PINNACLE WEST CAPITAL CORP, 10-K filed on 2/20/2015
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2014
Feb. 13, 2015
Jun. 30, 2014
Entity Information [Line Items]
 
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
 
Entity Central Index Key
0000764622 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2014 
 
 
Amendment Flag
false 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Public Float
 
 
$ 6,356,930,539 
Entity Common Stock, Shares Outstanding
 
110,575,187 
 
Document Fiscal Year Focus
2014 
 
 
Document Fiscal Period Focus
FY 
 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Entity Information [Line Items]
 
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY 
 
 
Entity Central Index Key
0000007286 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2014 
 
 
Amendment Flag
false 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Non-accelerated Filer 
 
 
Entity Public Float
 
 
$ 0 
Entity Common Stock, Shares Outstanding
 
71,264,947 
 
Document Fiscal Year Focus
2014 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
OPERATING REVENUES
$ 3,491,632 
$ 3,454,628 
$ 3,301,804 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,179,829 
1,095,709 
994,790 
Operations and maintenance
908,025 
924,727 
884,769 
Depreciation and amortization
417,358 
415,708 
404,336 
Taxes other than income taxes
172,295 
164,167 
159,323 
Other expenses
2,883 
7,994 
6,831 
Total
2,680,390 
2,608,305 
2,450,049 
OPERATING INCOME
811,242 
846,323 
851,755 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
30,790 
25,581 
22,436 
Other income (Note S-3)
9,608 
1,704 
1,606 
Other expense (Note S-3)
(21,746)
(16,024)
(19,842)
Total
18,652 
11,261 
4,200 
INTEREST EXPENSE
 
 
 
Interest charges
200,950 
201,888 
214,616 
Allowance for borrowed funds used during construction (Note 1)
(15,457)
(14,861)
(14,971)
Total
185,493 
187,027 
199,645 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
644,401 
670,557 
656,310 
INCOME TAXES (Note 4)
220,705 
230,591 
237,317 
INCOME FROM CONTINUING OPERATIONS
423,696 
439,966 
418,993 
Net of income tax benefit of $(3,813) (Note 1)
(5,829)
NET INCOME
423,696 
439,966 
413,164 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,622 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
397,595 
406,074 
381,542 
Average common shares outstanding — basic (in shares)
110,626 
109,984 
109,510 
Average common shares outstanding — diluted (in shares)
111,178 
110,806 
110,527 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Income from continuing operations attributable to common shareholders — basic (in dollars per share)
$ 3.59 
$ 3.69 
$ 3.54 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.59 
$ 3.69 
$ 3.48 
Income from continuing operations attributable to common shareholders — diluted (in dollars per share)
$ 3.58 
$ 3.66 
$ 3.50 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 3.58 
$ 3.66 
$ 3.45 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
Income from continuing operations, net of tax
397,595 
406,074 
387,380 
Discontinued operations, net of tax
(5,838)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
ELECTRIC OPERATING REVENUES
3,488,946 
3,451,251 
3,293,489 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,179,829 
1,095,709 
994,790 
Operations and maintenance
882,442 
897,824 
873,916 
Depreciation and amortization
417,264 
415,612 
404,242 
Taxes other than income taxes
171,583 
163,377 
158,412 
Income taxes (Notes 4 and S-1)
245,036 
256,864 
256,600 
Total
2,896,154 
2,829,386 
2,687,960 
OPERATING INCOME
592,792 
621,865 
605,529 
OTHER INCOME (DEDUCTIONS)
 
 
 
Income taxes (Notes 4 and S-1)
7,676 
11,769 
12,204 
Allowance for equity funds used during construction (Note 1)
30,790 
25,581 
22,436 
Other income (Note S-3)
11,295 
3,896 
2,868 
Other expense (Note S-3)
(13,403)
(20,449)
(21,150)
Total
36,358 
20,797 
16,358 
INTEREST EXPENSE
 
 
 
Interest on long-term debt
186,323 
188,011 
198,398 
Interest on short-term borrowings
6,796 
6,605 
7,135 
Debt discount, premium and expense
4,168 
4,046 
4,215 
Allowance for borrowed funds used during construction (Note 1)
(15,457)
(14,861)
(14,971)
Total
181,830 
183,801 
194,777 
INCOME TAXES (Note 4)
237,360 
245,095 
244,396 
NET INCOME
447,320 
458,861 
427,110 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,613 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 421,219 
$ 424,969 
$ 395,497 
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Income Statement [Abstract]
 
 
 
Income tax expense (benefit) on discontinued operations
$ 0 
$ 0 
$ (3,813)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Net income
$ 423,696 
$ 439,966 
$ 413,164 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(810)
(213)
(22,763)
Reclassification of net realized loss, net of tax benefit
13,483 
26,747 
59,887 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(2,761)
9,421 
1,031 
Total other comprehensive income
9,912 
35,955 
38,155 
COMPREHENSIVE INCOME
433,608 
475,921 
451,319 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,622 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
407,507 
442,029 
419,697 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net income
447,320 
458,861 
427,110 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(809)
(214)
(22,775)
Reclassification of net realized loss, net of tax benefit
13,483 
26,747 
59,888 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(7,635)
9,190 
(617)
Total other comprehensive income
5,039 
35,723 
36,496 
COMPREHENSIVE INCOME
452,359 
494,584 
463,606 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,613 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 426,258 
$ 460,692 
$ 431,993 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Net unrealized loss, tax benefit
$ (438)
$ 140 
$ 14,900 
Reclassification of net realized loss, tax benefit
7,932 
17,472 
39,120 
Pension and other postretirement benefits activity, tax (expense) benefit
1,307 
(6,156)
(651)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net unrealized loss, tax benefit
(438)
140 
14,888 
Reclassification of net realized loss, tax benefit
7,932 
17,472 
39,119 
Pension and other postretirement benefits activity, tax (expense) benefit
$ 4,655 
$ (6,003)
$ 408 
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 7,604 
$ 9,526 
Customer and other receivables
297,740 
299,904 
Accrued unbilled revenues
100,533 
96,796 
Allowance for doubtful accounts
(3,094)
(3,203)
Materials and supplies (at average cost)
218,889 
221,682 
Fossil fuel (at average cost)
37,097 
38,028 
Income tax receivable (Note 4)
3,098 
135,517 
Assets from risk management activities (Note 16)
13,785 
17,169 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
20,755 
Other regulatory assets (Note 3)
129,808 
76,388 
Deferred income taxes (Notes 4 and S-1)
122,232 
91,152 
Other current assets
38,817 
39,895 
Total current assets
973,435 
1,043,609 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
17,620 
23,815 
Nuclear decommissioning trust (Notes 13 and 19)
713,866 
642,007 
Other assets
54,047 
60,875 
Total investments and other assets
785,533 
726,697 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
15,543,063 
15,200,464 
Accumulated depreciation and amortization
(5,397,751)
(5,300,219)
Net
10,145,312 
9,900,245 
Construction work in progress
682,807 
581,369 
Palo Verde sale leaseback, net of accumulated depreciation of $229,795 and $225,925 (Note 18)
121,255 
125,125 
Intangible assets, net of accumulated amortization of $489,538 and $439,703
119,755 
157,689 
Nuclear fuel, net of accumulated amortization of $143,554 and $146,057
125,201 
124,557 
Total property, plant and equipment
11,194,330 
10,888,985 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,054,087 
711,712 
Assets for other postretirement benefits (Note 7)
152,290 
Other
153,857 
137,683 
Total deferred debits
1,360,234 
849,395 
Total Assets
14,313,532 
13,508,686 
CURRENT LIABILITIES
 
 
Accounts payable
295,211 
284,516 
Accrued taxes (Note 4)
140,613 
130,998 
Accrued interest
52,603 
48,351 
Common dividends payable
65,790 
62,528 
Short-term borrowings (Note 5)
147,400 
153,125 
Current maturities of long-term debt (Note 6)
383,570 
540,424 
Customer deposits
72,307 
76,101 
Liabilities from risk management activities (Note 16)
59,676 
31,892 
Liability for asset retirements (Note 11)
32,462 
32,896 
Regulatory liabilities (Note 3)
130,549 
99,273 
Other current liabilities
178,962 
158,540 
Total current liabilities
1,559,143 
1,618,644 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
3,031,215 
2,796,465 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,582,636 
2,351,882 
Regulatory liabilities (Notes 1, 3, 4 and 7)
1,051,196 
801,297 
Liability for asset retirements (Note 11)
358,288 
313,833 
Liabilities for pension and other postretirement benefits (Note 7)
453,736 
513,628 
Liabilities from risk management activities (Note 16)
50,602 
70,315 
Customer advances
123,052 
114,480 
Coal mine reclamation
198,292 
207,453 
Deferred investment tax credit
178,607 
152,361 
Unrecognized tax benefits (Note 4)
19,377 
42,209 
Other
188,286 
185,659 
Total deferred credits and other
5,204,072 
4,753,117 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, issued 110,649,762 at end of 2014 and 110,280,703 at end of 2013
2,512,970 
2,491,558 
Treasury stock at cost; 78,400 shares at end of 2014 and 98,944 shares at end of 2013
(3,401)
(4,308)
Total common stock
2,509,569 
2,487,250 
Retained earnings
1,926,065 
1,785,273 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(57,756)
(54,995)
Derivative instruments (Note 16)
(10,385)
(23,058)
Total accumulated other comprehensive loss
(68,141)
(78,053)
Total shareholders’ equity
4,367,493 
4,194,470 
Noncontrolling interests (Note 18)
151,609 
145,990 
Total equity
4,519,102 
4,340,460 
Total Liabilities and Equity
14,313,532 
13,508,686 
ARIZONA PUBLIC SERVICE COMPANY
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
4,515 
3,725 
Customer and other receivables
297,712 
299,055 
Accrued unbilled revenues
100,533 
96,796 
Allowance for doubtful accounts
(3,094)
(3,203)
Materials and supplies (at average cost)
218,889 
221,682 
Fossil fuel (at average cost)
37,097 
38,028 
Income tax receivable (Note 4)
135,179 
Assets from risk management activities (Note 16)
13,785 
17,169 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
20,755 
Other regulatory assets (Note 3)
129,808 
76,388 
Deferred income taxes (Notes 4 and S-1)
55,253 
Other current assets
38,693 
39,153 
Total current assets
900,117 
944,727 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
17,620 
23,815 
Nuclear decommissioning trust (Notes 13 and 19)
713,866 
642,007 
Other assets
33,362 
33,709 
Total investments and other assets
764,848 
699,531 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
15,539,811 
15,196,598 
Accumulated depreciation and amortization
(5,394,650)
(5,296,501)
Net
10,145,161 
9,900,097 
Construction work in progress
682,807 
581,369 
Palo Verde sale leaseback, net of accumulated depreciation of $229,795 and $225,925 (Note 18)
121,255 
125,125 
Intangible assets, net of accumulated amortization of $489,538 and $439,703
119,600 
157,534 
Nuclear fuel, net of accumulated amortization of $143,554 and $146,057
125,201 
124,557 
Total property, plant and equipment
11,194,024 
10,888,682 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,054,087 
711,712 
Assets for other postretirement benefits (Note 7)
149,260 
Unamortized debt issue costs
24,642 
21,860 
Other
128,026 
114,865 
Total deferred debits
1,356,015 
848,437 
Total Assets
14,215,004 
13,381,377 
CURRENT LIABILITIES
 
 
Accounts payable
289,930 
281,237 
Accrued taxes (Note 4)
131,110 
122,460 
Accrued interest
52,358 
48,132 
Common dividends payable
65,800 
62,500 
Short-term borrowings (Note 5)
147,400 
153,125 
Current maturities of long-term debt (Note 6)
383,570 
540,424 
Customer deposits
72,307 
76,101 
Deferred income taxes
2,033 
Liabilities from risk management activities (Note 16)
59,676 
31,892 
Liability for asset retirements (Note 11)
32,462 
32,896 
Regulatory liabilities (Note 3)
130,549 
99,273 
Other current liabilities
167,302 
130,774 
Total current liabilities
1,532,464 
1,580,847 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,571,365 
2,347,724 
Regulatory liabilities (Notes 1, 3, 4 and 7)
1,051,196 
801,297 
Liability for asset retirements (Note 11)
358,288 
313,833 
Liabilities for pension and other postretirement benefits (Note 7)
424,508 
476,017 
Liabilities from risk management activities (Note 16)
50,602 
70,315 
Customer advances
123,052 
114,480 
Coal mine reclamation
198,292 
207,453 
Deferred investment tax credit
178,607 
152,361 
Unrecognized tax benefits (Note 4)
45,740 
42,209 
Other
144,823 
148,502 
Total deferred credits and other
5,146,473 
4,674,191 
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
1,968,718 
1,804,398 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(37,948)
(30,313)
Derivative instruments (Note 16)
(10,385)
(23,059)
Total accumulated other comprehensive loss
(48,333)
(53,372)
Total shareholders’ equity
4,478,243 
4,308,884 
Noncontrolling interests (Note 18)
151,609 
145,990 
Total equity
4,629,852 
4,454,874 
Long-term debt less current maturities (Note 6)
2,906,215 
2,671,465 
Total capitalization
7,536,067 
7,126,339 
Total Liabilities and Equity
$ 14,215,004 
$ 13,381,377 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 229,795 
$ 225,925 
Accumulated amortization on intangible assets
489,538 
439,703 
Accumulated amortization on nuclear fuel
143,554 
146,057 
EQUITY
 
 
Common stock, par value
   
   
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
110,649,762 
110,280,703 
Treasury stock at cost, shares
78,400 
98,944 
ARIZONA PUBLIC SERVICE COMPANY
 
 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
229,795 
225,925 
Accumulated amortization on intangible assets
483,538 
439,703 
Accumulated amortization on nuclear fuel
$ 143,554 
$ 146,057 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net Income
$ 423,696,000 
$ 439,966,000 
$ 413,164,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
496,487,000 
492,322,000 
481,262,000 
Deferred fuel and purchased power
(26,927,000)
21,678,000 
71,573,000 
Deferred fuel and purchased power amortization
40,757,000 
31,190,000 
(116,716,000)
Allowance for equity funds used during construction
(30,790,000)
(25,581,000)
(22,436,000)
Deferred income taxes
159,023,000 
249,296,000 
187,023,000 
Deferred investment tax credit
26,246,000 
52,542,000 
41,579,000 
Change in derivative instruments fair value
339,000 
534,000 
(749,000)
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(52,672,000)
(44,991,000)
14,587,000 
Accrued unbilled revenues
(3,737,000)
(1,951,000)
30,394,000 
Materials, supplies and fossil fuel
3,724,000 
(11,878,000)
(23,043,000)
Income tax receivable
132,419,000 
(133,094,000)
(4,043,000)
Other current assets
4,384,000 
(17,913,000)
(27,352,000)
Accounts payable
(353,000)
45,414,000 
(96,600,000)
Accrued taxes
9,615,000 
6,059,000 
12,736,000 
Other current liabilities
17,892,000 
(7,513,000)
23,869,000 
Change in margin and collateral accounts — assets
(343,000)
993,000 
2,216,000 
Change in margin and collateral accounts — liabilities
(24,975,000)
12,355,000 
137,785,000 
Change in unrecognized tax benefits
2,778,000 
(91,425,000)
(2,583,000)
Change in long-term regulatory liabilities
59,618,000 
64,473,000 
13,539,000 
Change in long-term income tax receivable
137,270,000 
(1,756,000)
Change in other long-term assets
(59,344,000)
(41,757,000)
6,872,000 
Change in other long-term liabilities
(78,210,000)
(24,682,000)
29,801,000 
Net cash flow provided by operating activities
1,099,627,000 
1,153,307,000 
1,171,122,000 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(910,634,000)
(1,016,322,000)
(889,551,000)
Contributions in aid of construction
20,325,000 
41,090,000 
49,876,000 
Allowance for borrowed funds used during construction
(15,457,000)
(14,861,000)
(14,971,000)
Proceeds from nuclear decommissioning trust sales
356,195,000 
446,025,000 
417,603,000 
Investment in nuclear decommissioning trust
(373,444,000)
(463,274,000)
(434,852,000)
Other
347,000 
(2,059,000)
(1,099,000)
Net cash flow used for investing activities
(922,668,000)
(1,009,401,000)
(872,994,000)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
731,126,000 
136,307,000 
476,081,000 
Repayment of long-term debt
(652,578,000)
(122,828,000)
(654,286,000)
Short-term borrowings and payments — net
(5,725,000)
60,950,000 
92,175,000 
Dividends paid on common stock
(246,671,000)
(235,244,000)
(225,075,000)
Common stock equity issuance
15,288,000 
17,319,000 
15,955,000 
Distributions to noncontrolling interests
(20,482,000)
(17,385,000)
(10,529,000)
Other
161,000 
299,000 
170,000 
Net cash flow used for financing activities
(178,881,000)
(160,582,000)
(305,509,000)
NET DECREASE IN CASH AND CASH EQUIVALENTS
(1,922,000)
(16,676,000)
(7,381,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
9,526,000 
26,202,000 
33,583,000 
CASH AND CASH EQUIVALENTS AT END OF YEAR
7,604,000 
9,526,000 
26,202,000 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
(102,154,000)
18,537,000 
2,543,000 
Interest, net of amounts capitalized
177,074,000 
184,010,000 
200,923,000 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
44,712,000 
33,184,000 
26,208,000 
Dividends declared but not paid
65,790,000 
62,528,000 
59,789,000 
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)
145,609,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net Income
447,320,000 
458,861,000 
427,110,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
496,393,000 
492,226,000 
481,168,000 
Deferred fuel and purchased power
(26,927,000)
21,678,000 
71,573,000 
Deferred fuel and purchased power amortization
40,757,000 
31,190,000 
(116,716,000)
Allowance for equity funds used during construction
(30,790,000)
(25,581,000)
(22,436,000)
Deferred income taxes
155,401,000 
278,101,000 
202,159,000 
Deferred investment tax credit
26,246,000 
52,542,000 
41,579,000 
Change in derivative instruments fair value
339,000 
534,000 
(749,000)
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(52,466,000)
(46,552,000)
12,914,000 
Accrued unbilled revenues
(3,737,000)
(1,951,000)
30,394,000 
Materials, supplies and fossil fuel
3,724,000 
(11,878,000)
(23,043,000)
Income tax receivable
135,179,000 
(134,590,000)
(2,280,000)
Other current assets
3,766,000 
(17,112,000)
(27,745,000)
Accounts payable
(2,355,000)
47,870,000 
(97,395,000)
Accrued taxes
8,650,000 
5,760,000 
7,330,000 
Other current liabilities
33,970,000 
(9,005,000)
6,070,000 
Change in margin and collateral accounts — assets
(343,000)
993,000 
2,216,000 
Change in margin and collateral accounts — liabilities
(24,975,000)
12,355,000 
137,785,000 
Change in unrecognized tax benefits
2,778,000 
(91,244,000)
(2,583,000)
Change in long-term regulatory liabilities
59,618,000 
64,473,000 
13,539,000 
Change in long-term income tax receivable
137,665,000 
(1,756,000)
Change in other long-term assets
(65,521,000)
(46,043,000)
1,391,000 
Change in other long-term liabilities
(82,860,000)
(25,601,000)
34,854,000 
Net cash flow provided by operating activities
1,124,167,000 
1,194,691,000 
1,175,379,000 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(910,084,000)
(1,016,322,000)
(889,551,000)
Contributions in aid of construction
20,325,000 
41,090,000 
49,876,000 
Allowance for borrowed funds used during construction
(15,457,000)
(14,861,000)
(14,971,000)
Proceeds from nuclear decommissioning trust sales
356,195,000 
446,025,000 
417,603,000 
Investment in nuclear decommissioning trust
(373,444,000)
(463,274,000)
(434,852,000)
Other
347,000 
(2,067,000)
(1,099,000)
Net cash flow used for investing activities
(922,118,000)
(1,009,409,000)
(872,994,000)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
606,126,000 
136,307,000 
351,081,000 
Repayment of long-term debt
(527,578,000)
(122,828,000)
(529,286,000)
Short-term borrowings and payments — net
(5,725,000)
60,950,000 
92,175,000 
Dividends paid on common stock
(253,600,000)
(242,100,000)
(222,200,000)
Distributions to noncontrolling interests
(20,482,000)
(17,385,000)
(10,529,000)
Net cash flow used for financing activities
(201,259,000)
(185,056,000)
(318,759,000)
NET DECREASE IN CASH AND CASH EQUIVALENTS
790,000 
226,000 
(16,374,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
3,725,000 
3,499,000 
19,873,000 
CASH AND CASH EQUIVALENTS AT END OF YEAR
4,515,000 
3,725,000 
3,499,000 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
(86,054,000)
7,524,000 
1,196,000 
Interest, net of amounts capitalized
173,436,000 
180,757,000 
196,038,000 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
44,712,000 
33,184,000 
26,208,000 
Dividends declared but not paid
65,800,000 
62,500,000 
59,800,000 
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)
$ 0 
$ 145,609,000 
$ 0 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
ARIZONA PUBLIC SERVICE COMPANY
ARIZONA PUBLIC SERVICE COMPANY
Common Stock
ARIZONA PUBLIC SERVICE COMPANY
Additional Paid-in Capital
ARIZONA PUBLIC SERVICE COMPANY
Retained Earnings
ARIZONA PUBLIC SERVICE COMPANY
Accumulated Other Comprehensive Income (Loss)
ARIZONA PUBLIC SERVICE COMPANY
Noncontrolling Interests
Balance at Dec. 31, 2011
$ 3,930,586 
$ 2,444,247 
$ (4,717)
$ 1,534,483 
$ (152,163)
$ 108,736 
$ 4,051,406 
$ 178,162 
$ 2,379,696 
$ 1,510,740 
$ (125,591)
$ 108,399 
Balance (in shares) at Dec. 31, 2011
 
109,356,974 
111,161 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
413,164 
 
 
381,542 
 
31,622 
427,110 
 
 
395,497 
 
31,613 
Other comprehensive income
38,155 
 
 
 
38,155 
 
36,496 
 
 
 
36,496 
 
Dividends, common stock
(291,923)
 
 
(291,923)
 
 
(282,000)
 
 
(282,000)
 
 
Issuance of common stock
22,676 
22,676 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
480,983 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,607)
 
(4,607)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(89,629)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
5,113 
 
5,113 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
105,598 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(10,875)
 
 
 
 
(10,875)
(10,529)
 
 
 
 
(10,529)
Balance at Dec. 31, 2012
4,102,289 
2,466,923 
(4,211)
1,624,102 
(114,008)
129,483 
4,222,483 
178,162 
2,379,696 
1,624,237 
(89,095)
129,483 
Balance (in shares) at Dec. 31, 2012
 
109,837,957 
95,192 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
439,966 
 
 
406,074 
 
33,892 
458,861 
 
 
424,969 
 
33,892 
Other comprehensive income
35,955 
 
 
 
35,955 
 
35,723 
 
 
 
35,723 
 
Dividends, common stock
(244,903)
 
 
(244,903)
 
 
(244,800)
 
 
(244,800)
 
 
Other
 
 
 
 
 
 
(8)
 
 
(8)
 
 
Issuance of common stock
24,635 
24,635 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
442,746 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(9,727)
 
(9,727)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(174,290)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
9,630 
 
9,630 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
170,538 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(17,385)
 
 
 
 
(17,385)
(17,385)
 
 
 
 
(17,385)
Balance at Dec. 31, 2013
4,340,460 
2,491,558 
(4,308)
1,785,273 
(78,053)
145,990 
4,454,874 
178,162 
2,379,696 
1,804,398 
(53,372)
145,990 
Balance (in shares) at Dec. 31, 2013
110,280,703 
110,280,703 
98,944 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
423,696 
 
 
397,595 
 
26,101 
447,320 
 
 
421,219 
 
26,101 
Other comprehensive income
9,912 
 
 
 
9,912 
 
5,039 
 
 
 
5,039 
 
Dividends, common stock
(256,803)
 
 
(256,803)
 
 
(256,900)
 
 
(256,900)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
21,412 
21,412 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
369,059 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(7,893)
 
(7,893)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(139,746)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
8,800 
 
8,800 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
160,290 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(20,482)
 
 
 
 
(20,482)
(20,482)
 
 
 
 
(20,482)
Balance at Dec. 31, 2014
$ 4,519,102 
$ 2,512,970 
$ (3,401)
$ 1,926,065 
$ (68,141)
$ 151,609 
$ 4,629,852 
$ 178,162 
$ 2,379,696 
$ 1,968,718 
$ (48,333)
$ 151,609 
Balance (in shares) at Dec. 31, 2014
110,649,762 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.33 
$ 2.23 
$ 2.67 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
 
Description of Business and Basis of Presentation
 
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE, and formerly SunCor. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.  El Dorado is an investment firm. BCE is a new subsidiary formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. SunCor was a developer of residential, commercial and industrial real estate projects and essentially all of these assets were sold in 2009 and 2010.  In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  All activities for SunCor are reported as discontinued operations. 
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE, and formerly SunCor. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).
 
