 
5,000,000 
92,429,000 
122,663,000 
 
 
 
 
Amounts offset
 
 
 
 
(40,101,000)
(19,000,000)
 
 
 
 
Derivative liability, not subject to master netting arrangement
 
 
 
 
7,743,000 
7,518,000 
 
 
 
 
Other
 
 
 
 
481,000 
7,000 
 
 
 
 
Concentration of credit risk, number of counterparties
 
 
 
 
2 
 
 
 
 
 
Concentration of risk with two counterparties, as a percentage of risk management assets
 
 
 
 
89.00% 
 
 
 
 
 
Risk management activities-derivative instruments: Commodity Contracts
 
 
 
 
29,301,000 
40,984,000 
 
 
 
 
Additional collateral to counterparties for energy related non-derivative instrument contracts
 
 
 
 
$ 175,000,000 
 
 
 
 
 
Derivative Accounting Schedule of Gross Notional Amounts Outstanding (Details)
Sep. 30, 2014
GW
Commodity - Power
 
Outstanding gross notional amount of derivatives
 
Outstanding gross notional amount of derivative instruments
4,167 
Commodity - Gas
 
Outstanding gross notional amount of derivatives
 
Outstanding gross notional amount of derivative instruments
131,000 
Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
$ (149)
$ (240)
$ 94 
$ (409)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)
(9,772)
(23,658)
(17,426)
(39,156)
Not Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net Gain (Loss) Recognized in Income from Derivative Instruments
(23,642)
(1,145)
(668)
(11,350)
Not Designated as Hedging Instruments |
Revenue
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net Gain (Loss) Recognized in Income from Derivative Instruments
273 
196 
335 
400 
Not Designated as Hedging Instruments |
Fuel and purchased power
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net Gain (Loss) Recognized in Income from Derivative Instruments
$ (23,915)
$ (1,341)
$ (1,003)
$ (11,750)
Derivative Instruments in the Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Commodity Contracts
 
 
Assets
 
 
Gross Recognized Derivatives
$ 36,884 
$ 49,951 
Amounts Offset
(8,064)
(8,974)
Net Recognized Derivatives
28,820 
40,977 
Other
(481)
(7)
Amount Reported on Balance Sheet
29,301 
40,984 
Liabilities
 
 
Gross Recognized Derivatives
(92,429)
(122,663)
Amounts Offset
48,165 
27,974 
Net Recognized Derivatives
(44,264)
(94,689)
Other
(7,743)
(7,518)
Amount Reported on Balance Sheet
(52,007)
(102,207)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(55,545)
(72,712)
Amounts Offset
40,101 
19,000 
Net Recognized Derivatives
(15,444)
(53,712)
Other
7,262 
7,511 
Amount Reported on Balance Sheet
(22,706)
(61,223)
Commodity Contracts |
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
16,172 
24,587 
Amounts Offset
(4,790)
(7,425)
Net Recognized Derivatives
11,382 
17,162 
Other
(481)
(7)
Amount Reported on Balance Sheet
11,863 
17,169 
Commodity Contracts |
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
20,712 
25,364 
Amounts Offset
(3,274)
(1,549)
Net Recognized Derivatives
17,438 
23,815 
Other
0 
0 
Amount Reported on Balance Sheet
17,438 
23,815 
Commodity Contracts |
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(39,236)
(50,540)
Amounts Offset
19,357 
26,166 
Net Recognized Derivatives
(19,879)
(24,374)
Other
(7,743)
(7,518)
Amount Reported on Balance Sheet
(27,622)
(31,892)
Commodity Contracts |
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(53,193)
(72,123)
Amounts Offset
28,808 
1,808 
Net Recognized Derivatives
(24,385)
(70,315)
Other
0 
0 
Amount Reported on Balance Sheet
(24,385)
(70,315)
Designated as Hedging Instruments
 
 
Liabilities
 
 
Gross Recognized Derivatives
$ (4,000)
$ (5,000)
Changes in Equity (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Changes in equity
 
 
 
