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)
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 
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
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)
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 
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 
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
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
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
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
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
 
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
 
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