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.
 
Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with GAAP.  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Regulatory Accounting
 
APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates.  Regulatory liabilities generally represent expected future costs that have already been collected from customers.
 
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
 
See Note 3 for additional information.
 
Electric Revenues
 
We derive electric revenues primarily from sales of electricity to our regulated Native Load customers.  Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers.  The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month.  Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed.  Differences historically between the actual and estimated unbilled revenues are immaterial.  We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
 
Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income.  In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy.  This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow.  We net these book-outs, which reduces both revenues and fuel and purchased power costs.
 
For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 3).  Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.
 
Some of our cost recovery mechanisms are alternative revenue programs.  For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

Allowance for Doubtful Accounts
 
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible.  The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues.  The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.
 
Property, Plant and Equipment
 
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities.  We report utility plant at its original cost, which includes:
 
material and labor;
contractor costs;
capitalized leases;
construction overhead costs (where applicable); and
allowance for funds used during construction.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 11.
 
APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations.  APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.
 
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2014 were as follows:
 
Fossil plant — 19 years;
Nuclear plant — 28 years;
Other generation — 25 years;
Transmission — 38 years;
Distribution — 33 years; and
Other — 7 years.

Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  See Note 3 for further discussion.  These costs were deferred and will be amortized on the depreciation line of the Consolidated Statements of Income.
 
For the years 2012 through 2014, the depreciation rates ranged from a low of 0.30% to a high of 12.08%.  The weighted-average rate was 2.77% for 2014, 3.00% for 2013, and 2.71% for 2012.
 
Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
 
AFUDC was calculated by using a composite rate of 8.47% for 2014, 8.56% for 2013, and 8.60% for 2012.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
 
Materials and Supplies
 
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
 
Fair Value Measurements
 
We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis.  Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).
 
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
 
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
 
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.
 
See Note 13 for additional information about fair value measurements.
 
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial 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.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  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 expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  See Note 16 for additional information about our derivative instruments.
 
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
 
Retirement Plans and Other Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries.  We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.  See Note 7 for additional information on pension and other postretirement benefits.
 
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through August 2014, at which point the DOE suspended the fee.  In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2016. See Note 10 for information on spent nuclear fuel disposal costs.
 
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).
 
Cash and Cash Equivalents
 
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
 
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
 
 
Year ended December 31,
 
2014
 
2013
 
2012
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
(102,154
)
 
$
18,537

 
$
2,543

Interest, net of amounts capitalized
177,074

 
184,010

 
200,923

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
44,712

 
$
33,184

 
$
26,208

Dividends declared but not paid
65,790

 
62,528

 
59,789

Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)

 
145,609

 



Intangible Assets
 
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets.  The intangible assets are amortized over their finite useful lives.  Amortization expense was $53 million in 2014, $53 million in 2013, and $50 million in 2012.  Estimated amortization expense on existing intangible assets over the next five years is $42 million in 2015, $32 million in 2016, $21 million in 2017, $9 million in 2018, and $3 million in 2019.  At December 31, 2014, the weighted-average remaining amortization period for intangible assets was 6 years.
 
Investments
 
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments.
 
Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.

Preferred Stock

At December 31, 2014, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.
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 4 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.
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 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 from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the 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, see "Four Corners" below);
Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;
Modifications to the Environmental Improvement Surcharge 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 PSA, including the elimination of the 90/10 sharing provision;
A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2009 Settlement Agreement discussed below;
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 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. The ACC adopted these changes on December 18, 2014.  The revised rules are expected to become effective in the second quarter of 2015.

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 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.
 
Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a 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.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards.  The draft proposed substantial changes to the rules and energy efficiency standards.    The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014.  A formal rule making has not been initiated and there has been no additional action on the draft to date.
 
PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The PSA is subject to specified parameters and procedures, including the following:
 
APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
 
an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
 
the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
 
the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
 
the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
 
The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions):
 
 
Year Ended December 31,
 
2014
 
2013
Beginning balance
$
21

 
$
73

Deferred fuel and purchased power costs - current period
27

 
(21
)
Amounts charged to customers
(41
)
 
(31
)
Ending balance
$
7

 
$
21


 
The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh.  Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, 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. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million effective March 1, 2015.
 
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 Arizona 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 another is currently scheduled for February 26, 2015.

Net Metering
 
On July 12, 2013, APS filed an application with the ACC proposing a solution to address 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. 
 
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. No further action has been taken in this docket.

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.  On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  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 through its inclusion in rates.  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 $77 million as of December 31, 2014 and is being amortized in rates over 10 years. 

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

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Cholla Unit 2 by April 2016 and cease 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 ($128 million as of December 31, 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
 
December 31, 2014
 
December 31, 2013
 
Period
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension and other postretirement benefits
(a)
 
$

 
$
485

 
$

 
$
314

Income taxes — AFUDC equity
2044
 
5

 
118

 
4

 
105

Deferred fuel and purchased power — mark-to-market (Note 16)
2017
 
51

 
46

 
5

 
29

Transmission vegetation management
2016
 
9

 
5

 
9

 
14

Coal reclamation
2026
 

 
7

 
8

 
18

Palo Verde VIEs (Note 18)
2046
 

 
35

 

 
41

Deferred compensation
2036
 

 
34

 

 
34

Deferred fuel and purchased power (b) (c)
2015
 
7

 

 
21

 

Tax expense of Medicare subsidy
2024
 
2

 
14

 
2

 
15

Loss on reacquired debt
2034
 
1

 
16

 
1

 
17

Income taxes — investment tax credit basis adjustment
2044
 
2

 
46

 
1

 
39

Pension and other postretirement benefits deferral
2015
 
4

 

 
8

 
4

Four Corners cost deferral
2024
 
7

 
70

 

 
37

Lost fixed cost recovery
2015
 
38

 

 
25

 

Transmission cost adjustor
2014
 

 

 
8

 
2

Retired power plant costs
2033
 
10

 
136

 
3

 
18

Deferred property taxes
(d)
 

 
30

 

 
11

Other
Various
 
2

 
12

 
2

 
14

Total regulatory assets (e)
 
 
$
138

 
$
1,054

 
$
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 OCI and result in lower future revenues.  See Note 7 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
 
December 31, 2014
 
December 31, 2013
 
Period
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
31

 
$
273

 
$
28

 
$
303

Asset retirement obligations
2044
 

 
296

 

 
266

Renewable energy standard (b)
2017
 
25

 
23

 
33

 
15

Income taxes — change in rates
2043
 

 
72

 

 
74

Spent nuclear fuel
2047
 
5

 
66

 
6

 
36

Deferred gains on utility property
2019
 
2

 
8

 
2

 
10

Income taxes — deferred investment tax credit
2043
 
4

 
93

 
3

 
79

Demand side management (b)
2015
 
31

 

 
27

 

Other postretirement benefits
(c)
 
32

 
199

 

 

Other
Various
 
1

 
21

 

 
18

Total regulatory liabilities
 
 
$
131

 
$
1,051

 
$
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 (see Note 11).
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
See Note 7.
Income Taxes
Income Taxes
 
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.
 
APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits.  The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates.
 
In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.
 
During the year ended December 31, 2013, IRS guidance was released which provided clarification regarding an APS tax accounting method change approved by the IRS in the third quarter of 2009. As a result of this guidance, uncertain tax positions decreased $67 million. Additionally, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, which further reduced uncertain tax positions by approximately $41 million. These reductions in uncertain tax positions were materially offset by an increase in deferred tax liabilities.

Included in the current income tax receivable on the Consolidated Balance Sheets as of December 31, 2013 was $133 million that represented an anticipated IRS refund related to the finalized examinations of tax years ended December 31, 2008 and 2009. Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations has been accounted for in the Consolidated Balance Sheets as of December 31, 2013 and 2014.
 
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18).  As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.
 
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
 
2014
 
2013
 
2012
Total unrecognized tax benefits, January 1
$
41,997

 
$
133,422

 
$
136,005

Additions for tax positions of the current year
4,309

 
3,516

 
5,167

Additions for tax positions of prior years
751

 
13,158

 

Reductions for tax positions of prior years for:
 

 
 

 
 

Changes in judgment
(2,282
)
 
(108,099
)
 
(7,729
)
Settlements with taxing authorities

 

 

Lapses of applicable statute of limitations

 

 
(21
)
Total unrecognized tax benefits, December 31
$
44,775

 
$
41,997

 
$
133,422


 
Included in the balances of unrecognized tax benefits at December 31, 2014, 2013 and 2012 were approximately $11 million, $10 million and $10 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
 
As of the balance sheet date, the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.
 
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, $26 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Consolidated Balance Sheets as of December 31, 2014.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense.  The amount of interest recognized in the Consolidated Statements of Income related to unrecognized tax benefits was a pre-tax expense of $1 million for 2014, a pre-tax benefit of $4 million for 2013, and a pre-tax expense of $4 million for 2012.
 
The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2014 and December 31, 2013 and $13 million as of December 31, 2012.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2014, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
 
The components of income tax expense are as follows (dollars in thousands):
 
Year Ended December 31,
 
2014
 
2013
 
2012
Current:
 

 
 

 
 

Federal
$
25,054

 
$
(81,784
)
 
$
(3,493
)
State
10,382

 
10,537

 
8,395

Total current
35,436

 
(71,247
)
 
4,902

Deferred:
 

 
 

 
 

Federal
167,365

 
279,973

 
200,322

State
17,904

 
21,865

 
28,280

Total deferred
185,269

 
301,838

 
228,602

Total income tax expense
220,705

 
230,591

 
233,504

Less: income tax benefit on discontinued operations

 

 
(3,813
)
Income tax expense — continuing operations
$
220,705

 
$
230,591

 
$
237,317


 
The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Federal income tax expense at 35% statutory rate
$
225,540

 
$
234,695

 
$
229,709

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

State income tax net of federal income tax benefit
18,149

 
21,387

 
23,819

Credits and favorable adjustments related to prior years resolved in current year

 
(3,356
)
 

Medicare Subsidy Part-D
830

 
823

 
483

Allowance for equity funds used during construction (see Note 1)
(8,523
)
 
(6,997
)
 
(6,158
)
Palo Verde VIE noncontrolling interest (see Note 18)
(9,135
)
 
(11,862
)
 
(11,065
)
Investment tax credit amortization
(4,928
)
 
(3,548
)
 
(2,030
)
Other
(1,228
)
 
(551
)
 
2,559

Income tax expense — continuing operations
$
220,705

 
$
230,591

 
$
237,317


 
The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
 
December 31,
 
2014
 
2013
Current asset
$
122,232

 
$
91,152

Long-term liability
(2,582,636
)
 
(2,351,882
)
Deferred income taxes — net
$
(2,460,404
)
 
$
(2,260,730
)

 
On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2014, APS has recorded a regulatory liability of $74 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
 
On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2014, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
 
The components of the net deferred income tax liability were as follows (dollars in thousands):
 
 
December 31,
 
2014
 
2013
DEFERRED TAX ASSETS
 

 
 

Risk management activities
$
57,505

 
$
44,920

Regulatory liabilities:
 

 
 

Asset retirement obligation and removal costs
229,772

 
235,959

Unamortized investment tax credits
96,232

 
82,116

Other postretirement benefits
90,496

 

Other
60,409

 
42,609

Pension liabilities
205,227

 
140,773

Other postretirement liabilities

 
57,869

Renewable energy incentives
65,169

 
65,434

Credit and loss carryforwards
68,347

 
133,070

Other
138,729

 
148,492

Total deferred tax assets
1,011,886

 
951,242

DEFERRED TAX LIABILITIES
 

 
 

Plant-related
(2,958,369
)
 
(2,903,730
)
Risk management activities
(12,171
)
 
(16,191
)
Other postretirement assets
(59,170
)
 

Regulatory assets:
 

 
 

Allowance for equity funds used during construction
(48,286
)
 
(43,058
)
Deferred fuel and purchased power
(2,498
)
 
(8,282
)
Deferred fuel and purchased power — mark-to-market
(38,187
)
 
(13,343
)
Pension and other postretirement benefits
(191,747
)
 
(129,250
)
Retired power plant costs (see Note 3)
(57,255
)
 
(8,199
)
Other
(99,123
)
 
(85,003
)
Other
(5,484
)
 
(4,916
)
Total deferred tax liabilities
(3,472,290
)
 
(3,211,972
)
Deferred income taxes — net
$
(2,460,404
)
 
$
(2,260,730
)

 
As of December 31, 2014, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $90 million, which first begin to expire in 2031, and other federal and state loss carryforwards of $4 million, which first begin to expire in 2019. The credit and loss carryforwards amount above has been reduced by $26 million of unrecognized tax benefits as a result of the guidance adopted in January 2014, as disclosed above.
Income Taxes
 
APS is included in Pinnacle West’s consolidated tax return.  However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’s taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.
 
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted tax rates.
 
APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits.  The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits ("ITCs") and the change in income tax rates.
 
In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property, with such amortization applied as a credit to reduce current income tax expense in the statement of income.
 
During the year ended December 31, 2013, IRS guidance was released which provided clarification regarding an APS tax accounting method change approved by the IRS in the third quarter of 2009. As a result of this guidance, uncertain tax positions decreased $67 million. Additionally, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, which further reduced uncertain tax positions by approximately $41 million. These reductions in uncertain tax positions were materially offset by an increase in deferred tax liabilities.

The $135 million current income tax receivable on APS’s Consolidated Balance Sheets as of December 31, 2013 represented an anticipated IRS refund related to the finalized examinations of tax years ended December 31, 2008 and 2009. Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015 resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations has been accounted for in APS's Consolidated Balance Sheets as of December 31, 2013 and 2014.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18).  As a result, there is no income tax expense associated with the VIEs recorded on APS’s Consolidated Statements of Income.
 
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
 
 
2014
 
2013
 
2012
Total unrecognized tax benefits, January 1
$
41,997

 
$
133,241

 
$
135,824

Additions for tax positions of the current year
4,309

 
3,516

 
5,167

Additions for tax positions of prior years
751

 
13,158

 

Reductions for tax positions of prior years for:
 

 
 

 
 

Changes in judgment
(2,282
)
 
(107,918
)
 
(7,729
)
Settlements with taxing authorities

 

 

Lapses of applicable statute of limitations

 

 
(21
)
Total unrecognized tax benefits, December 31
$
44,775

 
$
41,997

 
$
133,241


 
Included in the balance of unrecognized tax benefits at December 31, 2014, 2013 and 2012 were approximately $11 million, $10 million and $10 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
 
As of the balance sheet date, the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.
 
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.  The adoption of this guidance did not have any impact on APS's Consolidated Balance Sheets as of December 31, 2014.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Statements of Income as income tax expense.  The amount of interest recognized in the Statements of Income related to unrecognized tax benefits was a pre-tax expense of $1 million for 2014, a pre-tax benefit of $4 million for 2013 and a pre-tax expense of $4 million for 2012.
 
The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $1 million as of December 31, 2014, less than $1 million as of December 31, 2013 and $13 million as of December 31, 2012.  To the extent that matters are settled favorably, this amount could be reversed and decrease our effective tax rate.  Additionally, as of December 31, 2014, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
 
The components of APS’s income tax expense are as follows (dollars in thousands): 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Current:
 

 
 

 
 

Federal
$
40,115

 
$
(97,531
)
 
$
(11,650
)
State
15,598

 
11,983

 
12,308

Total current
55,713

 
(85,548
)
 
658

Deferred:
 

 
 

 
 

Federal
165,027

 
305,389

 
216,367

State
16,620

 
25,254

 
27,371

Total deferred
181,647

 
330,643

 
243,738

Total income tax expense
$
237,360

 
$
245,095

 
$
244,396


 
On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.
 
The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Federal income tax expense at 35% statutory rate
$
239,638

 
$
246,384

 
$
235,027

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

State income tax net of federal income tax benefit
21,148

 
23,970

 
25,379

Credits and favorable adjustments related to prior years resolved in current year

 
(3,231
)
 

Medicare Subsidy Part-D
830

 
823

 
483

Allowance for equity funds used during construction (see Note 1)
(8,523
)
 
(6,997
)
 
(6,158
)
Palo Verde VIE noncontrolling interest (see Note 18)
(9,135
)
 
(11,862
)
 
(11,065
)
Investment tax credit amortization
(4,928
)
 
(3,548
)
 
(2,030
)
Other
(1,670
)
 
(444
)
 
2,760

Income tax expense
$
237,360

 
$
245,095

 
$
244,396


 
The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands): 
 
December 31,
 
2014
 
2013
Current asset (liability)
$
55,253

 
$
(2,033
)
Long-term liability
(2,571,365
)
 
(2,347,724
)
Deferred income taxes — net
$
(2,516,112
)
 
$
(2,349,757
)

 
On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2014, APS has recorded a regulatory liability of $74 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
 
On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2014, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
 
The components of the net deferred income tax liability were as follows (dollars in thousands):
 
 
December 31,
 
2014
 
2013
DEFERRED TAX ASSETS
 

 
 

Regulatory liabilities:
 

 
 

Asset retirement obligation and removal costs
$
229,772

 
$
235,959

Unamortized investment tax credits
96,232

 
82,116

Other postretirement benefits
90,496

 

Other
60,409

 
42,609

Risk management activities
57,505

 
44,920

Pension liabilities
194,541

 
132,263

Other postretirement liabilities

 
53,950

Renewable energy incentives
65,169

 
65,434

Credit and loss carryforwards

 
38,183

Other
161,379

 
166,781

Total deferred tax assets
955,503

 
862,215

DEFERRED TAX LIABILITIES
 

 
 

Plant-related
(2,958,369
)
 
(2,903,730
)
Risk management activities
(12,171
)
 
(16,191
)
Other postretirement benefit assets
(58,495
)
 

Regulatory assets:
 

 
 

Allowance for equity funds used during construction
(48,286
)
 
(43,058
)
Deferred fuel and purchased power
(2,498
)
 
(8,282
)
Deferred fuel and purchased power — mark-to-market
(38,187
)
 
(13,343
)
Pension and other postretirement benefits
(191,747
)
 
(129,250
)
Retired power plant costs (see Note 3)
(57,255
)
 
(8,199
)
Other
(99,123
)
 
(85,003
)
Other
(5,484
)
 
(4,916
)
Total deferred tax liabilities
(3,471,615
)
 
(3,211,972
)
Deferred income taxes — net
$
(2,516,112
)
 
$
(2,349,757
)
Lines of Credit and Short-Term Borrowings
Lines of Credit and Short-Term Borrowings
Lines of Credit and Short-Term Borrowings
 
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2014 (dollars in millions):
 
Credit Facility
 
Expiration
 
Amount
Committed
 
Unused
Amount (a)
 
Commitment
Fees
Pinnacle West Revolving Credit Facility
 
May 2019
 
$
200

 
$
200

 
0.175
%
APS Revolving Credit Facility
 
May 2019
 
500

 
500

 
0.125
%
APS Revolving Credit Facility
 
April 2018
 
500

 
353

 
0.125
%
Total
 
 
 
$
1,200

 
$
1,053

 
 



(a)
At December 31, 2014, APS had $147 million of outstanding commercial paper.  Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $853 million.
 