 
Balance
$ 4,381,862 
$ 4,169,234 
$ 4,340,460 
$ 4,102,289 
NET INCOME
248,086 
234,718 
414,161 
407,152 
Other comprehensive income
11,815 
15,122 
15,651 
24,673 
COMPREHENSIVE INCOME
259,901 
249,840 
429,812 
431,825 
Issuance of capital stock
2,152 
2,331 
7,024 
7,268 
Reissuance (purchase) of treasury stock - net
83 
37 
4,202 
(5,868)
Other (primarily stock compensation)
0 
(22)
3,634 
14,988 
Dividends on common stock
15 
8 
(125,250)
(119,877)
Net capital activities by noncontrolling interests
 
 
(15,869)
(9,197)
Balance
4,644,013 
4,421,428 
4,644,013 
4,421,428 
Common Shareholders
 
 
 
 
Changes in equity
 
 
 
 
Balance
4,233,890 
4,032,165 
4,194,470 
3,972,806 
NET INCOME
243,961 
226,163 
392,185 
381,814 
Other comprehensive income
11,815 
15,122 
15,651 
24,673 
COMPREHENSIVE INCOME
255,776 
241,285 
407,836 
406,487 
Issuance of capital stock
2,152 
2,331 
7,024 
7,268 
Reissuance (purchase) of treasury stock - net
83 
37 
4,202 
(5,868)
Other (primarily stock compensation)
0 
(22)
3,634 
14,988 
Dividends on common stock
15 
8 
(125,250)
(119,877)
Balance
4,491,916 
4,275,804 
4,491,916 
4,275,804 
Noncontrolling Interests
 
 
 
 
Changes in equity
 
 
 
 
Balance
147,972 
137,069 
145,990 
129,483 
NET INCOME
4,125 
8,555 
21,976 
25,338 
COMPREHENSIVE INCOME
4,125 
8,555 
21,976 
25,338 
Net capital activities by noncontrolling interests
 
 
(15,869)
(9,197)
Balance
152,097 
145,624 
152,097 
145,624 
Arizona Public Service Company
 
 
 
 
Changes in equity
 
 
 
 
Balance
4,490,065 
4,279,796 
4,454,874 
4,222,483 
NET INCOME
255,172 
243,509 
427,460 
420,283 
Other comprehensive income
6,584 
15,116 
10,556 
24,659 
COMPREHENSIVE INCOME
261,756 
258,625 
438,016 
444,942 
Other (primarily stock compensation)
 
0 
0 
(7)
Dividends on common stock
(100)
0 
(125,300)
(119,800)
Net capital activities by noncontrolling interests
 
 
(15,869)
(9,197)
Balance
4,751,721 
4,538,421 
4,751,721 
4,538,421 
Arizona Public Service Company |
Common Shareholders
 
 
 
 
Changes in equity
 
 
 
 
Balance
4,342,093 
4,142,726 
4,308,884 
4,093,000 
NET INCOME
251,047 
234,954 
405,484 
394,945 
Other comprehensive income
6,584 
15,116 
10,556 
24,659 
COMPREHENSIVE INCOME
257,631 
250,070 
416,040 
419,604 
Other (primarily stock compensation)
 
1 
0 
(7)
Dividends on common stock
(100)
 
(125,300)
(119,800)
Balance
4,599,624 
4,392,797 
4,599,624 
4,392,797 
Arizona Public Service Company |
Noncontrolling Interests
 
 
 
 
Changes in equity
 
 
 
 
Balance
147,972 
137,070 
145,990 
129,483 
NET INCOME
4,125 
8,555 
21,976 
25,338 
COMPREHENSIVE INCOME
4,125 
8,555 
21,976 
25,338 
Other (primarily stock compensation)
 
(1)
 