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 December 31, 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 December 31, 2014, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS
 
On May 9, 2014, APS refinanced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019.
 
At December 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million credit 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 December 31, 2014, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  In addition, APS had commercial paper borrowings of $147 million at December 31, 2014.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2013 (dollars in millions):
 
Credit Facility
 
Expiration
 
Amount
Committed
 
Unused
Amount (a)
 
Commitment
Fees
Pinnacle West Revolving Credit Facility
 
November 2016
 
$
200

 
$
200

 
0.175
%
APS Revolving Credit Facility
 
November 2016
 
500

 
347

 
0.125
%
APS Revolving Credit Facility
 
April 2018
 
500

 
500

 
0.125
%
Total
 
 
 
$
1,200

 
$
1,047

 
 



(a)
At December 31, 2013, APS had $153 million of outstanding commercial paper.  Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $847 million.
 
Pinnacle West
 
At December 31, 2013, the Pinnacle West credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At December 31, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.
 
APS
 
On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility.  The new revolving credit facility matures in April 2018.

At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016.  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS can 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 December 31, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  In addition, APS had commercial paper borrowings of $153 million at December 31, 2013.
 
See “Financial Assurances” in Note 10 for a discussion of APS’s separate outstanding letters of credit.
 
Debt Provisions
 
Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.  On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt.  This financing order is set to expire on December 31, 2017.
Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters
  Long-Term Debt and Liquidity Matters
 
All of Pinnacle West’s and APS’s debt is unsecured.  The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2014 and 2013 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2014
 
2013
APS
 
 
 
 
 

 
 

Pollution Control Bonds:
 
 
 
 
 

 
 

Variable
2029-2038
 
(b)
 
$
156,405

 
$
75,580

Fixed
2024-2034
 
0.45%-5.75%
 
249,300

 
426,125

Total Pollution Control Bonds
 
 
 
 
405,705

 
501,705

Senior unsecured notes
2015-2044
 
3.35%-8.75%
 
2,875,000

 
2,675,000

Palo Verde sale leaseback lessor notes
2015
 
8.00%
 
13,420

 
38,869

Unamortized discount
 
 
 
 
(9,206
)
 
(8,732
)
Unamortized premium
 
 
 
 
4,866

 
5,047

Total APS long-term debt
 
 
 
 
3,289,785

 
3,211,889

Less current maturities
(d)
 
 
 
383,570

 
540,424

Total APS long-term debt less current maturities
 
 
 
 
2,906,215

 
2,671,465

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(c)
 
125,000

 
125,000

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
3,031,215

 
$
2,796,465


(a)                                 This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)                                 The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.27% at December 31, 2014 and 0.03%-0.06% at December 31, 2013.
(c)                                  The weighted-average interest rate was 1.019% at December 31, 2014 and 1.269% at December 31, 2013.
(d)                                 Current maturities include $70 million of pollution control bonds expected to be remarketed in 2015 and $300 million in senior unsecured notes that mature in 2015.

 
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in millions):
Year
 
Consolidated
Pinnacle West
 
Consolidated
APS
2015
 
$
384

 
$
384

2016
 
357

 
357

2017
 
157

 
32

2018
 
32

 
32

2019
 
500

 
500

Thereafter
 
1,989

 
1,989

Total
 
$
3,419

 
$
3,294


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

 
$
125

 
$
125

 
$
125

APS
3,290

 
3,714

 
3,212

 
3,454

Total
$
3,415

 
$
3,839

 
$
3,337

 
$
3,579


 
Credit Facilities and Debt Issuances
 
Pinnacle West

On December 31, 2014, Pinnacle West entered into a $125 million term loan facility that matures December 31, 2017. Pinnacle West used the proceeds to repay and refinance the term loan facility that would have matured in November 2015.

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.
 
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 SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used in 2013 to re-acquire the two series of tax-exempt indebtedness.

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 Consolidated Balance Sheets at December 31, 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.
 
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 current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014. On October 1, 2014, APS remarketed all $32 million of the 2009 Series C Bonds, which are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2014. We expect to remarket or refinance all $32 million of the 2009 Series B Bonds within the next twelve months. 
 
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 Consolidated Balance Sheets at December 31, 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 June 30, 2014.

On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.
 
See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.
 
Debt Provisions
 
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At December 31, 2014, the ratio was approximately 46% for Pinnacle West and 45% for APS.  Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.  See further discussion of “cross-default” provisions below.
 
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.  However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
 
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.  All of APS’s bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements.  Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.
 
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 December 31, 2014, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.0 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.  Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
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 (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries.  All new employees participate in the account balance plan.  Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant.  The pension plan covers nearly all employees.  The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors.  Our employees do not contribute to the plans.  We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors an other postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries.  This plan provides medical and life insurance benefits to retired employees.  Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.  For the medical insurance plan, retirees make contributions to cover a portion of the plan costs.  For the life insurance plan, retirees do not make contributions.  We retain the right to change or eliminate these benefits.

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). The Company will provide a subsidy allowing post-65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The remeasurement reduced net periodic benefit costs in 2014 by $10 million ($5 million of which reduced expense), which was recognized during the fourth quarter of 2014. The September 30, 2014 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 December 31, 2014 of $152 million and $231 million, respectively.
 
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 trust account to pay for active union employee medical costs.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.  See Note 13 for further discussion of how fair values are determined.  Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.
 
A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates.  Accordingly, these changes are recorded as a regulatory asset or regulatory liability.  In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012.  We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011.  Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over 3 years beginning in July 2012.  We amortized approximately $8 million during 2014, $8 million during 2013, and $4 million during 2012.
 
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):
 
Pension
 
Other Benefits
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Service cost-benefits earned during the period
$
53,080

 
$
64,195

 
$
63,502

 
$
18,139

 
$
23,597

 
$
27,163

Interest cost on benefit obligation
129,194

 
112,392

 
119,586

 
41,243

 
41,536

 
46,467

Expected return on plan assets
(158,998
)
 
(146,333
)
 
(140,979
)
 
(46,400
)
 
(45,717
)
 
(45,793
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Transition obligation

 

 

 

 

 
452

Prior service cost (credit)
869

 
1,097

 
1,143

 
(9,626
)
 
(179
)
 
(179
)
Net actuarial loss
10,963

 
39,852

 
44,250

 
1,175

 
11,310

 
20,233

Net periodic benefit cost
$
35,108

 
$
71,203

 
$
87,502

 
$
4,531

 
$
30,547

 
$
48,343

Portion of cost charged to expense
$
21,985

 
$
38,968

 
$
36,333

 
$
6,000

 
$
18,469

 
$
19,321


 
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2014 and 2013 (dollars in thousands):
 
Pension
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
2,646,530

 
$
2,850,846

 
$
890,418

 
$
990,418

Service cost
53,080

 
64,195

 
18,139

 
23,597

Interest cost
129,194

 
112,392

 
41,243

 
41,536

Benefit payments
(128,550
)
 
(125,269
)
 
(29,054
)
 
(26,675
)
Actuarial (gain) loss
378,394

 
(255,634
)
 
150,188

 
(138,458
)
Plan amendments

 

 
(388,599
)
 

Benefit obligation at December 31
3,078,648

 
2,646,530

 
682,335

 
890,418

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,264,121

 
2,079,181

 
748,339

 
684,221

Actual return on plan assets
292,992

 
150,546

 
105,223

 
76,995

Employer contributions
175,000

 
140,500

 
770

 
14,438

Benefit payments
(116,709
)
 
(106,106
)
 
(19,707
)
 
(27,315
)
Fair value of plan assets at December 31
2,615,404

 
2,264,121

 
834,625

 
748,339

Funded Status at December 31
$
(463,244
)
 
$
(382,409
)
 
$
152,290

 
$
(142,079
)


The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2014 and 2013 (dollars in thousands):
 
2014
 
2013
Projected benefit obligation
$
3,078,648

 
$
2,646,530

Accumulated benefit obligation
2,873,741

 
2,469,889

Fair value of plan assets
2,615,404

 
2,264,121


 
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2014 and 2013 (dollars in thousands):
 
Pension
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
Noncurrent asset
$

 
$

 
$
152,290

 
$

Current liability
(9,508
)
 
(10,860
)
 

 

Noncurrent liability
(453,736
)
 
(371,549
)
 

 
(142,079
)
Net amount recognized
$
(463,244
)
 
$
(382,409
)
 
$
152,290

 
$
(142,079
)

 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2014 and 2013 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
Net actuarial loss
$
577,976

 
$
344,540

 
$
148,006

 
$
57,816

Prior service cost (credit)
1,203

 
2,072

 
(379,269
)
 
(296
)
APS’s portion recorded as a regulatory (asset) liability
(485,037
)
 
(265,107
)
 
230,916

 
(49,298
)
Income tax expense (benefit)
(36,890
)
 
(32,204
)
 
851

 
(2,528
)
Accumulated other comprehensive loss
$
57,252

 
$
49,301

 
$
504

 
$
5,694


 
The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2015 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
28,180

 
$
5,651

Prior service cost (credit)
595

 
(37,968
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2014
$
28,775

 
$
(32,317
)


The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
 
Benefit Obligations
As of December 31,
 
Benefit Costs
For the Years Ended December 31,
 
2014
 
2013
 
2014
 
2013
 
2012
 
 
 
 
 
January - September
October - December
 
 
 
 
Discount rate – pension
4.02
%
 
4.88
%
 
4.88
%
4.88
%
 
4.01
%
 
4.42
%
Discount rate – other benefits
4.14
%
 
5.10
%
 
5.10
%
4.41
%
 
4.20
%
 
4.59
%
Rate of compensation increase
4.00
%
 
4.00
%
 
4.00
%
4.00
%
 
4.00
%
 
4.00
%
Expected long-term return on plan assets - pension
N/A

 
N/A

 
6.90
%
6.90
%
 
7.00
%
 
7.75
%
Expected long-term return on plan assets - other benefits
N/A

 
N/A

 
6.80
%
4.25
%
 
7.00
%
 
7.75
%
Initial healthcare cost trend rate (pre-65 participants)
7.00
%
 
7.50
%
 
7.50
%
7.50
%
 
7.50
%
 
7.50
%
Initial healthcare cost trend rate (post-65 participants)
5.00
%
 
7.50
%
 
7.50
%
5.00
%
 
7.50
%
 
7.50
%
Ultimate healthcare cost trend rate
5.00
%
 
5.00
%
 
5.00
%
5.00
%
 
5.00
%
 
5.00
%
Number of years to ultimate trend rate (pre-65 participants)
4

 
4

 
4

4

 
4

 
4

Number of years to ultimate trend rate (post-65 participants)
0

 
4

 
4

0

 
4

 
4


 
In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan.  For 2015, we are assuming a 6.90% long-term rate of return for pension assets and 4.74% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final reports on its recommended mortality basis (“RP-2014 Mortality Tables Report” and "Mortality Improvement Scale MP-2014 Report").  At December 31, 2014, we updated our mortality assumptions using the recommended basis with modifications to better reflect our plan experience and additional data regarding mortality trends.  The updated mortality assumptions resulted in a $67 million increase in Pinnacle West’s pension and other postretirement obligations, which was offset by the related regulatory asset, regulatory liability and accumulated other comprehensive income.

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.  A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in millions): 
 
1% Increase
 
1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
$
10

 
$
(4
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
12

 
(9
)
Effect on the accumulated other postretirement benefit obligation
110

 
(88
)

 
Plan Assets
 
The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”).  The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.
 
The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations.  To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets.  The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status.  The plan’s funded status is reviewed on at least a monthly basis.
 
Long-term fixed income assets, also known as liability-hedging assets, are designed to offset changes in the benefit obligations due to changes in interest rates.  Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury, other government agencies, and corporations.  Long-term fixed income assets may also include interest rate swaps, U.S. Treasury futures and other instruments.
 
Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.  Return-generating assets are composed of U.S. equities, international equities, and alternative investments.  International equities include investments in both developed and emerging markets.  Alternative investments include investments in real estate, private equity and various other strategies.  The plan may hold investments in return-generating assets by holding securities in partnerships and common and collective trusts.
 
Based on the IPS, and given the pension plan’s funded status at year-end 2014, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 39% to 45%.  The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments.  The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade.  As of December 31, 2014, long-term fixed income assets represented 61% of total pension plan assets, and return-generating assets represented 39% of total pension plan assets.
 
As of December 31, 2014, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability.  Some of these asset allocation target mixes vary with the plan’s funded status.  As of December 31, 2014, investment in fixed income assets represented 43% of the other postretirement benefit plan total assets, and non-fixed income assets represented 57% of the other postretirement benefit plan’s assets.  Fixed income assets are primarily invested in corporate bonds of investment-grade U.S. issuers, and U.S. Treasuries.  Non-fixed income assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both emerging and developed markets.
 
See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied.  The plans invest directly in fixed income and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of partnerships and common and collective trusts.  Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1.  Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality.  These instruments are classified as Level 2.
 
The common and collective trusts, which are similar to mutual funds, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index).  Common and collective trusts are valued using the concept of net asset value (“NAV”), which is a value derived from the quoted active market prices of the underlying securities.  The plans’ common and collective real estate trust is valued using NAV, which is derived from the appraised values of the trust’s underlying real estate assets.  As of December 31, 2014, the plans were able to transact in the common and collective trusts at NAV and accordingly classify these investments as Level 2.  Because the trust’s shares are offered to a limited group of investors, they are not considered to be traded in an active market.

Investments in partnerships are also valued using the concept of NAV, which is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Partnerships are classified as Level 2 if the plan is able to transact in the partnership at the NAV. At December 31, 2014, certain partnerships have been classified as Level 3 due to restrictions that limit the plan's ability to transact in these partnerships at the NAV. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerhips; as of December 31, 2014, $30 million of these commitments have been funded.
 
The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value.  We have internal control procedures 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.

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2014, by asset category, are as follows (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other (b)
 
Balance at December 31, 2014
Pension Plan:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
387

 
$

 
$

 
$

 
$
387

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate

 
1,162,096

 

 

 
1,162,096

U.S. Treasury
291,817

 

 

 

 
291,817

Other (a)

 
113,265

 

 

 
113,265

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
246,387

 

 

 

 
246,387

International Companies
18,069

 

 

 

 
18,069

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
127,336

 

 

 
127,336

International Equities

 
317,167

 

 

 
317,167

Real estate

 
129,715

 

 

 
129,715

Partnerships

 
138,337

 
27,929

 

 
166,266

Short-term investments and other

 
26,016

 

 
16,883

 
42,899

Total Pension Plan
$
556,660

 
$
2,013,932

 
$
27,929

 
$
16,883

 
$
2,615,404

Other Benefits:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
318

 
$

 
$

 
$

 
$
318

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate

 
187,961

 

 

 
187,961

U.S. Treasury
130,967

 

 

 

 
130,967

Other (a)

 
35,291

 

 

 
35,291

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
265,106

 

 

 

 
265,106

International Companies
17,813

 

 

 

 
17,813

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
88,258

 

 

 
88,258

International Equities

 
85,746

 

 

 
85,746

Real Estate

 
11,657

 

 

 
11,657

Short-term investments and other

 
7,408

 

 
4,100

 
11,508

Total Other Benefits
$
414,204

 
$
416,321

 
$

 
$
4,100

 
$
834,625


(a)
This category consists primarily of debt securities issued by municipalities.
(b)
Represents plan receivables and payables.

 
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2013, by asset category, are as follows (dollars in thousands):
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other (b)
 
Balance at December 31, 2013
Pension Plan:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
504

 
$

 
$

 
$

 
$
504

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate

 
898,621

 

 

 
898,621

U.S. Treasury
231,590

 

 

 

 
231,590

Other (a)

 
84,011

 

 

 
84,011

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
239,036

 

 

 

 
239,036

International Companies
19,429

 

 

 

 
19,429

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
116,150

 

 

 
116,150

International Equities

 
367,551

 

 

 
367,551

Fixed Income

 
137,520

 

 

 
137,520

Real estate

 
119,739

 

 

 
119,739

Partnerships

 

 
8,660

 

 
8,660

Short-term investments and other

 
41,060

 

 
250

 
41,310

Total Pension Plan
$
490,559

 
$
1,764,652

 
$
8,660

 
$
250

 
$
2,264,121

Other Benefits:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
 

 
 

 
 

 
 

 
 

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate
$

 
$
153,888

 
$

 
$

 
$
153,888

U.S. Treasury
98,704

 

 

 

 
98,704

Other (a)

 
27,936

 

 

 
27,936

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
252,181

 

 

 

 
252,181

International Companies
20,892

 

 

 

 
20,892

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
80,751

 

 

 
80,751

International Equities

 
92,382

 

 

 
92,382

Real Estate

 
10,761

 

 

 
10,761

Short-term investments and other

 
8,414

 

 
2,430

 
10,844

Total Other Benefits
$
371,777

 
$
374,132

 
$

 
$
2,430

 
$
748,339


(a)
This category consists primarily of debt securities issued by municipalities.
(b)
Represents plan receivables and payables.

The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2014 and 2013 (dollars in thousands):
 
 
Pension
Partnerships
 
2014
 
2013
Beginning balance at January 1
 
$
8,660

 
$
2,419

Actual return on assets still held at December 31
 
927

 
(498
)
Purchases
 
19,984

 
7,377

Sales
 
(1,642
)
 
(638
)
Transfers in and/or out of Level 3
 

 

Ending balance at December 31
 
$
27,929

 
$
8,660


 
Contributions
 
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $175 million in 2014, $141 million in 2013, and $65 million in 2012.  The minimum contributions for the pension plan are zero for the next three years.  We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  With regard to contributions to our other postretirement benefit plans, we made a contribution of $1 million in 2014, $14 million in 2013, and $23 million in 2012.  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans. APS funds its share of the contributions.  APS’s share of the pension plan contribution was $175 million in 2014, $140 million in 2013, and $64 million in 2012.  APS’s share of the contributions to the other postretirement benefit plan was $1 million in 2014, $14 million in 2013, and $22 million in 2012.
 
Estimated Future Benefit Payments
 
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):
Year
 
Pension
 
Other Benefits
2015
 
$
139,013

 
$
25,134

2016
 
155,968

 
27,311

2017
 
160,080

 
29,253

2018
 
167,600

 
31,258

2019
 
177,470

 
33,190

Years 2020-2024
 
983,557

 
184,772


 
Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

Employee Savings Plan Benefits
 
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries.  In 2014, costs related to APS’s employees represented 99% of the total cost of this plan.  In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments.  Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions.  Pinnacle West recorded expenses for this plan of approximately $9 million for 2014, $9 million for 2013, and $8 million for 2012.
Leases
Leases
Leases
 
We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.
 
Total lease expense recognized in the Consolidated Statements of Income was $18 million in 2014, $18 million in 2013, and $19 million in 2012.  APS’s lease expense was $15 million in 2014, $15 million in 2013, and $16 million in 2012.
 
Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions):
Year
 
Pinnacle West
Consolidated
 
APS
2015
 
$
18

 
$
15

2016
 
6

 
6

2017
 
5

 
5

2018
 
4

 
4

2019
 
3

 
3

Thereafter
 
63

 
62

Total future lease commitments
 
$
99

 
$
95


 
In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.  As the primary beneficiary, APS consolidated these lessor trust entities.  The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 18 for a discussion of VIEs.
Jointly-Owned Facilities
Jointly-Owned Facilities
Jointly-Owned Facilities
 
APS shares ownership of some of its generating and transmission facilities with other companies.  We are responsible for our share of operating costs, as well as for providing our own financing.  Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation.  The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2014 (dollars in thousands):

 
 
Percent
Owned
 
 
 
Plant in
Service
 
Accumulated
Depreciation
 
Construction
Work in
Progress
Generating facilities:
 
 

 
 
 
 

 
 

 
 

Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,734,918

 
$
1,051,670

 
$
16,955

Palo Verde Unit 2 (a)
 
16.8
%
 

 
556,472

 
349,960

 
13,710

Palo Verde Common
 
28.0
%
 
(b)
 
612,190

 
224,208

 
68,896

Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
229,795

 

Four Corners Generating Station
 
63.0
%
 

 
811,648

 
578,772

 
33,150

Navajo Generating Station Units 1, 2 and 3
 
14.0
%
 

 
272,208

 
159,198

 
2,716

Cholla common facilities (c)
 
63.3
%
 
(b)
 
155,856

 
49,954

 
866

Transmission facilities:
 
 

 
 
 
 

 
 

 
 

ANPP 500kV System
 
33.6
%
 
 (b)
 
106,369

 
35,035

 
3,731

Navajo Southern System
 
22.5
%
 
(b)
 
59,994

 
18,119

 
1,113

Palo Verde — Yuma 500kV System
 
18.2
%
 
(b)
 
12,925

 
4,943

 
12

Four Corners Switchyards
 
47.5
%
 
 (b)
 
33,034

 
10,035

 
386

Phoenix — Mead System
 
17.1
%
 
(b)
 
39,777

 
12,843

 
105

Palo Verde — Estrella 500kV System
 
50.0
%
 
(b)
 
89,572

 
16,491

 
736

Morgan — Pinnacle Peak System
 
64.4
%
 
 (b)
 
130,840

 
8,970

 
1,690

Round Valley System
 
50.0
%
 
(b)
 
497

 
276

 
1

Palo Verde — Morgan System
 
90.0
%
 
(b)
 

 

 
69,377

Hassayampa - North Gila System
 
80.0
%
 
(b)
 
8,902

 
3,634

 
142,645


(a)
See Note 18.
(b)
Weighted-average of interests.
(c)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp.  The common facilities at Cholla are jointly-owned.
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 DOE in the United States Court of Federal Claims.  The lawsuit seeks to recover damages incurred due to DOE’s breach of the 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 NWPA.  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. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on current income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.
  
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 commercial insurance carriers.  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.
 
Fuel and Purchased Power Commitments and Purchase Obligations
 
APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2015 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $723 million in 2015; $747 million in 2016; $630 million in 2017; $610 million in 2018; $583 million in 2019; and $8.2 billion thereafter.  However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
 
Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions.  The current coal contracts with take-or-pay provisions have terms expiring through 2031.
 
The following table summarizes our estimated coal take-or-pay commitments (dollars in millions):
 
 
 Years Ended December 31,
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
Coal take-or-pay commitments (a)
$
151

 
$
171

 
$
195

 
$
190

 
$
194

 
$
2,469

 
(a)
Total take-or-pay commitments are approximately $3.4 billion.  The total net present value of these commitments is approximately $2.2 billion.
 
APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual payments under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in millions):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Total payments
$
237

 
$
188

 
$
196


 
Renewable Energy Credits
 
APS has entered into contracts to purchase renewable energy credits to comply with the RES.  APS estimates the contract requirements to be approximately $46 million in 2015; $42 million in 2016; $42 million in 2017; $42 million in 2018; $42 million in 2019; and $448 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.  Also, these amounts do not include purchases of renewable energy credits that are associated with purchased power contracts.
 
Coal Mine Reclamation Obligations
 
APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation.  We account for contemporaneous reclamation costs as part of the cost of the delivered coal.  We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation.  These studies utilize various assumptions to estimate the future costs.  Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $198 million at December 31, 2014 and $207 million at December 31, 2013.  Under our current coal supply agreements, we expect to make payments to certain coal providers for the final mine reclamation as follows:  $1 million in 2015; $15 million in 2016; $17 million in 2017; $18 million in 2018; $19 million in 2019; and $281 million thereafter.  Any amendments to current coal supply agreements may change the timing of the reimbursement.

Superfund-Related Matters
 
Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs.  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, 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, 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 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 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 fully briefed and 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 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 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 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 rulemaking imposing new requirements on Four Corners, Cholla and the Navajo Plant.  EPA and ADEQ will require these plants to install pollution control equipment that constitutes the 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.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5, which would increase our share of the cost of these controls by approximately $40 million. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP proposal, 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 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.  SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.
 
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million.  The Navajo Plant currently disposes of CCR in a dry landfill storage area. At this time, SRP, the operating agent for the Navajo Plant, is analyzing the operations that would be covered by the rule and any resulting compliance costs.

Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, 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, ESA, 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 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; the court scheduled oral argument for March 9, 2015.
 
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 December 31, 2014, approximately $109 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.  These letters of credit will expire in 2015, 2016, and 2017. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 18 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 December 31, 2014.  Additionally, APS has issued letters of credit to support collateral obligations under a natural gas tolling contract entered into with a third party.  At December 31, 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 December 31, 2014.
Asset Retirement Obligations
Asset Retirement Obligations
Asset Retirement Obligations
 
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. 

The Palo Verde asset retirement obligation primarily relates to final plant decommissioning.  This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.  The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal.  These agreements have a history of uninterrupted renewal that APS expects to continue.  As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

In 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 increase to the ARO in the amount of $20 million. Also in 2014, an updated Four Corners Units 1-3 coal-fired power plant decommissioning study was finalized, which resulted in an increase to the ARO of $24 million. In addition, Four Corners spent $30 million in actual decommissioning costs. Finally, in 2014 APS also recognized an ARO related to a new solar facility on leased property that requires the land to be returned to its original condition upon decommissioning of the plant, which resulted in an increase to the ARO of $6 million.

In 2013, a decommissioning study with updated cash flow estimates was completed for Palo Verde, which resulted in a decrease of $52 million. Also in 2013, APS finalized the transaction to acquire SCE’s interest in Four Corners. As part of that transaction, APS assumed SCE’s asset retirement obligation resulting in an increase to the ARO of $34 million. In addition, on December 30, 2013, APS also retired Four Corners Units 1-3 and began decommissioning activities. Finally, Four Corners spent $12 million in actual decommissioning costs. An update was made to the timing of the Units 1-3 decommissioning cash flows to coincide with the expected decommissioning activities. This update resulted in a decrease to the ARO of $4 million.
 
The following schedule shows the change in our asset retirement obligations for 2014 and 2013 (dollars in millions):

 
2014
 
2013
Asset retirement obligations at the beginning of year
$
347

 
$
357

Changes attributable to:
 

 
 

Accretion expense
24

 
24

Settlements
(30
)
 
(12
)
Assumed SCE’s obligation

 
34

Estimated cash flow revisions
44

 
(56
)
Newly incurred obligation
6

 

Asset retirement obligations at the end of year
$
391

 
$
347


 
As mentioned above, decommissioning activities for Four Corners Units 1-3 began in January 2014; and, $32 million of the total ARO at December 31, 2014, was classified as a current liability on the balance sheet. At December 31, 2013, $33 million of the total ARO of $347 million was 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.
Selected Quarterly Financial Data (Unaudited)
Selected Quarterly Financial Data (Unaudited) 

Consolidated quarterly financial information for 2014 and 2013 is provided in the tables below (dollars in thousands, except per share amounts).  Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

 
2014 Quarter Ended
 
2014
 
March 31,
 
June 30,
 
Sept. 30,
 
Dec. 31,
 
Total
Operating revenues
$
686,251

 
$
906,264

 
$
1,172,667

 
$
726,450

 
$
3,491,632

Operations and maintenance
212,882

 
211,222

 
223,418

 
260,503

 
908,025

Operating income
75,170

 
254,113

 
421,775

 
60,184

 
811,242

Income taxes
6,405

 
74,540

 
134,753

 
5,007

 
220,705

Income from continuing operations
24,691

 
141,384

 
248,086

 
9,535

 
423,696

Net income attributable to common shareholders
15,766

 
132,458

 
243,961

 
5,410

 
397,595

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.14

 
$
1.20

 
$
2.20

 
$
0.05

 
$
3.59

Net income attributable to common shareholders — Diluted
0.14

 
1.19

 
2.20

 
0.05

 
3.58

 
 
2013 Quarter Ended
 
2013
 
March 31,
 
June 30,
 
Sept. 30,
 
Dec. 31,
 
Total
Operating revenues
$
686,652

 
$
915,822

 
$
1,152,392

 
$
699,762

 
$
3,454,628

Operations and maintenance
223,250

 
229,300

 
233,323

 
238,854

 
924,727

Operating income
86,923

 
259,812

 
415,688

 
83,900

 
846,323

Income taxes
12,469

 
77,043

 
131,912

 
9,167

 
230,591

Income from continuing operations
32,836

 
139,598

 
234,718

 
32,814

 
439,966

Net income attributable to common shareholders
24,444

 
131,207

 
226,163

 
24,260

 
406,074

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.22

 
$
1.19

 
$
2.06

 
$
0.22

 
$
3.69

Net income attributable to common shareholders — Diluted
0.22

 
1.18

 
2.04

 
0.22

 
3.66

Selected Quarterly Financial Data (Unaudited)
 
Quarterly financial information for 2014 and 2013 is as follows (dollars in thousands):
 
 
2014 Quarter Ended,
 
2014
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
685,545

 
$
905,578

 
$
1,172,190

 
$
725,633

 
$
3,488,946

Operations and maintenance
208,285

 
208,059

 
212,430

 
253,668

 
882,442

Operating income
69,635

 
180,394

 
287,928

 
54,835

 
592,792

Net income attributable to common shareholder
19,518

 
134,916

 
251,047

 
15,738

 
421,219

 
 
2013 Quarter Ended,
 
2013
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
685,827

 
$
915,065

 
$
1,151,535

 
$
698,824

 
$
3,451,251

Operations and maintenance
220,752

 
224,950

 
222,617

 
229,505

 
897,824

Operating income
74,862

 
183,728

 
284,251

 
79,024

 
621,865

Net income attributable to common shareholder
26,042

 
133,949

 
234,954

 
30,024

 
424,969

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 that are redeemable and valued based on NAV, such as common and collective trusts and commingled funds.
 
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 7 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 Trust
 
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 19 for additional discussion about our nuclear decommissioning trust.
 
Fair Value Tables
 
The following table presents the fair value at December 31, 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 December 31, 2014
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity Contracts
$

 
$
21

 
$
33

 
$
(23
)
 
(b)
 
$
31

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds

 
310

 

 

 
 
 
310

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
119

 

 

 

 
 
 
119

Cash and cash equivalent funds

 
11

 

 
(7
)
 
(c)
 
4

Corporate debt

 
109

 

 

 
 
 
109

Mortgage-backed securities

 
89

 

 

 
 
 
89

Municipality bonds

 
69

 

 

 
 
 
69

Other

 
14

 

 

 
 
 
14

Subtotal nuclear decommissioning trust
119

 
602

 

 
(7
)
 

 
714

Total
$
119

 
$
623

 
$
33

 
$
(30
)
 

 
$
745

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$

 
$
(95
)
 
$
(74
)
 
$
59

 
(b)
 
$
(110
)

(a)
Primarily consists of heat rate options and other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral.  See Note 16.
(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 other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral.  See Note 16.
(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 December 31, 2014 and December 31, 2013:
 
 
December 31, 2014
Fair Value (millions)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
30

 
$
56

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$19.51 - $56.72
 
$
35.27

Option Contracts (b)

 
15

 
Option model
 
Electricity forward price (per MWh)
 
$32.14 - $66.09
 
$
45.83

 
 

 
 

 
 
 
Natural gas forward price (per MMbtu)
 
$3.18 - $3.29
 
$
3.25

 
 

 
 

 
 
 
Electricity price volatilities
 
23% - 63%
 
41
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
23% - 41%
 
31
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
3

 
3

 
Discounted cash flows
 
Natural gas forward price (per MMbtu)
 
$2.98 - $4.13
 
$
3.45

Total
$
33

 
$
74

 
 
 
 
 
 
 
 


(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
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
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 natural gas price volatilities are estimated 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 years ended December 31, 2014 and 2013 (dollars in millions):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2014
 
2013
Net derivative balance at beginning of period
 
$
(49
)
 
$
(48
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 

 

Included in OCI
 

 

Deferred as a regulatory asset or liability
 

 
(10
)
Settlements
 
12

 
10

Transfers into Level 3 from Level 2
 
(2
)
 

Transfers from Level 3 into Level 2
 
(2
)
 
(1
)
Net derivative balance at end of period
 
$
(41
)
 
$
(49
)
Net unrealized gains included in earnings related to instruments still held at end of period
 
$

 
$


 
Amounts included in earnings are recorded in either 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 short-term borrowings approximate fair value.  Our short-term borrowings are classified within Level 2 of the fair value hierarchy.  See Note 6 for our long-term debt fair values.
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 continuing operations attributable to common shareholders for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per share amounts):
 
2014
 
2013
 
2012
Income from continuing operations attributable to common shareholders
$
397,595

 
$
406,074

 
$
387,380

Weighted average common shares outstanding — basic
110,626

 
109,984

 
109,510

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
552

 
822

 
1,017

Weighted average common shares outstanding — diluted
111,178

 
110,806

 
110,527

Earnings per average common share outstanding:
 
 
 
 
 
Income from continuing operations attributable to common shareholders — basic
$
3.59

 
$
3.69

 
$
3.54

Income from continuing operations attributable to common shareholders — diluted
$
3.58

 
$
3.66

 
$
3.50

Stock-Based Compensation
Stock-Based Compensation
      Stock-Based Compensation
 
Pinnacle West grants long-term incentive awards under the 2012 Long-Term Incentive Plan (“2012 Plan”) in the form of Stock Grants, Restricted Stock Units, Stock Units and Performance Shares and may grant restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.  The 2012 Plan, effective May 16, 2012, provides 4,595,500 common shares to be available for grant to eligible employees and members of the Board of Directors.  Awards made since 2012 were issued under the 2012 Plan, and prior awards from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”).

Restricted Stock Unit Awards, Stock Unit Awards and Stock Grants
 
Stock grants issued to non-officer members of the Board of Directors in 2014, 2013 and 2012 provided the members of the Board of Directors the option to elect to receive a stock grant, or to defer receipt until a later date and receive restricted stock units in 2012 and stock units in 2013 and 2014 in lieu of the stock grant.  The members of the Board of Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock.  The members of the Board of Directors may elect to receive payments either as of the last business day of the month following the month in which they separate from service on the Board of Directors, or as of a specified date, which must be after December 31 of the year in which the grant was received.  The deferred restricted stock units and stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment plus interest compounded quarterly.  The dividends and interest are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock.
 
Restricted stock units have been granted to officers and key employees in each year since 2008.  From 2008 through 2009, officers and key employees elected to receive payment in either cash or in fully transferable shares of stock, in exchange for each restricted stock unit on pre-established valuation dates.  From 2010 through 2014, officers and key employees elected to receive payment in either stock, or 50% in cash and 50% in stock.
 
Restricted stock unit awards vest and settle over a 4-year period.  In addition, officers and key employees accrue dividend rights on vested restricted stock units, equal to the amount of dividends that they would have received had they directly owned stock, equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly.  The dividends and interest for the 2008 and 2009 awards were paid in cash.  The dividends and interest for the 2010 through 2014 awards are paid in the same form as the restricted stock unit payment election.  Restricted stock unit awards are accounted for as a liability award, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date.  Compensation expense for retirement eligible participants is recognized immediately.
 
In December 2012, the Company granted a retention award of 50,617 restricted stock units to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West.  The award will vest and will be paid in shares of common stock on December 31, 2016, provided that he remains employed with the Company until the vesting date.  The award will accrue notional dividends equal to the amount of dividends that would have been received if the Chairman of the Board, President and Chief Executive Officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date.  The award can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met.
 
A grant of restricted stock unit awards was made to officers of the company on February 15, 2011, payable solely in shares of common stock upon the officer’s retirement or other separation of employment.  This award vested 50% on February 15, 2013 and 25% on February 15, 2014. The remaining award will vest 25% on February 15, 2015, provided that the officer remains employed on such date.  The officers will also accrue notional dividends equal to the amount of dividends that they would have received if they had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date.  Each additional restricted stock unit will proportionally vest on the same remaining vesting schedule that applies to the original restricted stock unit.
 
The following table is a summary of granted restricted stock units, stock units and stock grants and the weighted-average fair value for the 3 years ended 2014, 2013 and 2012
 
2014
 
2013
 
2012
Units granted
130,273

 
129,620

 
202,278

Grant date fair value (a) 
$
54.91

 
$
55.21

 
$
49.31

(a)
Weighted-average grant date fair value.
 
The following table is a summary of the status of restricted stock units, stock units and stock grants, as of December 31, 2014 and changes during the year.  This table represents only the stock portion of restricted stock units and stock units, per the election on payment discussed in the paragraph above:
 
Nonvested shares
 
Shares
 
Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2014
 
397,976

 
$
47.74

Granted
 
130,273

 
54.91

Vested
 
(161,283
)
 
45.55

Forfeited
 
(13,067
)
 
51.53

Nonvested at December 31, 2014
 
353,899

 
51.23


 
The amount of cash required to settle the payments on restricted stock units is (dollars in millions):
 
Year
 
2014
 
2013
 
2012
2008 Grant
 
$

 
$

 
$
1.9

2009 Grant
 

 
3.0

 
1.7

2010 Grant
 
2.3

 
2.3

 
0.6

2011 Grant
 
2.4

 
2.5

 
0.7

2012 Grant
 
2.1

 
2.2

 

2013 Grant
 
2.1

 

 


 
Performance Share Awards
 
Performance share awards have been granted to officers and key employees under the 2012 Plan since 2012 and under the 2007 Plan from 2009 to 2011.  Performance share awards contain two performance element criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met.
 
The 2014, 2013 and 2012 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period, as compared with the total shareholder return of all relevant companies in a specified utility index and the other 50% is based upon six non-financial separate performance metrics.  The exact number of shares issued will vary from 0% to 200% of the target award.  Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.
 
Performance share awards are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date.  Compensation expense for retirement eligible participants is recognized immediately.  Management also evaluates the probability of meeting the performance criteria at each balance sheet date.  If performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
 
The following table is a summary of the performance shares granted and the weighted-average fair value for the three years ended 2014, 2013 and 2012:
 
 
2014
 
2013
 
2012
Units granted (a)
166,244

 
176,332

 
185,878

Grant date fair value (b)
$
54.86

 
$
55.45

 
$
47.40


(a)                                 Reflects the target payout level.
(b)                                 Weighted-average grant date fair value.
 
The following table is a summary of the status of performance shares as of December 31, 2014 and changes during the year:
 
Nonvested shares (a)
 
Shares
 
Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2014
 
344,396

 
$
51.13

Granted
 
166,244

 
54.86

Increase in performance factor
 
86,558

 
47.40

Vested
 
(258,224
)
 
47.40

Forfeited
 
(14,744
)
 
53.30

Nonvested at December 31, 2014
 
324,230

 
54.92


(a)
Nonvested shares are reflected at target payout level.  The increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests.
 
Stock Options
 
The Company has not granted stock options since 2004 and has no stock options outstanding.

As of December 31, 2014, there was $15 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans.  That cost is expected to be recognized over a weighted-average period of 2 years.  The total fair value of shares vested during 2014, 2013 and 2012 was $20 million, $20 million and $19 million, respectively.
 
The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $33 million in 2014, $25 million in 2013, and $32 million in 2012.  The compensation cost that Pinnacle West has capitalized is immaterial for all years.  Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $13 million in 2014, $10 million in 2013, and $13 million in 2012.  APS’s share of compensation cost that has been charged against income was $33 million in 2014, $25 million in 2013, and $32 million in 2012.
 
Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans, and it does not expect to repurchase any shares except to satisfy tax withholding obligations upon the vesting of restricted stock units and performance shares.
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 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 13 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 December 31, 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
 
3,915

 
GWh
Gas
 
136

 
Bcf (a)
(a)
“Bcf” is Billion Cubic Feet.
 
Gains and Losses from Derivative Instruments
 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2014
 
2013
 
2012
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(372
)
 
$
(353
)
 
$
(37,663
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(21,415
)
 
(44,219
)
 
(99,007
)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Fuel and purchased power (b)
 

 

 
117


(a)
During the years ended December 31, 2014, 2013, and 2012, we had zero, zero, and $1.8 million of losses 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 $6 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 years ended December 31, 2014, 2013 and 2012 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2014
 
2013
 
2012
Net Gain Recognized in Income
 
Operating revenues
 
$
324

 
$
289

 
$
103

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(66,367
)
 
(10,449
)
 
(2,747
)
Total
 
 
 
$
(66,043
)
 
$
(10,160
)
 
$
(2,644
)

(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the 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 Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.
 
We do not offset a 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 Consolidated Balance Sheets as of December 31, 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 December 31, 2014 and 2013.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.
 
As of December 31, 2014:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current Assets
 
$
28,562

 
$
(15,127
)
 
$
13,435

 
$
350

 
$
13,785

Investments and Other Assets
 
24,810

 
(7,190
)
 
17,620

 

 
17,620

Total Assets
 
53,372

 
(22,317
)
 
31,055

 
350

 
31,405

 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
(86,062
)
 
33,829

 
(52,233
)
 
(7,443
)
 
(59,676
)
Deferred Credits and Other
 
(82,990
)
 
32,388

 
(50,602
)
 

 
(50,602
)
Total Liabilities
 
(169,052
)
 
66,217

 
(102,835
)
 
(7,443
)
 
(110,278
)
Total
 
$
(115,680
)
 
$
43,900

 
$
(71,780
)
 
$
(7,093
)
 
$
(78,873
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $43,900.
(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 $7,443, and cash margin provided to counterparties of $350.
 
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 one counterparty for which our exposure represents approximately 90% of Pinnacle West’s $31 million of risk management assets as of December 31, 2014.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2014 (dollars in millions):
 
 
December 31, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position
$
169

Cash Collateral Posted
44

Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)
80


(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.
Other Income and Other Expense
Other Income and Other Expense
 
The following table provides detail of other income and other expense for 2014, 2013 and 2012 (dollars in thousands):
 
 
2014
 
2013
 
2012
Other income:
 

 
 

 
 

Interest income
$
1,010

 
$
1,629

 
$
1,239

Debt return on the purchase of Four Corners units 4 & 5
8,386

 

 

Miscellaneous
212

 
75

 
367

Total other income
$
9,608

 
$
1,704

 
$
1,606

Other expense:
 

 
 

 
 

Non-operating costs
$
(9,657
)
 
$
(8,207
)
 
$
(7,777
)
Investment loss — net
(9,426
)
 
(3,711
)
 
(2,453
)
Miscellaneous
(2,663
)
 
(4,106
)
 
(9,612
)
Total other expense
$
(21,746
)
 
$
(16,024
)
 
$
(19,842
)
Other Income and Other Expense
 
The following table provides detail of APS’s other income and other expense for 2014, 2013 and 2012 (dollars in thousands):
 
 
2014
 
2013
 
2012
Other income:
 

 
 

 
 

Interest income
$
689

 
$
1,234

 
$
310

Debt return on the purchase of Four Corners units 4 & 5
8,386

 

 

Miscellaneous
2,220

 
2,662

 
2,558

Total other income
$
11,295

 
$
3,896

 
$
2,868

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(10,397
)
 
$
(9,626
)
 
$
(8,706
)
Asset dispositions
(615
)
 
(4,992
)
 
(1,511
)
Miscellaneous
(2,391
)
 
(5,831
)
 
(10,933
)
Total other expense
$
(13,403
)
 
$
(20,449
)
 
$
(21,150
)

(a)As defined by FERC, includes non-operating utility income and expense (items excluded from utility rate recovery).
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 in 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 asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
 
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 lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for 2014, 2013 and 2012 of $26 million, $34 million and $32 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 Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):
 
 
December 31, 2014
 
December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
121

 
$
125

Current maturities of long-term debt
13

 
26

Long-term debt excluding current maturities

 
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 lease.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur.  Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Palo Verde Unit 2 interests which, if appropriate, may be required to be written down in value.  If such an event had occurred as of December 31, 2014, APS would have been required to pay the noncontrolling equity participants approximately $123 million and assume $13 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Consolidated Balance Sheets.
 