 
Net capital activities by noncontrolling interests
 
 
(15,869)
(9,197)
Balance
$ 152,097 
$ 145,624 
$ 152,097 
$ 145,624 
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)
0 Months Ended 3 Months Ended 9 Months Ended 0 Months Ended
Jul. 7, 2014
Arizona Public Service Company
Sep. 30, 2014
Arizona Public Service Company
item
Sep. 30, 2014
Arizona Public Service Company
item
Dec. 31, 1986
Arizona Public Service Company
Trust
Jul. 7, 2014
Arizona Public Service Company
Consolidation of VIEs
Period 2016 through 2023
Jul. 7, 2014
Arizona Public Service Company
Consolidation of VIEs
Period 2024 through 2033
Aug. 18, 2014
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Aug. 18, 2014
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Arizona Public Service Company
Palo Verde Nuclear Generating Station
 
 
 
 
 
 
 
 
Litigation settlement amount
$ 3,250,000 
 
 
 
 
 
$ 57,400,000 
$ 16,700,000 
Maximum insurance against public liability per occurrence for a nuclear incident
 
 
13,600,000,000 
 
 
 
 
 
Maximum available nuclear liability insurance
 
 
375,000,000 
 
 
 
 
 
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program
 
 
13,200,000,000 
 
 
 
 
 
Maximum retrospective premium assessment per reactor for each nuclear liability incident
 
 
127,300,000 
 
 
 
 
 
Annual limit per incident with respect to maximum retrospective premium assessment
 
 
19,000,000 
 
 
 
 
 
Number of VIE lessor trusts
 
3 
3 
3 
 
 
 
 
Maximum potential retrospective assessment per incident of APS
 
 
111,000,000 
 
 
 
 
 
Annual payment limitation with respect to maximum potential retrospective premium assessment
 
 
16,500,000 
 
 
 
 
 
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde
 
 
2,750,000,000 
 
 
 
 
 
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment
 
 
20,000,000 
 
 
 
 
 
Collateral assurance provided based on rating triggers
 
 
53,000,000 
 
 
 
 
 
Period to provide collateral assurance based on rating triggers
 
 
20 days 
 
 
 
 
 
Annual lease payments
 
 
49,000,000 
 
23,000,000 
16,000,000 
 
 
Purchase obligation increase
 
230,000,000 
 
 
 
 
 
 
Purchase obligation, due in 2015
 
57,000,000 
57,000,000 
 
 
 
 
 
Purchase obligation, due in 2016
 
122,000,000 
122,000,000 
 
 
 
 
 
Purchase obligation, due in 2017
 
18,000,000 
18,000,000 
 
 
 
 
 
Purchase obligation, due in 2018
 
$ 31,000,000 
$ 31,000,000 
 
 
 
 
 
Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) (Arizona Public Service Company, USD $)
In Millions, unless otherwise specified
0 Months Ended 9 Months Ended 0 Months Ended
Jul. 7, 2014
Requirement
Jan. 22, 2014
Entity
Requirement
Sep. 8, 2011
item
MW
kV
Customer
Sep. 30, 2014
Aug. 6, 2013
Contaminated groundwater wells
Defendant
Superfund-Related Matters
 
 
 
 
 
Costs related to investigation and study under Superfund site
 
 
 
$ 2 
 
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit
 
 
 
 
24 
Southwest Power Outage
 
 
 
 
 
Capacity of transmission line that tripped out of service (in kV)
 
 
500 
 
 
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost
 
 
10 minutes 
 
 
Number of customers losing service in Yuma area
 
 
69,700 
 
 
Capacity of firm load that were reported to have been affected due to outages affecting portions of southern Arizona, southern California and northern Mexico (in MW)
 
 
7,900 
 
 
Number of customers that were reported to have been affected due to outages
 
 
2,700,000 
 
 
Number of alleged entities
 
6 
 
 
 
Number of reliability standard requirements violations
 
7 
 
 
 
Number of reliability standard requirements neither admitted nor denied violations in settlement
4 
 
 
 
 
Amount of civil penalty agreed in settlement
3.25 
 
 
 
 
Civil penalty amount required to be paid in equal parts
2 
 
 
 
 
Civil penalty amount offset in exchange for completing certain reliability enhancements
$ 1.25 
 
 
 