For regulatory ratemaking purposes, the leases are treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
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 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 Consolidated Balance Sheets.  See Note 13 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 December 31, 2014 and December 31, 2013 (dollars in millions):
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2014
 

 
 

 
 

Equity securities
$
310

 
$
159

 
$

Fixed income securities
411

 
17

 
(1
)
Net payables (a)
(7
)
 

 

Total
$
714

 
$
176

 
$
(1
)
 
 
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 purchases and sales of securities.
 
The costs of securities sold are determined on the basis of specific identification.  The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Realized gains
$
5

 
$
6

 
$
7

Realized losses
(5
)
 
(7
)
 
(4
)
Proceeds from the sale of securities (a)
356

 
446

 
418


(a)
Proceeds are reinvested in the trust.
 
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2014 is as follows (dollars in millions):
 
 
Fair Value
Less than one year
$
14

1 year – 5 years
116

5 years – 10 years
122

Greater than 10 years
159

Total
$
411

Changes in Accumulated Other Comprehensive Loss
   Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands): 
 
Year Ended December 31, 2014
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(23,058
)
 
 
 
$
(54,995
)
 
 
 
$
(78,053
)
OCI (loss) before reclassifications
(810
)
 
 
 
(5,419
)
 
 
 
(6,229
)
Amounts reclassified from accumulated other comprehensive loss
13,483

 
(a)
 
2,658

 
(b)
 
16,141

Net current period OCI (loss)
12,673

 
 
 
(2,761
)
 
 
 
9,912

Ending balance
$
(10,385
)
 
 
 
$
(57,756
)
 
 
 
$
(68,141
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands): 
 
Year Ended December 31, 2013
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(49,592
)
 
 
 
$
(64,416
)
 
 
 
$
(114,008
)
OCI (loss) before reclassifications
(213
)
 
 
 
5,594

 
 
 
5,381

Amounts reclassified from accumulated other comprehensive loss
26,747

 
(a)
 
3,827

 
(b)
 
30,574

Net current period OCI
26,534

 
 
 
9,421

 
 
 
35,955

Ending balance
$
(23,058
)
 
 
 
$
(54,995
)
 
 
 
$
(78,053
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands): 
 
Year Ended December 31, 2014
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(23,059
)
 
 
 
$
(30,313
)
 
 
 
$
(53,372
)
OCI (loss) before reclassifications
(809
)
 
 
 
(10,415
)
 
 
 
(11,224
)
Amounts reclassified from accumulated other comprehensive loss
13,483

 
(a)
 
2,780

 
(b)
 
16,263

Net current period OCI (loss)
12,674

 
 
 
(7,635
)
 
 
 
5,039

Ending balance
$
(10,385
)
 
 
 
$
(37,948
)
 
 
 
$
(48,333
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands): 
 
Year Ended December 31, 2013
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(49,592
)
 
 
 
$
(39,503
)
 
 
 
$
(89,095
)
OCI (loss) before reclassifications
(214
)
 
 
 
5,387

 
 
 
5,173

Amounts reclassified from accumulated other comprehensive loss
26,747

 
(a)
 
3,803

 
(b)
 
30,550

Net current period OCI
26,533

 
 
 
9,190

 
 
 
35,723

Ending balance
$
(23,059
)
 
 
 
$
(30,313
)
 
 
 
$
(53,372
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
 
Year Ended December 31,
 
2014
 
2013
 
2012
Operating revenues
$
642

 
$
799

 
$
6,133

Operating expenses
23,507

 
24,930

 
12,125

Operating loss
(22,865
)
 
(24,131
)
 
(5,992
)
Other
 

 
 

 
 

Equity in earnings of subsidiaries
411,528

 
420,926

 
391,528

Other expense
(3,276
)
 
(1,999
)
 
(2,001
)
Total
408,252

 
418,927

 
389,527

Interest expense
3,663

 
3,226

 
4,868

Income from continuing operations
381,724

 
391,570

 
378,667

Income tax benefit
(15,871
)
 
(14,504
)
 
(7,079
)
Income from continuing operations — net of income taxes
397,595

 
406,074

 
385,746

Loss from discontinued operations — net of income taxes

 

 
(4,204
)
Net income attributable to common shareholders
397,595

 
406,074

 
381,542

Other comprehensive income — attributable to common shareholders
9,912

 
35,955

 
38,155

Total comprehensive income — attributable to common shareholders
$
407,507

 
$
442,029

 
$
419,697

 
December 31,
 
2014
 
2013
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
3,088

 
$
5,798

Accounts receivable
99,958

 
80,108

Current deferred income taxes
66,979

 
93,185

Income tax receivable
7,329

 
1,853

Other current assets
124

 
242

Total current assets
177,478

 
181,186

Investments and other assets
 

 
 

Investments in subsidiaries
4,630,570

 
4,455,049

Other assets
43,051

 
13,789

Total investments and other assets
4,673,621

 
4,468,838

Total Assets
$
4,851,099

 
$
4,650,024

LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
$
5,250

 
$
3,279

Accrued taxes
12,220

 
8,538

Common dividends payable
65,790

 
62,528

Other current liabilities
38,992

 
31,295

Total current liabilities
122,252

 
105,640

Long-term debt less current maturities
125,000

 
125,000

Deferred credits and other
 

 
 

Deferred income taxes
12,055

 
4,158

Pension and other postretirement liabilities
29,228

 
37,611

Other
43,462

 
37,155

Total deferred credits and other
84,745

 
78,924

Common stock equity
 
 
 

Common stock
2,509,569

 
2,487,250

Accumulated other comprehensive loss
(68,141
)
 
(78,053
)
Retained earnings
1,926,065

 
1,785,273

Total Pinnacle West Shareholders’ equity
4,367,493

 
4,194,470

Noncontrolling interests
151,609

 
145,990

Total Equity
4,519,102

 
4,340,460

Total Liabilities and Equity
$
4,851,099

 
$
4,650,024

 
Year Ended December 31,
 
2014
 
2013
 
2012
Cash flows from operating activities
 

 
 

 
 

Net income
$
397,595

 
$
406,074

 
$
381,542

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 

 
 

Equity in earnings of subsidiaries — net
(411,528
)
 
(420,926
)
 
(391,528
)
Depreciation and amortization
94

 
95

 
94

Deferred income taxes
4,406

 
(28,806
)
 
(15,135
)
Accounts receivable
(22,945
)
 
21,671

 
28,763

Accounts payable
2,017

 
(2,449
)
 
879

Accrued taxes and income tax receivables — net
(1,795
)
 
1,402

 
(3,103
)
Dividends received from subsidiaries
253,600

 
242,100

 
222,200

Other
18,432

 
(15,065
)
 
(4,589
)
Net cash flow provided by operating activities
239,876

 
204,096

 
219,123

Cash flows from investing activities
 

 
 

 
 

Investments in subsidiaries
(10,236
)
 
(3,400
)
 

Repayments of loans from subsidiaries
322

 
2,149

 
996

Advances of loans to subsidiaries
(1,450
)
 
(2,099
)
 
(1,200
)
Net cash flow used for investing activities
(11,364
)
 
(3,350
)
 
(204
)
Cash flows from financing activities
 

 
 

 
 

Issuance of long-term debt
125,000

 

 
125,000

Dividends paid on common stock
(246,671
)
 
(235,244
)
 
(225,075
)
Repayment of long-term debt
(125,000
)
 

 
(125,000
)
Common stock equity issuance
15,288

 
17,319

 
15,955

Other
161

 
298

 
170

Net cash flow used for financing activities
(231,222
)
 
(217,627
)
 
(208,950
)
Net increase (decrease) in cash and cash equivalents
(2,710
)
 
(16,881
)
 
9,969

Cash and cash equivalents at beginning of year
5,798

 
22,679

 
12,710

Cash and cash equivalents at end of year
$
3,088

 
$
5,798

 
$
22,679

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES
Column A
Column B
 
Column C
 
Column D
 
Column E
 
 
 
Additions
 
 
 
 
Description
Balance at
beginning
of period
 
Charged to
cost and
expenses
 
Charged
to other
accounts
 
Deductions
 
Balance
at end of
period
Reserve for uncollectibles:
 

 
 

 
 

 
 

 
 

2014
$
3,203

 
$
3,942

 
$

 
$
4,051

 
$
3,094

2013
3,340

 
4,923

 

 
5,060

 
3,203

2012
3,748

 
5,290

 

 
5,698

 
3,340

Column A
 
Column B
 
Column C
 
Column D
 
Column E
 
 
 
 
Additions
 
 
 
 
Description
 
Balance at
beginning
of period
 
Charged to
cost and
expenses
 
Charged
to other
accounts
 
Deductions
 
Balance
at end of
period
Reserve for uncollectibles:
 
 

 
 

 
 

 
 

 
 

2014
 
$
3,203

 
$
3,942

 
$

 
$
4,051

 
$
3,094

2013
 
3,340

 
4,923

 

 
5,060

 
3,203

2012
 
3,748

 
5,290

 

 
5,698

 
3,340

Summary of Significant Accounting Policies (Policies)
Description of Business and Basis of Presentation
 
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE, and formerly SunCor. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.  El Dorado is an investment firm. BCE is a new subsidiary formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. SunCor was a developer of residential, commercial and industrial real estate projects and essentially all of these assets were sold in 2009 and 2010.  In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  All activities for SunCor are reported as discontinued operations. 
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE, and formerly SunCor. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).
 
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.
Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with GAAP.  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
Regulatory Accounting
 
APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates.  Regulatory liabilities generally represent expected future costs that have already been collected from customers.
 
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
Electric Revenues
 
We derive electric revenues primarily from sales of electricity to our regulated Native Load customers.  Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers.  The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month.  Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed.  Differences historically between the actual and estimated unbilled revenues are immaterial.  We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
 
Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income.  In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy.  This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow.  We net these book-outs, which reduces both revenues and fuel and purchased power costs.
 
For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 3).  Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.
 
Some of our cost recovery mechanisms are alternative revenue programs.  For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.
Allowance for Doubtful Accounts
 
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible.  The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues.  The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.
Property, Plant and Equipment
 
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities.  We report utility plant at its original cost, which includes:
 
material and labor;
contractor costs;
capitalized leases;
construction overhead costs (where applicable); and
allowance for funds used during construction.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 11.
 
APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations.  APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.
 
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2014 were as follows:
 
Fossil plant — 19 years;
Nuclear plant — 28 years;
Other generation — 25 years;
Transmission — 38 years;
Distribution — 33 years; and
Other — 7 years.

Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  See Note 3 for further discussion.  These costs were deferred and will be amortized on the depreciation line of the Consolidated Statements of Income.
Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
 
AFUDC was calculated by using a composite rate of 8.47% for 2014, 8.56% for 2013, and 8.60% for 2012.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Materials and Supplies
 
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
Fair Value Measurements
 
We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis.  Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).
 
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
 
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
 
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial 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.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  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 expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
Retirement Plans and Other Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries.  We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through August 2014, at which point the DOE suspended the fee.  In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2016.
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).
Cash and Cash Equivalents
 
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
Intangible Assets
 
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets.  The intangible assets are amortized over their finite useful lives.
Investments
 
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities.
Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.
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 4 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.
Summary of Significant Accounting Policies (Tables)
Summary of supplemental cash flow information
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
 
 
Year ended December 31,
 
2014
 
2013
 
2012
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
(102,154
)
 
$
18,537

 
$
2,543

Interest, net of amounts capitalized
177,074

 
184,010

 
200,923

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
44,712

 
$
33,184

 
$
26,208

Dividends declared but not paid
65,790

 
62,528

 
59,789

Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)

 
145,609

 

Regulatory Matters (Tables)
The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions):
 
 
Year Ended December 31,
 
2014
 
2013
Beginning balance
$
21

 
$
73

Deferred fuel and purchased power costs - current period
27

 
(21
)
Amounts charged to customers
(41
)
 
(31
)
Ending balance
$
7

 
$
21

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

 
$
485

 
$

 
$
314

Income taxes — AFUDC equity
2044
 
5

 
118

 
4

 
105

Deferred fuel and purchased power — mark-to-market (Note 16)
2017
 
51

 
46

 
5

 
29

Transmission vegetation management
2016
 
9

 
5

 
9

 
14

Coal reclamation
2026
 

 
7

 
8

 
18

Palo Verde VIEs (Note 18)
2046
 

 
35

 

 
41

Deferred compensation
2036
 

 
34

 

 
34

Deferred fuel and purchased power (b) (c)
2015
 
7

 

 
21

 

Tax expense of Medicare subsidy
2024
 
2

 
14

 
2

 
15

Loss on reacquired debt
2034
 
1

 
16

 
1

 
17

Income taxes — investment tax credit basis adjustment
2044
 
2

 
46

 
1

 
39

Pension and other postretirement benefits deferral
2015
 
4

 

 
8

 
4

Four Corners cost deferral
2024
 
7

 
70

 

 
37

Lost fixed cost recovery
2015
 
38

 

 
25

 

Transmission cost adjustor
2014
 

 

 
8

 
2

Retired power plant costs
2033
 
10

 
136

 
3

 
18

Deferred property taxes
(d)
 

 
30

 

 
11

Other
Various
 
2

 
12

 
2

 
14

Total regulatory assets (e)
 
 
$
138

 
$
1,054

 
$
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 OCI and result in lower future revenues.  See Note 7 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
 
December 31, 2014
 
December 31, 2013
 
Period
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
31

 
$
273

 
$
28

 
$
303

Asset retirement obligations
2044
 

 
296

 

 
266

Renewable energy standard (b)
2017
 
25

 
23

 
33

 
15

Income taxes — change in rates
2043
 

 
72

 

 
74

Spent nuclear fuel
2047
 
5

 
66

 
6

 
36

Deferred gains on utility property
2019
 
2

 
8

 
2

 
10

Income taxes — deferred investment tax credit
2043
 
4

 
93

 
3

 
79

Demand side management (b)
2015
 
31

 

 
27

 

Other postretirement benefits
(c)
 
32

 
199

 

 

Other
Various
 
1

 
21

 

 
18

Total regulatory liabilities
 
 
$
131

 
$
1,051

 
$
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 (see Note 11).
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
See Note 7.
Income Taxes (Tables)
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
 
2014
 
2013
 
2012
Total unrecognized tax benefits, January 1
$
41,997

 
$
133,422

 
$
136,005

Additions for tax positions of the current year
4,309

 
3,516

 
5,167

Additions for tax positions of prior years
751

 
13,158

 

Reductions for tax positions of prior years for:
 

 
 

 
 

Changes in judgment
(2,282
)
 
(108,099
)
 
(7,729
)
Settlements with taxing authorities

 

 

Lapses of applicable statute of limitations

 

 
(21
)
Total unrecognized tax benefits, December 31
$
44,775

 
$
41,997

 
$
133,422

The components of income tax expense are as follows (dollars in thousands):
 
Year Ended December 31,
 
2014
 
2013
 
2012
Current:
 

 
 

 
 

Federal
$
25,054

 
$
(81,784
)
 
$
(3,493
)
State
10,382

 
10,537

 
8,395

Total current
35,436

 
(71,247
)
 
4,902

Deferred:
 

 
 

 
 

Federal
167,365

 
279,973

 
200,322

State
17,904

 
21,865

 
28,280

Total deferred
185,269

 
301,838

 
228,602

Total income tax expense
220,705

 
230,591

 
233,504

Less: income tax benefit on discontinued operations

 

 
(3,813
)
Income tax expense — continuing operations
$
220,705

 
$
230,591

 
$
237,317

 
The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Federal income tax expense at 35% statutory rate
$
225,540

 
$
234,695

 
$
229,709

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

State income tax net of federal income tax benefit
18,149

 
21,387

 
23,819

Credits and favorable adjustments related to prior years resolved in current year

 
(3,356
)
 

Medicare Subsidy Part-D
830

 
823

 
483

Allowance for equity funds used during construction (see Note 1)
(8,523
)
 
(6,997
)
 
(6,158
)
Palo Verde VIE noncontrolling interest (see Note 18)
(9,135
)
 
(11,862
)
 
(11,065
)
Investment tax credit amortization
(4,928
)
 
(3,548
)
 
(2,030
)
Other
(1,228
)
 
(551
)
 
2,559

Income tax expense — continuing operations
$
220,705

 
$
230,591

 
$
237,317

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
 
December 31,
 
2014
 
2013
Current asset
$
122,232

 
$
91,152

Long-term liability
(2,582,636
)
 
(2,351,882
)
Deferred income taxes — net
$
(2,460,404
)
 
$
(2,260,730
)
The components of the net deferred income tax liability were as follows (dollars in thousands):
 
 
December 31,
 
2014
 
2013
DEFERRED TAX ASSETS
 

 
 

Risk management activities
$
57,505

 
$
44,920

Regulatory liabilities:
 

 
 

Asset retirement obligation and removal costs
229,772

 
235,959

Unamortized investment tax credits
96,232

 
82,116

Other postretirement benefits
90,496

 

Other
60,409

 
42,609

Pension liabilities
205,227

 
140,773

Other postretirement liabilities

 
57,869

Renewable energy incentives
65,169

 
65,434

Credit and loss carryforwards
68,347

 
133,070

Other
138,729

 
148,492

Total deferred tax assets
1,011,886

 
951,242

DEFERRED TAX LIABILITIES
 

 
 

Plant-related
(2,958,369
)
 
(2,903,730
)
Risk management activities
(12,171
)
 
(16,191
)
Other postretirement assets
(59,170
)
 

Regulatory assets:
 

 
 

Allowance for equity funds used during construction
(48,286
)
 
(43,058
)
Deferred fuel and purchased power
(2,498
)
 
(8,282
)
Deferred fuel and purchased power — mark-to-market
(38,187
)
 
(13,343
)
Pension and other postretirement benefits
(191,747
)
 
(129,250
)
Retired power plant costs (see Note 3)
(57,255
)
 
(8,199
)
Other
(99,123
)
 
(85,003
)
Other
(5,484
)
 
(4,916
)
Total deferred tax liabilities
(3,472,290
)
 
(3,211,972
)
Deferred income taxes — net
$
(2,460,404
)
 
$
(2,260,730
)
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
 
 
2014
 
2013
 
2012
Total unrecognized tax benefits, January 1
$
41,997

 
$
133,241

 
$
135,824

Additions for tax positions of the current year
4,309

 
3,516

 
5,167

Additions for tax positions of prior years
751

 
13,158

 

Reductions for tax positions of prior years for:
 

 
 

 
 

Changes in judgment
(2,282
)
 
(107,918
)
 
(7,729
)
Settlements with taxing authorities

 

 

Lapses of applicable statute of limitations

 

 
(21
)
Total unrecognized tax benefits, December 31
$
44,775

 
$
41,997

 
$
133,241

The components of APS’s income tax expense are as follows (dollars in thousands): 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Current:
 

 
 

 
 

Federal
$
40,115

 
$
(97,531
)
 
$
(11,650
)
State
15,598

 
11,983

 
12,308

Total current
55,713

 
(85,548
)
 
658

Deferred:
 

 
 

 
 

Federal
165,027

 
305,389

 
216,367

State
16,620

 
25,254

 
27,371

Total deferred
181,647

 
330,643

 
243,738

Total income tax expense
$
237,360

 
$
245,095

 
$
244,396

The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Federal income tax expense at 35% statutory rate
$
239,638

 
$
246,384

 
$
235,027

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

State income tax net of federal income tax benefit
21,148

 
23,970

 
25,379

Credits and favorable adjustments related to prior years resolved in current year

 
(3,231
)
 

Medicare Subsidy Part-D
830

 
823

 
483

Allowance for equity funds used during construction (see Note 1)
(8,523
)
 
(6,997
)
 
(6,158
)
Palo Verde VIE noncontrolling interest (see Note 18)
(9,135
)
 
(11,862
)
 
(11,065
)
Investment tax credit amortization
(4,928
)
 
(3,548
)
 
(2,030
)
Other
(1,670
)
 
(444
)
 
2,760

Income tax expense
$
237,360

 
$
245,095

 
$
244,396

The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands): 
 
December 31,
 
2014
 
2013
Current asset (liability)
$
55,253

 
$
(2,033
)
Long-term liability
(2,571,365
)
 
(2,347,724
)
Deferred income taxes — net
$
(2,516,112
)
 
$
(2,349,757
)
The components of the net deferred income tax liability were as follows (dollars in thousands):
 
 
December 31,
 
2014
 
2013
DEFERRED TAX ASSETS
 

 
 

Regulatory liabilities:
 

 
 

Asset retirement obligation and removal costs
$
229,772

 
$
235,959

Unamortized investment tax credits
96,232

 
82,116

Other postretirement benefits
90,496

 

Other
60,409

 
42,609

Risk management activities
57,505

 
44,920

Pension liabilities
194,541

 
132,263

Other postretirement liabilities

 
53,950

Renewable energy incentives
65,169

 
65,434

Credit and loss carryforwards

 
38,183

Other
161,379

 
166,781

Total deferred tax assets
955,503

 
862,215

DEFERRED TAX LIABILITIES
 

 
 

Plant-related
(2,958,369
)
 
(2,903,730
)
Risk management activities
(12,171
)
 
(16,191
)
Other postretirement benefit assets
(58,495
)
 

Regulatory assets:
 

 
 

Allowance for equity funds used during construction
(48,286
)
 
(43,058
)
Deferred fuel and purchased power
(2,498
)
 
(8,282
)
Deferred fuel and purchased power — mark-to-market
(38,187
)
 
(13,343
)
Pension and other postretirement benefits
(191,747
)
 
(129,250
)
Retired power plant costs (see Note 3)
(57,255
)
 
(8,199
)
Other
(99,123
)
 
(85,003
)
Other
(5,484
)
 
(4,916
)
Total deferred tax liabilities
(3,471,615
)
 
(3,211,972
)
Deferred income taxes — net
$
(2,516,112
)
 
$
(2,349,757
)
Lines of Credit and Short-Term Borrowings (Tables)
Schedule of consolidated credit facilities and amounts available and outstanding
The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2014 (dollars in millions):
 
Credit Facility
 
Expiration
 
Amount
Committed
 
Unused
Amount (a)
 
Commitment
Fees
Pinnacle West Revolving Credit Facility
 
May 2019
 
$
200

 
$
200

 
0.175
%
APS Revolving Credit Facility
 
May 2019
 
500

 
500

 
0.125
%
APS Revolving Credit Facility
 
April 2018
 
500

 
353

 
0.125
%
Total
 
 
 
$
1,200

 
$
1,053

 
 



(a)
At December 31, 2014, APS had $147 million of outstanding commercial paper.  Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $853 million.
The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2013 (dollars in millions):
 
Credit Facility
 
Expiration
 
Amount
Committed
 
Unused
Amount (a)
 
Commitment
Fees
Pinnacle West Revolving Credit Facility
 
November 2016
 
$
200

 
$
200

 
0.175
%
APS Revolving Credit Facility
 
November 2016
 
500

 
347

 
0.125
%
APS Revolving Credit Facility
 
April 2018
 
500

 
500

 
0.125
%
Total
 
 
 
$
1,200

 
$
1,047

 
 



(a)
At December 31, 2013, APS had $153 million of outstanding commercial paper.  Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $847 million.
Long-Term Debt and Liquidity Matters (Tables)
The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2014 and 2013 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2014
 
2013
APS
 
 
 
 
 

 
 

Pollution Control Bonds:
 
 
 
 
 

 
 

Variable
2029-2038
 
(b)
 
$
156,405

 
$
75,580

Fixed
2024-2034
 
0.45%-5.75%
 
249,300

 
426,125

Total Pollution Control Bonds
 
 
 
 
405,705

 
501,705

Senior unsecured notes
2015-2044
 
3.35%-8.75%
 
2,875,000

 
2,675,000

Palo Verde sale leaseback lessor notes
2015
 
8.00%
 
13,420

 
38,869

Unamortized discount
 
 
 
 
(9,206
)
 
(8,732
)
Unamortized premium
 
 
 
 
4,866

 
5,047

Total APS long-term debt
 
 
 
 
3,289,785

 
3,211,889

Less current maturities
(d)
 
 
 
383,570

 
540,424

Total APS long-term debt less current maturities
 
 
 
 
2,906,215

 
2,671,465

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(c)
 
125,000

 
125,000

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
3,031,215

 
$
2,796,465


(a)                                 This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)                                 The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.27% at December 31, 2014 and 0.03%-0.06% at December 31, 2013.
(c)                                  The weighted-average interest rate was 1.019% at December 31, 2014 and 1.269% at December 31, 2013.
(d)                                 Current maturities include $70 million of pollution control bonds expected to be remarketed in 2015 and $300 million in senior unsecured notes that mature in 2015.
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in millions):
Year
 
Consolidated
Pinnacle West
 
Consolidated
APS
2015
 
$
384

 
$
384

2016
 
357

 
357

2017
 
157

 
32

2018
 
32

 
32

2019
 
500

 
500

Thereafter
 
1,989

 
1,989

Total
 
$
3,419

 
$
3,294

The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):
 
 
As of
December 31, 2014
 
As of
December 31, 2013
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125

 
$
125

 
$
125

 
$
125

APS
3,290

 
3,714

 
3,212

 
3,454

Total
$
3,415

 
$
3,839

 
$
3,337

 
$
3,579

Retirement Plans and Other Benefits (Tables)
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):
 
Pension
 
Other Benefits
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Service cost-benefits earned during the period
$
53,080

 
$
64,195

 
$
63,502

 
$
18,139

 
$
23,597

 
$
27,163

Interest cost on benefit obligation
129,194

 
112,392

 
119,586

 
41,243

 
41,536

 
46,467

Expected return on plan assets
(158,998
)
 
(146,333
)
 
(140,979
)
 
(46,400
)
 
(45,717
)
 
(45,793
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Transition obligation

 

 

 

 

 
452

Prior service cost (credit)
869

 
1,097

 
1,143

 
(9,626
)
 
(179
)
 
(179
)
Net actuarial loss
10,963

 
39,852

 
44,250

 
1,175

 
11,310

 
20,233

Net periodic benefit cost
$
35,108

 
$
71,203

 
$
87,502

 
$
4,531

 
$
30,547

 
$
48,343

Portion of cost charged to expense
$
21,985

 
$
38,968

 
$
36,333

 
$
6,000

 
$
18,469

 
$
19,321

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2014 and 2013 (dollars in thousands):
 
Pension
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
2,646,530

 
$
2,850,846

 
$
890,418

 
$
990,418

Service cost
53,080

 
64,195

 
18,139

 
23,597

Interest cost
129,194

 
112,392

 
41,243

 
41,536

Benefit payments
(128,550
)
 
(125,269
)
 
(29,054
)
 
(26,675
)
Actuarial (gain) loss
378,394

 
(255,634
)
 
150,188

 
(138,458
)
Plan amendments

 

 
(388,599
)
 

Benefit obligation at December 31
3,078,648

 
2,646,530

 
682,335

 
890,418

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,264,121

 
2,079,181

 
748,339

 
684,221

Actual return on plan assets
292,992

 
150,546

 
105,223

 
76,995

Employer contributions
175,000

 
140,500

 
770

 
14,438

Benefit payments
(116,709
)
 
(106,106
)
 
(19,707
)
 
(27,315
)
Fair value of plan assets at December 31
2,615,404

 
2,264,121

 
834,625

 
748,339

Funded Status at December 31
$
(463,244
)
 
$
(382,409
)
 
$
152,290

 
$
(142,079
)
The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2014 and 2013 (dollars in thousands):
 
2014
 
2013
Projected benefit obligation
$
3,078,648

 
$
2,646,530

Accumulated benefit obligation
2,873,741

 
2,469,889

Fair value of plan assets
2,615,404

 
2,264,121

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2014 and 2013 (dollars in thousands):
 
Pension
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
Noncurrent asset
$

 
$

 
$
152,290

 
$

Current liability
(9,508
)
 
(10,860
)
 

 

Noncurrent liability
(453,736
)
 
(371,549
)
 

 
(142,079
)
Net amount recognized
$
(463,244
)
 
$
(382,409
)
 
$
152,290

 
$
(142,079
)
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2014 and 2013 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
Net actuarial loss
$
577,976

 
$
344,540

 
$
148,006

 
$
57,816

Prior service cost (credit)
1,203

 
2,072

 
(379,269
)
 
(296
)
APS’s portion recorded as a regulatory (asset) liability
(485,037
)
 
(265,107
)
 
230,916

 
(49,298
)
Income tax expense (benefit)
(36,890
)
 
(32,204
)
 
851

 
(2,528
)
Accumulated other comprehensive loss
$
57,252

 
$
49,301

 
$
504

 
$
5,694

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2015 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
28,180

 
$
5,651

Prior service cost (credit)
595

 
(37,968
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2014
$
28,775

 
$
(32,317
)
The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
 
Benefit Obligations
As of December 31,
 
Benefit Costs
For the Years Ended December 31,
 
2014
 
2013
 
2014
 
2013
 
2012
 
 
 
 
 
January - September
October - December
 
 
 
 
Discount rate – pension
4.02
%
 
4.88
%
 
4.88
%
4.88
%
 
4.01
%
 
4.42
%
Discount rate – other benefits
4.14
%
 
5.10
%
 
5.10
%
4.41
%
 
4.20
%
 
4.59
%
Rate of compensation increase
4.00
%
 
4.00
%
 
4.00
%
4.00
%
 
4.00
%
 
4.00
%
Expected long-term return on plan assets - pension
N/A

 
N/A

 
6.90
%
6.90
%
 
7.00
%
 
7.75
%
Expected long-term return on plan assets - other benefits
N/A

 
N/A

 
6.80
%
4.25
%
 
7.00
%
 
7.75
%
Initial healthcare cost trend rate (pre-65 participants)
7.00
%
 
7.50
%
 
7.50
%
7.50
%
 
7.50
%
 
7.50
%
Initial healthcare cost trend rate (post-65 participants)
5.00
%
 
7.50
%
 
7.50
%
5.00
%
 
7.50
%
 
7.50
%
Ultimate healthcare cost trend rate
5.00
%
 
5.00
%
 
5.00
%
5.00
%
 
5.00
%
 
5.00
%
Number of years to ultimate trend rate (pre-65 participants)
4

 
4

 
4

4

 
4

 
4

Number of years to ultimate trend rate (post-65 participants)
0

 
4

 
4

0

 
4

 
4

A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in millions): 
 
1% Increase
 
1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
$
10

 
$
(4
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
12

 
(9
)
Effect on the accumulated other postretirement benefit obligation
110

 
(88
)
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2014, by asset category, are as follows (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other (b)
 
Balance at December 31, 2014
Pension Plan:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
387

 
$

 
$

 
$

 
$
387

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate

 
1,162,096

 

 

 
1,162,096

U.S. Treasury
291,817

 

 

 

 
291,817

Other (a)

 
113,265

 

 

 
113,265

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
246,387

 

 

 

 
246,387

International Companies
18,069

 

 

 

 
18,069

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
127,336

 

 

 
127,336

International Equities

 
317,167

 

 

 
317,167

Real estate

 
129,715

 

 

 
129,715

Partnerships

 
138,337

 
27,929

 

 
166,266

Short-term investments and other

 
26,016

 

 
16,883

 
42,899

Total Pension Plan
$
556,660

 
$
2,013,932

 
$
27,929

 
$
16,883

 
$
2,615,404

Other Benefits:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
318

 
$

 
$

 
$

 
$
318

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate

 
187,961

 

 

 
187,961

U.S. Treasury
130,967

 

 

 

 
130,967

Other (a)

 
35,291

 

 

 
35,291

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
265,106

 

 

 

 
265,106

International Companies
17,813

 

 

 

 
17,813

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
88,258

 

 

 
88,258

International Equities

 
85,746

 

 

 
85,746

Real Estate

 
11,657

 

 

 
11,657

Short-term investments and other

 
7,408

 

 
4,100

 
11,508

Total Other Benefits
$
414,204

 
$
416,321

 
$

 
$
4,100

 
$
834,625


(a)
This category consists primarily of debt securities issued by municipalities.
(b)
Represents plan receivables and payables.
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2013, by asset category, are as follows (dollars in thousands):
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other (b)
 
Balance at December 31, 2013
Pension Plan:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
504

 
$

 
$

 
$

 
$
504

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate

 
898,621

 

 

 
898,621

U.S. Treasury
231,590

 

 

 

 
231,590

Other (a)

 
84,011

 

 

 
84,011

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
239,036

 

 

 

 
239,036

International Companies
19,429

 

 

 

 
19,429

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
116,150

 

 

 
116,150

International Equities

 
367,551

 

 

 
367,551

Fixed Income

 
137,520

 

 

 
137,520

Real estate

 
119,739

 

 

 
119,739

Partnerships

 

 
8,660

 

 
8,660

Short-term investments and other

 
41,060

 

 
250

 
41,310

Total Pension Plan
$
490,559

 
$
1,764,652

 
$
8,660

 
$
250

 
$
2,264,121

Other Benefits:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
 

 
 

 
 

 
 

 
 

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

Corporate
$

 
$
153,888

 
$

 
$

 
$
153,888

U.S. Treasury
98,704

 

 

 

 
98,704

Other (a)

 
27,936

 

 

 
27,936

Equities:
 

 
 

 
 

 
 

 
 

U.S. Companies
252,181

 

 

 

 
252,181

International Companies
20,892

 

 

 

 
20,892

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. Equities

 
80,751

 

 

 
80,751

International Equities

 
92,382

 

 

 
92,382

Real Estate

 
10,761

 

 

 
10,761

Short-term investments and other

 
8,414

 

 
2,430

 
10,844

Total Other Benefits
$
371,777

 
$
374,132

 
$

 
$
2,430

 
$
748,339


(a)
This category consists primarily of debt securities issued by municipalities.
(b)
Represents plan receivables and payables.
The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2014 and 2013 (dollars in thousands):
 
 
Pension
Partnerships
 
2014
 
2013
Beginning balance at January 1
 
$
8,660

 
$
2,419

Actual return on assets still held at December 31
 
927

 
(498
)
Purchases
 
19,984

 
7,377

Sales
 
(1,642
)
 
(638
)
Transfers in and/or out of Level 3
 

 

Ending balance at December 31
 
$
27,929

 
$
8,660

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):
Year
 
Pension
 
Other Benefits
2015
 
$
139,013

 
$
25,134

2016
 
155,968

 
27,311

2017
 
160,080

 
29,253

2018
 
167,600

 
31,258

2019
 
177,470

 
33,190

Years 2020-2024
 
983,557

 
184,772

Leases (Tables)
Estimated future minimum lease payments for Pinnacle West's and APS's operating leases, excluding purchased power agreements
Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions):
Year
 
Pinnacle West
Consolidated
 
APS
2015
 
$
18

 
$
15

2016
 
6

 
6

2017
 
5

 
5

2018
 
4

 
4

2019
 
3

 
3

Thereafter
 
63

 
62

Total future lease commitments
 
$
99

 
$
95

Jointly-Owned Facilities (Tables)
APS's interests in jointly-owned facilities recorded on the Consolidated Balance Sheets
The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2014 (dollars in thousands):

 
 
Percent
Owned
 
 
 
Plant in
Service
 
Accumulated
Depreciation
 
Construction
Work in
Progress
Generating facilities:
 
 

 
 
 
 

 
 

 
 

Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,734,918

 
$
1,051,670

 
$
16,955

Palo Verde Unit 2 (a)
 
16.8
%
 

 
556,472

 
349,960

 
13,710

Palo Verde Common
 
28.0
%
 
(b)
 
612,190

 
224,208

 
68,896

Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
229,795

 

Four Corners Generating Station
 
63.0
%
 

 
811,648

 
578,772

 
33,150

Navajo Generating Station Units 1, 2 and 3
 
14.0
%
 

 
272,208

 
159,198

 
2,716

Cholla common facilities (c)
 
63.3
%
 
(b)
 
155,856

 
49,954

 
866

Transmission facilities:
 
 

 
 
 
 

 
 

 
 

ANPP 500kV System
 
33.6
%
 
 (b)
 
106,369

 
35,035

 
3,731

Navajo Southern System
 
22.5
%
 
(b)
 
59,994

 
18,119

 
1,113

Palo Verde — Yuma 500kV System
 
18.2
%
 
(b)
 
12,925

 
4,943

 
12

Four Corners Switchyards
 
47.5
%
 
 (b)
 
33,034

 
10,035

 
386

Phoenix — Mead System
 
17.1
%
 
(b)
 
39,777

 
12,843

 
105

Palo Verde — Estrella 500kV System
 
50.0
%
 
(b)
 
89,572

 
16,491

 
736

Morgan — Pinnacle Peak System
 
64.4
%
 
 (b)
 
130,840

 
8,970

 
1,690

Round Valley System
 
50.0
%
 
(b)
 
497

 
276

 
1

Palo Verde — Morgan System
 
90.0
%
 
(b)
 

 

 
69,377

Hassayampa - North Gila System
 
80.0
%
 
(b)
 
8,902

 
3,634

 
142,645


(a)
See Note 18.
(b)
Weighted-average of interests.
(c)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp.  The common facilities at Cholla are jointly-owned.
 
Commitments and Contingencies (Tables)
The following table summarizes our estimated coal take-or-pay commitments (dollars in millions):
 
 
 Years Ended December 31,
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
Coal take-or-pay commitments (a)
$
151

 
$
171

 
$
195

 
$
190

 
$
194

 
$
2,469

 
(a)
Total take-or-pay commitments are approximately $3.4 billion.  The total net present value of these commitments is approximately $2.2 billion.
The following table summarizes actual payments under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in millions):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Total payments
$
237

 
$
188

 
$
196

Asset Retirement Obligations (Tables)
Change in asset retirement obligations
The following schedule shows the change in our asset retirement obligations for 2014 and 2013 (dollars in millions):

 
2014
 
2013
Asset retirement obligations at the beginning of year
$
347

 
$
357

Changes attributable to:
 

 
 

Accretion expense
24

 
24

Settlements
(30
)
 
(12
)
Assumed SCE’s obligation

 
34

Estimated cash flow revisions
44

 
(56
)
Newly incurred obligation
6

 

Asset retirement obligations at the end of year
$
391

 
$
347

Selected Quarterly Financial Data (Unaudited) (Tables)
Consolidated quarterly financial information for 2014 and 2013 is provided in the tables below (dollars in thousands, except per share amounts).  Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

 
2014 Quarter Ended
 
2014
 
March 31,
 
June 30,
 
Sept. 30,
 
Dec. 31,
 
Total
Operating revenues
$
686,251

 
$
906,264

 
$
1,172,667

 
$
726,450

 
$
3,491,632

Operations and maintenance
212,882

 
211,222

 
223,418

 
260,503

 
908,025

Operating income
75,170

 
254,113

 
421,775

 
60,184

 
811,242

Income taxes
6,405

 
74,540

 
134,753

 
5,007

 
220,705

Income from continuing operations
24,691

 
141,384

 
248,086

 
9,535

 
423,696

Net income attributable to common shareholders
15,766

 
132,458

 
243,961

 
5,410

 
397,595

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.14

 
$
1.20

 
$
2.20

 
$
0.05

 
$
3.59

Net income attributable to common shareholders — Diluted
0.14

 
1.19

 
2.20

 
0.05

 
3.58

 
 
2013 Quarter Ended
 
2013
 
March 31,
 
June 30,
 
Sept. 30,
 
Dec. 31,
 
Total
Operating revenues
$
686,652

 
$
915,822

 
$
1,152,392

 
$
699,762

 
$
3,454,628

Operations and maintenance
223,250

 
229,300

 
233,323

 
238,854

 
924,727

Operating income
86,923

 
259,812

 
415,688

 
83,900

 
846,323

Income taxes
12,469

 
77,043

 
131,912

 
9,167

 
230,591

Income from continuing operations
32,836

 
139,598

 
234,718

 
32,814

 
439,966

Net income attributable to common shareholders
24,444

 
131,207

 
226,163

 
24,260

 
406,074

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.22

 
$
1.19

 
$
2.06

 
$
0.22

 
$
3.69

Net income attributable to common shareholders — Diluted
0.22

 
1.18

 
2.04

 
0.22

 
3.66

Quarterly financial information for 2014 and 2013 is as follows (dollars in thousands):
 
 
2014 Quarter Ended,
 
2014
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
685,545

 
$
905,578

 
$
1,172,190

 
$
725,633

 
$
3,488,946

Operations and maintenance
208,285

 
208,059

 
212,430

 
253,668

 
882,442

Operating income
69,635

 
180,394

 
287,928

 
54,835

 
592,792

Net income attributable to common shareholder
19,518

 
134,916

 
251,047

 
15,738

 
421,219

 
 
2013 Quarter Ended,
 
2013
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
685,827

 
$
915,065

 
$
1,151,535

 
$
698,824

 
$
3,451,251

Operations and maintenance
220,752

 
224,950

 
222,617

 
229,505

 
897,824

Operating income
74,862

 
183,728

 
284,251

 
79,024

 
621,865

Net income attributable to common shareholder
26,042

 
133,949

 
234,954

 
30,024

 
424,969

Fair Value Measurements (Tables)
The following table presents the fair value at December 31, 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 December 31, 2014
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity Contracts
$

 
$
21

 
$
33

 
$
(23
)
 
(b)
 
$
31

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds

 
310

 

 

 
 
 
310

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
119

 

 

 

 
 
 
119

Cash and cash equivalent funds

 
11

 

 
(7
)
 
(c)
 
4

Corporate debt

 
109

 

 

 
 
 
109

Mortgage-backed securities

 
89

 

 

 
 
 
89

Municipality bonds

 
69

 

 

 
 
 
69

Other

 
14

 

 

 
 
 
14

Subtotal nuclear decommissioning trust
119

 
602

 

 
(7
)
 

 
714

Total
$
119

 
$
623

 
$
33

 
$
(30
)
 

 
$
745

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$

 
$
(95
)
 
$
(74
)
 
$
59

 
(b)
 
$
(110
)

(a)
Primarily consists of heat rate options and other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral.  See Note 16.
(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 other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral.  See Note 16.
(c)
Represents nuclear decommissioning trust net pending securities sales and purchases.
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2014 and December 31, 2013:
 
 
December 31, 2014
Fair Value (millions)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
30

 
$
56

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$19.51 - $56.72
 
$
35.27

Option Contracts (b)

 
15

 
Option model
 
Electricity forward price (per MWh)
 
$32.14 - $66.09
 
$
45.83

 
 

 
 

 
 
 
Natural gas forward price (per MMbtu)
 
$3.18 - $3.29
 
$
3.25

 
 

 
 

 
 
 
Electricity price volatilities
 
23% - 63%
 
41
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
23% - 41%
 
31
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
3

 
3

 
Discounted cash flows
 
Natural gas forward price (per MMbtu)
 
$2.98 - $4.13
 
$
3.45

Total
$
33

 
$
74

 
 
 
 
 
 
 
 


(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
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
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 natural gas price volatilities are estimated 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 years ended December 31, 2014 and 2013 (dollars in millions):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2014
 
2013
Net derivative balance at beginning of period
 
$
(49
)
 
$
(48
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 

 

Included in OCI
 

 

Deferred as a regulatory asset or liability
 

 
(10
)
Settlements
 
12

 
10

Transfers into Level 3 from Level 2
 
(2
)
 

Transfers from Level 3 into Level 2
 
(2
)
 