 
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)
9 Months Ended 0 Months Ended 9 Months Ended
Sep. 30, 2014
Arizona Public Service Company
Four Corners Units 4 and 5
May 23, 2013
Four Corners
New Mexico Tax Matter
May 23, 2013
Four Corners
Arizona Public Service Company
New Mexico Tax Matter
Sep. 30, 2014
Navajo Plant
Arizona Public Service Company
Sep. 30, 2014
Cholla
Arizona Public Service Company
Sep. 30, 2014
Cholla Units 2 And 3
Arizona Public Service Company
Sep. 30, 2014
Letter of Credit
Arizona Public Service Company
Sep. 30, 2014
Equity Lessors in Palo Verde sale leaseback transactions
Arizona Public Service Company
Sep. 30, 2014
Natural gas tolling contract obligations
Arizona Public Service Company
Sep. 30, 2014
Letters of Credit Expiring in 2015
Arizona Public Service Company
Letter_of_credit
Sep. 30, 2014
Letters of Credit Expiring in 2016
Arizona Public Service Company
Letter_of_credit
Environmental Matters
 
 
 
 
 
 
 
 
 
 
 
Expected environmental cost
$ 350,000,000 
 
 
$ 200,000,000 
$ 200,000,000 
$ 130,000,000 
 
 
 
 
 
Percentage of share of cost of control
63.00% 
 
 
 
 
 
 
 
 
 
 
Coal severance surtax, penalty, and interest
 
30,000,000 
 
 
 
 
 
 
 
 
 
Share of the assessment
 
 
12,000,000 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
 
$ 76,000,000 
$ 23,000,000 
$ 5,000,000 
 
 
Number of letters of credit expiring
 
 
 
 
 
 
 
 
 
1 
2 
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Other income:
 
 
 
 
Interest income
$ 103 
$ 116 
$ 849 
$ 1,291 
Miscellaneous
2,263 
44 
6,665 
96 
Total other income
2,366 
160 
7,514 
1,387 
Other expense:
 
 
 
 
Non-operating costs
(1,985)
(2,028)
(6,976)
(5,951)
Investment losses — net
(118)
(3,435)
(364)
(3,643)
Miscellaneous
(2,090)
(1,972)
(2,045)
(3,827)
Total other expense
(4,193)
(7,435)
(9,385)
(13,421)
Arizona Public Service Company
 
 
 
 
Other income:
 
 
 
 
Interest income
31 
2 
585 
1,061 
Miscellaneous
2,582 
719 
8,011 
1,951 
Total other income
2,613 
721 
8,596 
3,012 
Other expense:
 
 
 
 
Non-operating costs
(2,298)
(2,263)
(7,753)
(6,868)
Asset dispositions
(98)
(1,203)
(565)
(3,864)
Miscellaneous
(830)
(1,149)
(1,439)
(5,023)
Total other expense
$ (3,226)
$ (4,615)
$ (9,757)
$ (15,755)
Earnings Per Share (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Earnings Per Share [Abstract]
 
 
 
 
Net income attributable to common shareholders
$ 243,961 
$ 226,163 
$ 392,185 
$ 381,814 
Average common shares outstanding - basic
110,686 
110,009 
110,579 
109,935 
Net effect of dilutive securities:
 
 
 
 
Contingently issuable performance shares and restricted stock units
417 
1,044 
383 
978 
Average common shares outstanding — diluted
111,103 
111,053 
110,962 
110,913 
Earnings per average common share attributable to common shareholders -basic (in dollars per share)
$ 2.20 
$ 2.06 
$ 3.55 
$ 3.47 
Earnings per average common share attributable to common shareholders -diluted (in dollars per share)
$ 2.20 
$ 2.04 
$ 3.53 
$ 3.44 
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) (USD $)
Sep. 30, 2014
Dec. 31, 2013
Assets
 
 
Nuclear decommissioning trust
$ 690,226,000 
$ 642,007,000 
Total assets
30,000,000 
41,000,000 
Recurring
 
 
Assets
 
 
Risk management activities-derivative instruments: Commodity contracts
29,000,000 
41,000,000 
Nuclear decommissioning trust
690,000,000 
642,000,000 
Total assets
719,000,000 
683,000,000 
Liabilities
 
 
Risk management activities-derivative instruments: Commodity Contracts
(52,000,000)
(102,000,000)
Recurring |
US commingled equity funds
 
 
Assets
 
 
Nuclear decommissioning trust
295,000,000 
272,000,000 
Recurring |
U.S. Treasury
 
 
Assets
 
 
Nuclear decommissioning trust
126,000,000 
107,000,000 
Recurring |
Cash and cash equivalent funds
 
 
Assets
 
 
Nuclear decommissioning trust
6,000,000 
8,000,000 
Recurring |
Corporate debt
 
 
Assets
 
 
Nuclear decommissioning trust
109,000,000 
88,000,000 
Recurring |
Mortgage-backed securities
 
 
Assets
 
 
Nuclear decommissioning trust
83,000,000 
85,000,000 
Recurring |
Municipality bonds
 
 
Assets
 
 
Nuclear decommissioning trust
56,000,000 
71,000,000 
Recurring |
Other
 
 
Assets
 
 
Nuclear decommissioning trust
15,000,000 
11,000,000 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Nuclear decommissioning trust
126,000,000 
107,000,000 
Total assets
126,000,000 
107,000,000 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
U.S. Treasury
 
 
Assets
 
 
Nuclear decommissioning trust
126,000,000 
107,000,000 
Recurring |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Risk management activities-derivative instruments: Commodity contracts
7,000,000 
9,000,000 
Nuclear decommissioning trust
566,000,000 
538,000,000 
Total assets
573,000,000 
547,000,000 
Liabilities
 
 
Risk management activities-derivative instruments: Commodity Contracts
(24,000,000)
(33,000,000)
Recurring |
Significant Other Observable Inputs (Level 2) |
US commingled equity funds
 
 
Assets
 
 
Nuclear decommissioning trust
295,000,000 
272,000,000 
Recurring |
Significant Other Observable Inputs (Level 2) |
Cash and cash equivalent funds
 
 
Assets
 
 
Nuclear decommissioning trust
8,000,000 
11,000,000 
Recurring |
Significant Other Observable Inputs (Level 2) |
Corporate debt
 
 
Assets
 
 
Nuclear decommissioning trust
109,000,000 
88,000,000 
Recurring |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Nuclear decommissioning trust
83,000,000 
85,000,000 
Recurring |
Significant Other Observable Inputs (Level 2) |
Municipality bonds
 
 
Assets
 
 
Nuclear decommissioning trust
56,000,000 
71,000,000 
Recurring |
Significant Other Observable Inputs (Level 2) |
Other
 
 
Assets
 
 
Nuclear decommissioning trust
15,000,000 
11,000,000 
Recurring |
Significant Unobservable Inputs (Level 3)
 
 
Assets
 
 
Risk management activities-derivative instruments: Commodity contracts
30,000,000 
41,000,000 
Total assets
30,000,000 
41,000,000 
Liabilities
 
 
Risk management activities-derivative instruments: Commodity Contracts
(68,000,000)
(90,000,000)
Recurring |
Other
 
 
Assets
 
 
Risk management activities-derivative instruments: Commodity contracts
(8,000,000)
(9,000,000)
Nuclear decommissioning trust
(2,000,000)
(3,000,000)
Total assets
(10,000,000)
(12,000,000)
Liabilities
 
 
Risk management activities-derivative instruments: Commodity Contracts
40,000,000 
21,000,000 
Recurring |
Other |
Cash and cash equivalent funds
 