(1
)
Net derivative balance at end of period
 
$
(41
)
 
$
(49
)
Net unrealized gains included in earnings related to instruments still held at end of period
 
$

 
$

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 continuing operations attributable to common shareholders for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per share amounts):
 
2014
 
2013
 
2012
Income from continuing operations attributable to common shareholders
$
397,595

 
$
406,074

 
$
387,380

Weighted average common shares outstanding — basic
110,626

 
109,984

 
109,510

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
552

 
822

 
1,017

Weighted average common shares outstanding — diluted
111,178

 
110,806

 
110,527

Earnings per average common share outstanding:
 
 
 
 
 
Income from continuing operations attributable to common shareholders — basic
$
3.59

 
$
3.69

 
$
3.54

Income from continuing operations attributable to common shareholders — diluted
$
3.58

 
$
3.66

 
$
3.50

Stock-Based Compensation (Tables)
The following table is a summary of granted restricted stock units, stock units and stock grants and the weighted-average fair value for the 3 years ended 2014, 2013 and 2012
 
2014
 
2013
 
2012
Units granted
130,273

 
129,620

 
202,278

Grant date fair value (a) 
$
54.91

 
$
55.21

 
$
49.31

(a)
Weighted-average grant date fair value.
The following table is a summary of the status of restricted stock units, stock units and stock grants, as of December 31, 2014 and changes during the year.  This table represents only the stock portion of restricted stock units and stock units, per the election on payment discussed in the paragraph above:
 
Nonvested shares
 
Shares
 
Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2014
 
397,976

 
$
47.74

Granted
 
130,273

 
54.91

Vested
 
(161,283
)
 
45.55

Forfeited
 
(13,067
)
 
51.53

Nonvested at December 31, 2014
 
353,899

 
51.23

The amount of cash required to settle the payments on restricted stock units is (dollars in millions):
 
Year
 
2014
 
2013
 
2012
2008 Grant
 
$

 
$

 
$
1.9

2009 Grant
 

 
3.0

 
1.7

2010 Grant
 
2.3

 
2.3

 
0.6

2011 Grant
 
2.4

 
2.5

 
0.7

2012 Grant
 
2.1

 
2.2

 

2013 Grant
 
2.1

 

 

The following table is a summary of the performance shares granted and the weighted-average fair value for the three years ended 2014, 2013 and 2012:
 
 
2014
 
2013
 
2012
Units granted (a)
166,244

 
176,332

 
185,878

Grant date fair value (b)
$
54.86

 
$
55.45

 
$
47.40


(a)                                 Reflects the target payout level.
(b)                                 Weighted-average grant date fair value.
The following table is a summary of the status of performance shares as of December 31, 2014 and changes during the year:
 
Nonvested shares (a)
 
Shares
 
Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2014
 
344,396

 
$
51.13

Granted
 
166,244

 
54.86

Increase in performance factor
 
86,558

 
47.40

Vested
 
(258,224
)
 
47.40

Forfeited
 
(14,744
)
 
53.30

Nonvested at December 31, 2014
 
324,230

 
54.92


(a)
Nonvested shares are reflected at target payout level.  The increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests.
Derivative Accounting (Tables)
As of December 31, 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
 
3,915

 
GWh
Gas
 
136

 
Bcf (a)
(a)
“Bcf” is Billion Cubic Feet.
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2014
 
2013
 
2012
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(372
)
 
$
(353
)
 
$
(37,663
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(21,415
)
 
(44,219
)
 
(99,007
)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Fuel and purchased power (b)
 

 

 
117


(a)
During the years ended December 31, 2014, 2013, and 2012, we had zero, zero, and $1.8 million of losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2014
 
2013
 
2012
Net Gain Recognized in Income
 
Operating revenues
 
$
324

 
$
289

 
$
103

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(66,367
)
 
(10,449
)
 
(2,747
)
Total
 
 
 
$
(66,043
)
 
$
(10,160
)
 
$
(2,644
)

(a)
Amounts are before the effect of PSA deferrals.
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 December 31, 2014 and 2013.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.
 
As of December 31, 2014:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current Assets
 
$
28,562

 
$
(15,127
)
 
$
13,435

 
$
350

 
$
13,785

Investments and Other Assets
 
24,810

 
(7,190
)
 
17,620

 

 
17,620

Total Assets
 
53,372

 
(22,317
)
 
31,055

 
350

 
31,405

 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
(86,062
)
 
33,829

 
(52,233
)
 
(7,443
)
 
(59,676
)
Deferred Credits and Other
 
(82,990
)
 
32,388

 
(50,602
)
 

 
(50,602
)
Total Liabilities
 
(169,052
)
 
66,217

 
(102,835
)
 
(7,443
)
 
(110,278
)
Total
 
$
(115,680
)
 
$
43,900

 
$
(71,780
)
 
$
(7,093
)
 
$
(78,873
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $43,900.
(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 $7,443, and cash margin provided to counterparties of $350.
 
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
The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2014 (dollars in millions):
 
 
December 31, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position
$
169

Cash Collateral Posted
44

Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)
80


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
Other Income and Other Expense (Tables)
The following table provides detail of other income and other expense for 2014, 2013 and 2012 (dollars in thousands):
 
 
2014
 
2013
 
2012
Other income:
 

 
 

 
 

Interest income
$
1,010

 
$
1,629

 
$
1,239

Debt return on the purchase of Four Corners units 4 & 5
8,386

 

 

Miscellaneous
212

 
75

 
367

Total other income
$
9,608

 
$
1,704

 
$
1,606

Other expense:
 

 
 

 
 

Non-operating costs
$
(9,657
)
 
$
(8,207
)
 
$
(7,777
)
Investment loss — net
(9,426
)
 
(3,711
)
 
(2,453
)
Miscellaneous
(2,663
)
 
(4,106
)
 
(9,612
)
Total other expense
$
(21,746
)
 
$
(16,024
)
 
$
(19,842
)
The following table provides detail of APS’s other income and other expense for 2014, 2013 and 2012 (dollars in thousands):
 
 
2014
 
2013
 
2012
Other income:
 

 
 

 
 

Interest income
$
689

 
$
1,234

 
$
310

Debt return on the purchase of Four Corners units 4 & 5
8,386

 

 

Miscellaneous
2,220

 
2,662

 
2,558

Total other income
$
11,295

 
$
3,896

 
$
2,868

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(10,397
)
 
$
(9,626
)
 
$
(8,706
)
Asset dispositions
(615
)
 
(4,992
)
 
(1,511
)
Miscellaneous
(2,391
)
 
(5,831
)
 
(10,933
)
Total other expense
$
(13,403
)
 
$
(20,449
)
 
$
(21,150
)

(a)As defined by FERC, includes non-operating utility income and expense (items excluded from utility rate recovery).
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
Amounts relating to the VIEs included in Consolidated Balance Sheets
Our Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):
 
 
December 31, 2014
 
December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
121

 
$
125

Current maturities of long-term debt
13

 
26

Long-term debt excluding current maturities

 
13

Equity-Noncontrolling interests
152

 
146

Nuclear Decommissioning Trusts (Tables)
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 December 31, 2014 and December 31, 2013 (dollars in millions):
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2014
 

 
 

 
 

Equity securities
$
310

 
$
159

 
$

Fixed income securities
411

 
17

 
(1
)
Net payables (a)
(7
)
 

 

Total
$
714

 
$
176

 
$
(1
)
 
 
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 purchases and sales of securities.
The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Realized gains
$
5

 
$
6

 
$
7

Realized losses
(5
)
 
(7
)
 
(4
)
Proceeds from the sale of securities (a)
356

 
446

 
418


(a)
Proceeds are reinvested in the trust.
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2014 is as follows (dollars in millions):
 
 
Fair Value
Less than one year
$
14

1 year – 5 years
116

5 years – 10 years
122

Greater than 10 years
159

Total
$
411

Changes in Accumulated Other Comprehensive Loss (Tables)
The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands): 
 
Year Ended December 31, 2014
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(23,058
)
 
 
 
$
(54,995
)
 
 
 
$
(78,053
)
OCI (loss) before reclassifications
(810
)
 
 
 
(5,419
)
 
 
 
(6,229
)
Amounts reclassified from accumulated other comprehensive loss
13,483

 
(a)
 
2,658

 
(b)
 
16,141

Net current period OCI (loss)
12,673

 
 
 
(2,761
)
 
 
 
9,912

Ending balance
$
(10,385
)
 
 
 
$
(57,756
)
 
 
 
$
(68,141
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands): 
 
Year Ended December 31, 2013
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(49,592
)
 
 
 
$
(64,416
)
 
 
 
$
(114,008
)
OCI (loss) before reclassifications
(213
)
 
 
 
5,594

 
 
 
5,381

Amounts reclassified from accumulated other comprehensive loss
26,747

 
(a)
 
3,827

 
(b)
 
30,574

Net current period OCI
26,534

 
 
 
9,421

 
 
 
35,955

Ending balance
$
(23,058
)
 
 
 
$
(54,995
)
 
 
 
$
(78,053
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands): 
 
Year Ended December 31, 2014
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(23,059
)
 
 
 
$
(30,313
)
 
 
 
$
(53,372
)
OCI (loss) before reclassifications
(809
)
 
 
 
(10,415
)
 
 
 
(11,224
)
Amounts reclassified from accumulated other comprehensive loss
13,483

 
(a)
 
2,780

 
(b)
 
16,263

Net current period OCI (loss)
12,674

 
 
 
(7,635
)
 
 
 
5,039

Ending balance
$
(10,385
)
 
 
 
$
(37,948
)
 
 
 
$
(48,333
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands): 
 
Year Ended December 31, 2013
 
Derivative 
Instruments
 
 
 
Pension and 
Other 
Postretirement 
Benefits
 
 
 
Total
Beginning balance
$
(49,592
)
 
 
 
$
(39,503
)
 
 
 
$
(89,095
)
OCI (loss) before reclassifications
(214
)
 
 
 
5,387

 
 
 
5,173

Amounts reclassified from accumulated other comprehensive loss
26,747

 
(a)
 
3,803

 
(b)
 
30,550

Net current period OCI
26,533

 
 
 
9,190

 
 
 
35,723

Ending balance
$
(23,059
)
 
 
 
$
(30,313
)
 
 
 
$
(53,372
)

(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 16.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
Summary of Significant Accounting Policies - Narrative (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 36 Months Ended 12 Months Ended 36 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Pinnacle West
Dec. 31, 2014
Minimum
Dec. 31, 2014
Maximum
Dec. 31, 2014
Maximum
Dec. 31, 2014
Fossil plant
Dec. 31, 2014
Nuclear plant
Dec. 31, 2014
Other generation
Dec. 31, 2014
Transmission
Dec. 31, 2014
Distribution
Dec. 31, 2014
Other
Approximate remaining average useful lives of utility property
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average useful life
 
 
 
 
 
 
 
 
19 years 
28 years 
25 years 
38 years 
33 years 
7 years 
Depreciation rates (as a percent)
2.77% 
3.00% 
2.71% 
 
 
0.30% 
 
12.08% 
 
 
 
 
 
 
Allowance for Funds Used During Construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Composite rate used to calculate AFUDC (as a percent)
8.47% 
8.56% 
8.60% 
 
 
 
 
 
 
 
 
 
 
 
Nuclear Fuel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh)
 
 
 
0.001 
 
 
 
 
 
 
 
 
 
 
Intangible Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization expense
$ 53 
$ 53 
$ 50 
 
 
 
 
 
 
 
 
 
 
 
Estimated amortization expense on existing intangible assets over the next five years
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
42 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016
32 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
21 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$ 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average remaining amortization period for intangible assets
6 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership percentage for classification as cost method investments by El Dorado
 
 
 
 
 
 
20.00% 
 
 
 
 
 
 
 
Preferred Stock
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock, shares authorized (in shares)
 
 
 
15,535,000 
10,000,000 
 
 
 
 
 
 
 
 
 
Preferred stock par or stated value per share 1 (in dollars per share)
 
 
 
$ 25 
 
 
 
 
 
 
 
 
 
 
Preferred stock par or stated value per share 2 (in dollars per share)
 
 
 
$ 50 
 
 
 
 
 
 
 
 
 
 
Preferred stock par or stated value per share 3 (in dollars per share)
 
 
 
$ 100 
 
 
 
 
 
 
 
 
 
 
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
 
 
 
Accrued capital expenditures
$ 44,712 
$ 33,184 
$ 26,208 
Dividends declared but not paid
65,790 
62,528 
59,789 
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)
145,609 
Cash Paid During Period [Abstract]
 
 
 
Income tax (benefit), net of refunds
(102,154)
18,537 
2,543 
Interest, net of amounts capitalized
$ 177,074 
$ 184,010 
$ 200,923 
Regulatory Matters (Details) (APS, USD $)
0 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended
Dec. 31, 2014
Retired power plant costs
Dec. 31, 2014
Lost Fixed Cost Recovery Mechanism
Jan. 1, 2014
ACC
Net Metering
Apr. 15, 2014
Filing with the Arizona Corporation Commission
Arizona Renewable Energy Standard and Tariff 2014 [Member]
MW
Jan. 6, 2012
Filing with the Arizona Corporation Commission
ACC
Retail rate case filing
Jun. 1, 2011
Filing with the Arizona Corporation Commission
ACC
Retail rate case filing
Jan. 31, 2012
Filing with the Arizona Corporation Commission
ACC
Retail rate case filing
Jan. 6, 2012
Filing with the Arizona Corporation Commission
ACC
Retail rate case filing
Jan. 6, 2012
Filing with the Arizona Corporation Commission
ACC
Retail rate case filing
Maximum
Dec. 31, 2014
Cost Recovery Mechanisms
2013 DSMAC
Dec. 31, 2013
Cost Recovery Mechanisms
2013 DSMAC
Dec. 31, 2012
Cost Recovery Mechanisms
2013 DSMAC
Dec. 31, 2014
Cost Recovery Mechanisms
Power Supply Adjustor (PSA)
Apr. 1, 2014
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Feb. 12, 2013
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Dec. 31, 2014
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Jan. 15, 2015
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Subsequent event
Dec. 31, 2014
Cost Recovery Mechanisms
ACC
RES
Jun. 1, 2012
Cost Recovery Mechanisms
ACC
2013 DSMAC
Dec. 31, 2014
Cost Recovery Mechanisms
ACC
RES implementation plan covering 2014-2018 timeframe
Jul. 1, 2014
Cost Recovery Mechanisms
ACC
RES implementation plan covering 2014-2018 timeframe
Jul. 12, 2013
Cost Recovery Mechanisms
ACC
RES implementation plan covering 2014-2018 timeframe
Dec. 31, 2014
Cost Recovery Mechanisms
ACC
Power Supply Adjustor (PSA)
Feb. 1, 2015
Cost Recovery Mechanisms
ACC
Power Supply Adjustor (PSA)
Subsequent event
Jun. 1, 2014
Cost Recovery Mechanisms
FERC
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters
Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Asset, Net Book Value
$ 128,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 
 
 
 
Rate Matter Additional Capacity from AZ Sun Projects
 
 
 
20 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of cumulative energy savings for current year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.00% 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate Matter, Approved Budget
 
 
 
 
 
 
 
 
 
68,900,000 
68,900,000 
 
 
 
 
 
 
 
 
152,000,000 
 
 
 
 
 
PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.000887 
 
PSA rate for prior year (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.001557)
 
 
Increase or decrease in PSA charge (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
0.004 
 
 
 
 
 
 
 
 
 
 
 
 
Forward component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001131 
 
Historical component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.000244)
 
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 
 
 
 
 
 
 
 
 
 
Rate Matter Cap Percentage of Retail Revenue
 
1.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of adjustment approved representing prorated sales losses
 
 
 
 
 
 
 
 
 
 
 
 
 
25,300,000 
5,100,000 
 
 
 
 
 
 
 
 
 
 
Amount of Adjustment Representing Prorated Sales Losses Pending Approval
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 38,500,000 
 
 
 
 
 
 
 
 
Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
$ (26,927,000)
$ 21,678,000 
$ 71,573,000 
Deferred fuel and purchased power amortization
40,757,000 
31,190,000 
(116,716,000)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
(26,927,000)
21,678,000 
71,573,000 
Deferred fuel and purchased power amortization
40,757,000 
31,190,000 
(116,716,000)
ACC |
ARIZONA PUBLIC SERVICE COMPANY |
Power Supply Adjustor (PSA) |
Cost Recovery Mechanisms
 
 
 
Change in regulatory asset
 
 
 
Beginning balance
21,000,000 
73,000,000 
 
Deferred fuel and purchased power
27,000,000 
(21,000,000)
 
Deferred fuel and purchased power amortization
(41,000,000)
(31,000,000)
 
Ending balance
$ 7,000,000 
$ 21,000,000 
 
Regulatory Matters - Four Corners (Details) (USD $)
0 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2014
APS
Dec. 31, 2013
APS
Dec. 31, 2014
Four Corners cost deferral
Dec. 31, 2013
Four Corners cost deferral
Dec. 30, 2013
SCE
Four Corners
APS
Dec. 30, 2013
SCE
Four Corners
APS
MW
Dec. 23, 2014
Four Corners Units 4 and 5
SCE
APS
Jan. 10, 2014
Four Corners Units 4 and 5
SCE
APS
Dec. 30, 2013
Four Corners Units 4 and 5
SCE
APS
Dec. 31, 2014
Four Corners Units 4 and 5
SCE
Four Corners cost deferral
APS
Acquisition
 
 
 
 
 
 
 
 
 
 
 
 
Ownership interest acquired
 
 
 
 
 
 
 
 
 
48.00% 
48.00% 
 
Settlement agreement, ACC approved rate adjustment, annualized customer impact
 
 
 
 
 
 
 
 
$ 57,100,000 
 
 
 
Regulatory assets, non-current
1,054,087,000 
711,712,000 
1,054,087,000 
711,712,000 
70,000,000 
37,000,000 
 
 
 
 
 
77,000,000 
Regulatory asset amortization period
 
 
 
 
 
 
 
 
 
 
 
P10Y 
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 $)
Dec. 31, 2014
Dec. 31, 2013
Detail of regulatory assets
 
 
Regulatory assets, current
$ 138,000,000 
$ 97,000,000 
Regulatory assets, non-current
1,054,087,000 
711,712,000 
Pension and other postretirement benefits
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
Regulatory assets, non-current
485,000,000 
314,000,000 
Income taxes - AFUDC equity
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
5,000,000 
4,000,000 
Regulatory assets, non-current
118,000,000 
105,000,000 
Deferred fuel and purchased power - mark-to-market
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
51,000,000 
5,000,000 
Regulatory assets, non-current
46,000,000 
29,000,000 
Transmission vegetation management
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
9,000,000 
9,000,000 
Regulatory assets, non-current
5,000,000 
14,000,000 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,000,000 
Regulatory assets, non-current
7,000,000 
18,000,000 
Palo Verde VIE
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
Regulatory assets, non-current
35,000,000 
41,000,000 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
Regulatory assets, non-current
34,000,000 
34,000,000 
Deferred fuel and purchased power
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
7,000,000 
21,000,000 
Regulatory assets, non-current
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
16,000,000 
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
4,000,000 
8,000,000 
Regulatory assets, non-current
4,000,000 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
7,000,000 
Regulatory assets, non-current
70,000,000 
37,000,000 
Lost fixed cost recovery
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
38,000,000 
25,000,000 
Regulatory assets, non-current
Transmission cost adjustor
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,000,000 
Regulatory assets, non-current
2,000,000 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
10,000,000 
3,000,000 
Regulatory assets, non-current
136,000,000 
18,000,000 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
Regulatory assets, non-current
30,000,000 
11,000,000 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,000,000 
2,000,000 
Regulatory assets, non-current
$ 12,000,000 
$ 14,000,000 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
Dec. 31, 2014
Dec. 31, 2013
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 131,000,000 
$ 99,000,000 
Regulatory liabilities, non-current
1,051,196,000 
801,297,000 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
31,000,000 
28,000,000 
Regulatory liabilities, non-current
273,000,000 
303,000,000 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
Regulatory liabilities, non-current
296,000,000 
266,000,000 
Renewable energy standard
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
25,000,000 
33,000,000 
Regulatory liabilities, non-current
23,000,000 
15,000,000 
Income taxes - change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
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
66,000,000 
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
8,000,000 
10,000,000 
Income taxes-deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
4,000,000 
3,000,000 
Regulatory liabilities, non-current
93,000,000 
79,000,000 
Demand side management
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
31,000,000 
27,000,000 
Regulatory liabilities, non-current
Other postretirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
32,000,000 
Regulatory liabilities, non-current
199,000,000 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
1,000,000 
Regulatory liabilities, non-current
$ 21,000,000 
$ 18,000,000 
Income Taxes (Details) (USD $)
0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended
Sep. 13, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Sep. 13, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
Third quarter 2009
Dec. 31, 2013
Third quarter 2009
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
Tax Years 2008 and 2009
Dec. 31, 2013
Tax Years 2008 and 2009
ARIZONA PUBLIC SERVICE COMPANY
Feb. 17, 2011
ARIZONA
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Apr. 4, 2013
NEW MEXICO
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
NEW MEXICO
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Maximum
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Palo Verde VIE
Income Taxes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decrease in prior period uncertain tax positions
 
$ 2,282,000 
$ 108,099,000 
$ 7,729,000 
 
$ 2,282,000 
$ 107,918,000 
$ 7,729,000 
$ 67,000,000 
$ 67,000,000 
$ 41,000,000 
$ 41,000,000 
 
 
 
 
 
 
Income tax examination, liability (refund) adjustment from settlement with taxing authority
 
 
(133,000,000)
 
 
 
(135,000,000)
 
 
 
 
 
 
 
 
 
 
 
Decrease in long term deferred tax liability due to adoption of regulations
82,000,000 
26,000,000 
 
 
82,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income tax expense benefit attributable to non controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefits if recognized, would decrease effective tax rate
 