 
Assets
 
 
Nuclear decommissioning trust
$ (2,000,000)
$ (3,000,000)
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
$ 30 
$ 41 
Liabilities
68 
90 
Electricity forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
27 
40 
Liabilities
50 
66 
Electricity forward contracts |
Minimum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
24.89 
24.89 
Electricity forward contracts |
Maximum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
63.85 
65.04 
Electricity forward contracts |
Weighted Average |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
40.42 
41.09 
Option Contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
0 
0 
Liabilities
15 
19 
Option Contracts |
Minimum |
Option model
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
38.96 
39.91 
Natural gas forward price (per MMbtu)
3.76 
3.57 
Electricity price volatilities (as a percent)
29.00% 
35.00% 
Natural gas price volatilities (as a percent)
21.00% 
22.00% 
Option Contracts |
Maximum |
Option model
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
78.85 
85.41 
Natural gas forward price (per MMbtu)
3.86 
3.80 
Electricity price volatilities (as a percent)
64.00% 
94.00% 
Natural gas price volatilities (as a percent)
67.00% 
36.00% 
Option Contracts |
Weighted Average |
Option model
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
53.76 
58.70 
Natural gas forward price (per MMbtu)
3.82 
3.71 
Electricity price volatilities (as a percent)
46.00% 
59.00% 
Natural gas price volatilities (as a percent)
28.00% 
27.00% 
Natural gas forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
3 
1 
Liabilities
$ 3 
$ 5 
Natural gas forward contracts |
Minimum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Natural gas forward price (per MMbtu)
3.77 
3.47 
Natural gas forward contracts |
Maximum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Natural gas forward price (per MMbtu)
4.34 
4.31 
Natural gas forward contracts |
Weighted Average |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Natural gas forward price (per MMbtu)
3.99 
3.87 
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
 
 
 
 
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs
$ (41,000,000)
$ (53,000,000)
$ (49,000,000)
$ (48,000,000)
Total net gains (losses) realized/unrealized: Deferred as a regulatory asset or liability
(3,000,000)
4,000,000 
4,000,000 
(2,000,000)
Settlements
6,000,000 
6,000,000 
10,000,000 
8,000,000 
Transfers into Level 3 from Level 2
0 
(1,000,000)
(2,000,000)
(1,000,000)
Transfers from Level 3 into Level 2
(1,000,000)
0 
(2,000,000)
(1,000,000)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs
(39,000,000)
(44,000,000)
(39,000,000)
(44,000,000)
Fair value measurement transfers
 
 
$ 0 
 
Nuclear Decommissioning Trusts (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
$ 690,226,000 
 
$ 690,226,000 
 
$ 642,007,000 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
 
 
Proceeds from the sale of securities
 
 
269,276,000 
363,944,000 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
690,226,000 
 
690,226,000 
 
642,007,000 
Arizona Public Service Company
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
690,226,000 
 
690,226,000 
 
642,007,000 
Unrealized Gains
162,000,000 
 
162,000,000 
 
140,000,000 
Unrealized Losses
(2,000,000)
 
(2,000,000)
 
(6,000,000)
Net payables for securities purchases
(2,000,000)
 
(2,000,000)
 
(3,000,000)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
 
 
Realized gains
2,000,000 
1,000,000 
4,000,000 
4,000,000 
 
Realized losses
(2,000,000)
(3,000,000)
(5,000,000)
(5,000,000)
 
Proceeds from the sale of securities
70,000,000 
110,000,000 
269,276,000 
363,944,000 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
690,226,000 
 
690,226,000 
 
642,007,000 
Arizona Public Service Company |
Equity Securities
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
295,000,000 
 
295,000,000 
 
272,000,000 
Unrealized Gains
147,000,000 
 
147,000,000 
 
129,000,000 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
295,000,000 
 
295,000,000 
 
272,000,000 
Arizona Public Service Company |
Fixed income securities.
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
397,000,000 
 
397,000,000 
 
373,000,000 
Unrealized Gains
15,000,000 
 
15,000,000 
 
11,000,000 
Unrealized Losses
(2,000,000)
 
(2,000,000)
 
(6,000,000)
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Less than one year
15,000,000 
 
15,000,000 
 
 
1 year - 5 years
121,000,000 
 
121,000,000 
 
 
5 years - 10 years
115,000,000 
 
115,000,000 
 
 
Greater than 10 years
146,000,000 
 
146,000,000 
 
 
Total
$ 397,000,000 
 
$ 397,000,000 
 
$ 373,000,000 
Changes in Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Changes in accumulated other comprehensive income (loss) by component
 
 
 
 
Beginning balance
$ (74,217)
$ (104,457)
$ (78,053)
$ (114,008)
OCI (loss) before reclassifications
5,140 
(145)
2,687 
(1,882)
Amounts reclassified from accumulated other comprehensive loss
6,675 
15,267 
12,964 
26,555 
Total other comprehensive income
11,815 
15,122 
15,651 
24,673 
Ending balance
(62,402)
(89,335)
(62,402)
(89,335)
Derivative Instruments
 
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
 
Beginning balance
(18,369)
(40,319)
(23,058)
(49,592)
OCI (loss) before reclassifications
(91)
(145)
(472)
(247)
Amounts reclassified from accumulated other comprehensive loss
5,939 
14,310 
11,009 
23,685 
Total other comprehensive income
5,848 
14,165 
10,537 
23,438 
Ending balance
(12,521)
(26,154)
(12,521)
(26,154)
Pension and other postretirement benefits
 
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
 
Beginning balance
(55,848)
(64,138)
(54,995)
(64,416)
OCI (loss) before reclassifications
5,231 
0 
3,159 
(1,635)
Amounts reclassified from accumulated other comprehensive loss
736 
957 
1,955 
2,870 
Total other comprehensive income
5,967 
957 
5,114 
1,235 
Ending balance
(49,881)
(63,181)
(49,881)
(63,181)
Arizona Public Service Company
 
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
 
Beginning balance
(49,400)
(79,552)
(53,372)
(89,095)
OCI (loss) before reclassifications
(91)
(145)
(2,513)
(1,877)
Amounts reclassified from accumulated other comprehensive loss
6,675 
15,261 
13,069 
26,536 
Total other comprehensive income
6,584 
15,116 
10,556 
24,659 
Ending balance
(42,816)
(64,436)
(42,816)
(64,436)
Arizona Public Service Company |
Derivative Instruments
 
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
 
Beginning balance
(18,370)
(40,320)
(23,059)
(49,592)
OCI (loss) before reclassifications
(91)
(145)
(472)
(247)
Amounts reclassified from accumulated other comprehensive loss
5,940 
14,310 
11,010 
23,684 
Total other comprehensive income
5,849 
14,165 
10,538 
23,437 
Ending balance
(12,521)
(26,155)
(12,521)
(26,155)
Arizona Public Service Company |
Pension and other postretirement benefits
 
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
 
Beginning balance
(31,030)
(39,232)
(30,313)
(39,503)
OCI (loss) before reclassifications
0 
0 
(2,041)
(1,630)
Amounts reclassified from accumulated other comprehensive loss
735 
951 
2,059 
2,852 
Total other comprehensive income
735 
951 
18 
1,222 
Ending balance
$ (30,295)
$ (38,281)
$ (30,295)
$ (38,281)
Asset Retirement Obligations Narrative (Details) (USD $)
3 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2014
Arizona Public Service Company
Dec. 31, 2013
Arizona Public Service Company
Mar. 31, 2014
Arizona Public Service Company
Four Corners Units 1-3
Jun. 30, 2014
Arizona Public Service Company
Palo Verde
Asset Retirement Obligations
 
 
 
 
 
 
Amount of update on account of decommissioning study
 
 
 
 
$ 24,000,000 
$ 20,000,000 
Asset Retirement Obligation, Current
39,416,000 
32,896,000 
39,416,000 
32,896,000 
 
 
Asset Retirement Obligation Total
$ 390,000,000 
 
$ 390,000,000 
$ 347,000,000 
 
 
Asset Retirement Obligations Roll-Forward (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 3 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Arizona Public Service Company
Jun. 30, 2014
Arizona Public Service Company
Palo Verde
Mar. 31, 2014
Arizona Public Service Company
Four Corners Units 1-3
Asset Retirement Obligations
 
 
 
 
Amount of update on account of decommissioning study
 
 
$ 20 
$ 24 
Change in asset retirement obligations
 
 
 
 
Asset retirement obligations at the beginning of year
390 
347 
 
 
Changes attributable to:
 
 
 
 
Accretion expense
 
18 
 
 
Settlements
 
(19)
 
 
Estimated cash flow revisions
 
44 
 
 
Asset retirement obligations at the end of year
$ 390 
$ 390