11,000,000 
10,000,000 
10,000,000 
 
11,000,000 
10,000,000 
10,000,000 
 
 
 
 
 
 
 
 
 
 
Pre-tax interest expense (benefit) related to unrecognized tax benefits
 
1,000,000 
(4,000,000)
4,000,000 
 
1,000,000 
4,000,000 
4,000,000 
 
 
 
 
 
 
 
 
 
 
Accrued liabilities for interest related to unrecognized tax benefit (less than $1 million for APS in 2014 and 2013)
 
1,000,000 
1,000,000 
13,000,000 
 
 
1,000,000 
13,000,000 
 
 
 
 
 
 
 
 
1,000,000 
 
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less then $1 million)
 
1,000,000 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Phase-in period of corporate income tax rate reductions beginning in 2014
 
 
 
 
 
 
 
 
 
 
 
 
4 years 
 
5 years 
 
 
 
Decrease in long term deferred tax liability due to rate changes
 
 
 
 
 
 
 
 
 
 
 
 
 
74,000,000 
 
2,000,000 
 
 
General business tax credit carryforwards that will begin to expire in 2031
 
90,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of federal and state loss carryforwards which will begin to expire in 2019
 
$ 4,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
 
 
 
Total unrecognized tax benefits, beginning of the year
$ 41,997 
$ 133,422 
$ 136,005 
Additions for tax positions of the current year
4,309 
3,516 
5,167 
Additions for tax positions of prior years
751 
13,158 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(2,282)
(108,099)
(7,729)
Settlements with taxing authorities
Lapses of applicable statute of limitations
(21)
Total unrecognized tax benefits, end of the year
44,775 
41,997 
133,422 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
 
 
 
Total unrecognized tax benefits, beginning of the year
41,997 
133,241 
135,824 
Additions for tax positions of the current year
4,309 
3,516 
5,167 
Additions for tax positions of prior years
751 
13,158 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(2,282)
(107,918)
(7,729)
Settlements with taxing authorities
Lapses of applicable statute of limitations
(21)
Total unrecognized tax benefits, end of the year
$ 44,775 
$ 41,997 
$ 133,241 
Income Taxes - Components of Income Tax Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
$ 25,054 
$ (81,784)
$ (3,493)
State
 
 
 
 
 
 
 
 
10,382 
10,537 
8,395 
Total current
 
 
 
 
 
 
 
 
35,436 
(71,247)
4,902 
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
167,365 
279,973 
200,322 
State
 
 
 
 
 
 
 
 
17,904 
21,865 
28,280 
Total deferred
 
 
 
 
 
 
 
 
185,269 
301,838 
228,602 
Total income tax expense
 
 
 
 
 
 
 
 
220,705 
230,591 
233,504 
Less: income tax benefit on discontinued operations
 
 
 
 
 
 
 
 
(3,813)
INCOME TAXES (Note 4)
5,007 
134,753 
74,540 
6,405 
9,167 
131,912 
77,043 
12,469 
220,705 
230,591 
237,317 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
40,115 
(97,531)
(11,650)
State
 
 
 
 
 
 
 
 
15,598 
11,983 
12,308 
Total current
 
 
 
 
 
 
 
 
55,713 
(85,548)
658 
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
165,027 
305,389 
216,367 
State
 
 
 
 
 
 
 
 
16,620 
25,254 
27,371 
Total deferred
 
 
 
 
 
 
 
 
181,647 
330,643 
243,738 
Total income tax expense
 
 
 
 
 
 
 
 
237,360 
245,095 
244,396 
INCOME TAXES (Note 4)
 
 
 
 
 
 
 
 
$ 237,360 
$ 245,095 
$ 244,396 
Income Taxes - Effective Tax Rate Reconciliation (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
 
 
 
 
 
 
 
 
 
 
 
Federal income tax rate (as a percent)
 
 
 
 
 
 
 
 
35.00% 
35.00% 
35.00% 
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Federal income tax expense at 35% statutory rate
 
 
 
 
 
 
 
 
$ 225,540,000 
$ 234,695,000 
$ 229,709,000 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
18,149,000 
21,387,000 
23,819,000 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
(3,356,000)
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
830,000 
823,000 
483,000 
Allowance for equity funds used during construction
 
 
 
 
 
 
 
 
(8,523,000)
(6,997,000)
(6,158,000)
Palo Verde VIE noncontrolling interest
 
 
 
 
 
 
 
 
(9,135,000)
(11,862,000)
(11,065,000)
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Amount
 
 
 
 
 
 
 
 
(4,928,000)
(3,548,000)
(2,030,000)
Other
 
 
 
 
 
 
 
 
(1,228,000)
(551,000)
2,559,000 
INCOME TAXES (Note 4)
5,007,000 
134,753,000 
74,540,000 
6,405,000 
9,167,000 
131,912,000 
77,043,000 
12,469,000 
220,705,000 
230,591,000 
237,317,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
 
 
 
 
 
 
 
 
 
 
 
Federal income tax rate (as a percent)
 
 
 
 
 
 
 
 
35.00% 
 
 
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Federal income tax expense at 35% statutory rate
 
 
 
 
 
 
 
 
239,638,000 
246,384,000 
235,027,000 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
21,148,000 
23,970,000 
25,379,000 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
(3,231,000)
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
830,000 
823,000 
483,000 
Allowance for equity funds used during construction
 
 
 
 
 
 
 
 
(8,523,000)
(6,997,000)
(6,158,000)
Palo Verde VIE noncontrolling interest
 
 
 
 
 
 
 
 
(9,135,000)
(11,862,000)
(11,065,000)
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Amount
 
 
 
 
 
 
 
 
(4,928,000)
(3,548,000)
(2,030,000)
Other
 
 
 
 
 
 
 
 
(1,670,000)
(444,000)
2,760,000 
INCOME TAXES (Note 4)
 
 
 
 
 
 
 
 
$ 237,360,000 
$ 245,095,000 
$ 244,396,000 
Income Taxes Income Taxes - Deferred Income Tax Liability Recognized on the Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Net deferred income tax liability recognized on the Consolidated Balance Sheets
 
 
Deferred tax asset, current
$ 122,232 
$ 91,152 
Long-term liability
(2,582,636)
(2,351,882)
Deferred income taxes — net
(2,460,404)
(2,260,730)
ARIZONA PUBLIC SERVICE COMPANY
 
 
Net deferred income tax liability recognized on the Consolidated Balance Sheets
 
 
Deferred tax asset, current
55,253 
Deferred tax liability, current
(2,033)
Long-term liability
(2,571,365)
(2,347,724)
Deferred income taxes — net
$ (2,516,112)
$ (2,349,757)
Income Taxes - Components of Deferred Income Tax Liability (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Regulatory liabilities:
 
 
Asset retirement obligation and removal costs
$ 229,772 
$ 235,959 
Unamortized investment tax credits
96,232 
82,116 
Other postretirement liabilities
90,496 
Other
60,409 
42,609 
Risk management activities
57,505 
44,920 
Pension liabilities
205,227 
140,773 
Other postretirement liabilities
57,869 
Renewable energy incentives
65,169 
65,434 
Credit and loss carryforwards
68,347 
133,070 
Other
138,729 
148,492 
Total deferred tax assets
1,011,886 
951,242 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(2,958,369)
(2,903,730)
Risk management activities
(12,171)
(16,191)
Other postretirement assets
(59,170)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(48,286)
(43,058)
Deferred fuel and purchased power
(2,498)
(8,282)
Deferred fuel and purchased power — mark-to-market
(38,187)
(13,343)
Pension and other postretirement benefits
(191,747)
(129,250)
Retired power plant costs (see Note 3)
(57,255)
(8,199)
Other
(99,123)
(85,003)
Other
(5,484)
(4,916)
Total deferred tax liabilities
(3,472,290)
(3,211,972)
Deferred income taxes — net
(2,460,404)
(2,260,730)
ARIZONA PUBLIC SERVICE COMPANY
 
 
Regulatory liabilities:
 
 
Asset retirement obligation and removal costs
229,772 
235,959 
Unamortized investment tax credits
96,232 
82,116 
Other postretirement liabilities
90,496 
Other
60,409 
42,609 
Risk management activities
57,505 
44,920 
Pension liabilities
194,541 
132,263 
Other postretirement liabilities
53,950 
Renewable energy incentives
65,169 
65,434 
Credit and loss carryforwards
38,183 
Other
161,379 
166,781 
Total deferred tax assets
955,503 
862,215 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(2,958,369)
(2,903,730)
Risk management activities
(12,171)
(16,191)
Other postretirement assets
(58,495)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(48,286)
(43,058)
Deferred fuel and purchased power
(2,498)
(8,282)
Deferred fuel and purchased power — mark-to-market
(38,187)
(13,343)
Pension and other postretirement benefits
(191,747)
(129,250)
Retired power plant costs (see Note 3)
(57,255)
(8,199)
Other
(99,123)
(85,003)
Other
(5,484)
(4,916)
Total deferred tax liabilities
(3,471,615)
(3,211,972)
Deferred income taxes — net
$ (2,516,112)
$ (2,349,757)
Lines of Credit and Short-Term Borrowings (Details) (USD $)
Feb. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Commercial paper
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Commercial paper
Dec. 31, 2014
Commercial paper
Pinnacle West
Dec. 31, 2013
Commercial paper
Pinnacle West
Dec. 31, 2014
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Letter of credit
Pinnacle West
Dec. 31, 2013
Letter of credit
Pinnacle West
Dec. 31, 2014
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Revolving credit facility
Dec. 31, 2013
Revolving credit facility
Dec. 31, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2019
May 9, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2019
May 8, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2016
Dec. 31, 2013
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2016
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2019
May 9, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2019
Apr. 8, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2015
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2018
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2018
Apr. 9, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2018
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing November 2016 and April 2018
Facility
May 8, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2016
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2016
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing April 2018 and May 2019
Facility
Dec. 31, 2014
Line of credit
Pinnacle West
Dec. 31, 2013
Line of credit
Pinnacle West
Lines of Credit and Short-Term Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount committed
 
 
 
 
 
 
 
 
 
 
$ 1,200,000,000 
$ 1,200,000,000 
$ 200,000,000 
$ 200,000,000 
$ 200,000,000 
$ 200,000,000 
 
 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 1,000,000,000 
$ 500,000,000 
$ 500,000,000 
$ 1,000,000,000 
 
 
Number of credit facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders
 
 
 
 
 
 
 
 
 
 
 
 
300,000,000 
 
 
300,000,000 
 
 
 
 
 
 
 
 
700,000,000 
 
 
700,000,000 
 
 
Long-term line of credit
 
147,000,000 
153,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
 
 
109,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial Paper
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum commercial paper support available under credit facility
 
 
 
200,000,000 
200,000,000 
250,000,000 
250,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Provisions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of APS's capitalization used in calculation of short-term debt authorization
7.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Required amount to be used in purchases of natural gas and power which is used in calculation of short-term debt authorization
500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt authorization before increase
4,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt authorization
$ 5,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Commercial paper
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Commercial paper
Dec. 31, 2014
Revolving credit facility
Dec. 31, 2013
Revolving credit facility
Dec. 31, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2019
May 9, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2019
Dec. 31, 2013
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2016
May 8, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2016
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2019
May 9, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2019
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2018
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2018
Apr. 9, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2018
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2016
May 8, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2016
Apr. 8, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2015
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing April 2018 and May 2019
Facility
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing November 2016 and April 2018
Facility
Lines of Credit and Short-Term Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of credit facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount committed
 
 
$ 1,200,000,000 
$ 1,200,000,000 
$ 200,000,000 
$ 200,000,000 
$ 200,000,000 
$ 200,000,000 
 
 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 1,000,000,000 
$ 1,000,000,000 
Unused amount
 
 
1,053,000,000 
1,047,000,000 
200,000,000 
 
200,000,000 
 
 
 
500,000,000 
 
353,000,000 
500,000,000 
 
347,000,000 
 
 
853,000,000 
847,000,000 
Commitment fees (as a percent)
 
 
 
 
0.175% 
 
17.50% 
 
 
 
0.125% 
 
0.125% 
12.50% 
 
12.50% 
 
 
 
 
Long-term line of credit
$ 147,000,000 
$ 153,000,000 
 
 
 
 
 
 
$ 0 
$ 0 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt and Liquidity Matters (Details) (USD $)
12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Jan. 10, 2014
ARIZONA PUBLIC SERVICE COMPANY
SCE
Four Corners Units 4 and 5
Series
Jan. 10, 2014
ARIZONA PUBLIC SERVICE COMPANY
SCE
Four Corners Units 4 and 5
Dec. 30, 2013
ARIZONA PUBLIC SERVICE COMPANY
SCE
Four Corners Units 4 and 5
Jul. 12, 2013
ARIZONA PUBLIC SERVICE COMPANY
Pollution control revenue refunding bonds, 1994 series A
Oct. 11, 2013
ARIZONA PUBLIC SERVICE COMPANY
Pollution control revenue refunding bonds, 1994 series C
Jan. 10, 2014
ARIZONA PUBLIC SERVICE COMPANY
4.70% unsecured senior notes that mature on January 15, 2044
Dec. 31, 2014
Pinnacle West
Dec. 31, 2013
Pinnacle West
Dec. 31, 2012
Pinnacle West
Dec. 31, 2014
Line of credit
Pinnacle West
Term loan facility matures on 31 December, 2017
May 1, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Pollution control revenue refunding bonds, 2009 series A, series D and series E
May 14, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Series A bonds 2009
Dec. 31, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Series D and series E bonds 2009
Sep. 23, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Pollution control revenue refunding bonds 2009 series A due 2034
Jun. 1, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Pollution control revenue refunding bonds 2009 series A due 2034
May 30, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Pollution control revenue refunding bonds 2009 series A due 2034
Jun. 1, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Series B and series C bonds 2009
Oct. 1, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Series C bonds 2009
Dec. 31, 2014
Debt instrument, bond
ARIZONA PUBLIC SERVICE COMPANY
Series B bonds 2009
Jun. 18, 2014
Senior notes
ARIZONA PUBLIC SERVICE COMPANY
Unsecured senior notes 3.35 percent matures on 15 June, 2024
Jun. 18, 2014
Senior notes
ARIZONA PUBLIC SERVICE COMPANY
Unsecured senior notes 5.80 percent matures on 30 June, 2014
Jun. 18, 2014
Senior notes
ARIZONA PUBLIC SERVICE COMPANY
Unsecured senior notes 5.80 percent matures on 30 June, 2014
Dec. 31, 2014
Revolving credit facility
Dec. 31, 2013
Revolving credit facility
May 8, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2016
Dec. 31, 2013
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2016
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2019
May 9, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in 2019
May 8, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2016
Dec. 31, 2013
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2016
Dec. 31, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2019
May 9, 2014
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2019
Dec. 31, 2014
Maximum
Dec. 31, 2014
ACC
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ACC
Minimum
ARIZONA PUBLIC SERVICE COMPANY
Jan. 12, 2015
Subsequent event
Senior notes
ARIZONA PUBLIC SERVICE COMPANY
Unsecured senior notes 2.20 percent matures on 15 January, 2020
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes issued
 
 
 
 
 
 
 
 
 
 
 
$ 250,000,000 
 
 
 
$ 125,000,000 
 
$ 36,000,000 
 
$ 38,000,000 
$ 13,000,000 
 
 
$ 32,000,000 
 
$ 250,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 250,000,000 
Gross long-term debt
 
 
 
3,294,000,000 
 
 
 
 
 
33,000,000 
32,000,000 
 
3,419,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate (as a percent)
 
 
 
 
 
 
 
 
 
 
 
4.70% 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.35% 
 
5.80% 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.20% 
Ownership interest acquired
 
 
 
 
 
 
 
48.00% 
48.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of tax-exempt indebtedness series re-acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Repayments of long-term debt
652,578,000 
122,828,000 
654,286,000 
527,578,000 
122,828,000 
529,286,000 
 
 
 
 
 
 
125,000,000 
125,000,000 
 
 
 
 
 
 
 
 
 
 
 
300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal balance repaid
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
 
 
38,000,000 
64,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument expected to be Issued in the next 12 months
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
64,000,000 
 
 
 
 
 
32,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving credit facility, current borrowing capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,200,000,000 
1,200,000,000 
500,000,000 
500,000,000 
500,000,000 
500,000,000 
200,000,000 
200,000,000 
200,000,000 
200,000,000 
 
 
 
 
Debt Provisions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of consolidated debt to consolidated capitalization (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
65.00% 
 
 
 
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)
 
 
 
45.00% 
 
 
 
 
 
 
 
 
46.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Required common equity ratio ordered by ACC (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
40.00% 
 
Total shareholder equity
4,367,493,000 
4,194,470,000 
 
4,478,243,000 
4,308,884,000 
 
 
 
 
 
 
 
4,367,493,000 
4,194,470,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,500,000,000 
 
 
Total capitalization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,000,000,000 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 3,200,000,000 
 
 
Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Long-term debt
$ 3,415,000 
$ 3,337,000 
Long-term debt less current maturities
3,031,215 
2,796,465 
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
3,294,000 
 
Unamortized discount
(9,206)
(8,732)
Unamortized premium
4,866 
5,047 
Long-term debt
3,289,785 
3,211,889 
Less current maturities
(383,570)
(540,424)
Total long-term debt less current maturities
2,906,215 
2,671,465 
Pinnacle West
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
3,419,000 
 
Long-term debt
125,000 
125,000 
Long-term debt less current maturities
125,000 
125,000 
Pollution Control Bonds - Variable |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
156,405 
75,580 
Less current maturities
(70,000)
 
Pollution Control Bonds - Variable |
APS |
Maximum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
0.27% 
0.06% 
Pollution Control Bonds - Variable |
APS |
Minimum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
0.03% 
0.03% 
Pollution Control Bonds - Fixed |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
249,300 
426,125 
Interest Rates, low end of range (as a percent)
0.45% 
0.45% 
Interest Rates, high end of range (as a percent)
5.75% 
5.75% 
Total Pollution Control Bonds |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
405,705 
501,705 
Senior unsecured notes |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
2,875,000 
2,675,000 
Interest Rates, low end of range (as a percent)
3.35% 
3.35% 
Interest Rates, high end of range (as a percent)
8.75% 
8.75% 
Palo Verde sale leaseback lessor notes |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities
13,420 
38,869 
Interest rate (as a percent)
8.00% 
8.00% 
Term loan facility |
Pinnacle West
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Long-term debt
125,000 
125,000 
Weighted-average interest rate (as a percent)
1.019% 
1.269% 
Senior unsecured notes maturing through 2015 |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Less current maturities
$ (300,000)
 
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) (USD $)
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
 
Principal payments due on long-term debt
 
2015
$ 384,000,000 
2016
357,000,000 
2017
32,000,000 
2018
32,000,000 
2019
500,000,000 
Thereafter
1,989,000,000 
Total
3,294,000,000 
Pinnacle West
 
Principal payments due on long-term debt
 
2015
384,000,000 
2016
357,000,000 
2017
157,000,000 
2018
32,000,000 
2019
500,000,000 
Thereafter
1,989,000,000 
Total
$ 3,419,000,000 
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) (USD $)
Dec. 31, 2014
Dec. 31, 2013
Estimated fair value of long-term debt, including current maturities
 
 
Long-term debt
$ 3,415,000,000 
$ 3,337,000,000 
Long-term debt, fair value
3,839,000,000 
3,579,000,000 
Pinnacle West
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Long-term debt
125,000,000 
125,000,000 
Long-term debt, fair value
125,000,000 
125,000,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Long-term debt
3,289,785,000 
3,211,889,000 
Long-term debt, fair value
$ 3,714,000,000 
$ 3,454,000,000 
Retirement Plans and Other Benefits Retirement Plans and Other Benefits (Details) (USD $)
1 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Jul. 31, 2012
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2014
Pension Benefits
Dec. 31, 2013
Pension Benefits
Dec. 31, 2012
Pension Benefits
Dec. 31, 2014
Pension Benefits
Fixed income securities
Dec. 31, 2014
Pension Benefits
Return-generating assets
Dec. 31, 2014
Pension Benefits
Developed equities
Dec. 31, 2014
Pension Benefits
Emerging equities
Dec. 31, 2014
Pension Benefits
Alternative investments
Dec. 31, 2014
Other postretirement benefits
Dec. 31, 2013
Other postretirement benefits
Dec. 31, 2012
Other postretirement benefits
Dec. 31, 2014
Other postretirement benefits
Fixed income
Dec. 31, 2014
Other postretirement benefits
Non-fixed income
Dec. 31, 2014
Maximum
Pension Benefits
Jan. 1, 2015
Subsequent event
Other postretirement benefits
Age
Dec. 31, 2014
Pinnacle West
Dec. 31, 2013
Pinnacle West
Dec. 31, 2012
Pinnacle West
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Other postretirement benefits
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Other postretirement benefits
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Other postretirement benefits
Plan Design Changes [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Age eligible for benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
65 
 
 
 
 
 
 
 
 
 
 
 
Effect of plan amendment on net periodic benefit cost
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 10,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect of plan amendment on expense
 
 
 
 
 
 
 
 
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect of plan amendment on accumulated benefit obligation
 
 
 
 
 
 
 
 
 
 
 
 
 
316,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets for other postretirement benefits
 
152,290,000 
 
 
 
 
 
 
 
 
152,290,000 
 
 
 
 
 
 
 
 
149,260,000 
 
 
 
 
 
 
Regulatory liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
231,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of other postretirement benefit trust assets for union employee medical costs
 
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of pension and other postretirement benefit costs deferred
 
 
 
14,000,000 
11,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory asset amortization period
3 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of regulatory assets
 
8,000,000 
8,000,000 
4,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected long-term return on plan assets for next fiscal year (as a percent)
 
 
 
 
 
6.90% 
 
 
 
 
 
 
 
4.74% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in mortality assumptions impact on pension and other postretirement obligations
 
67,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partnership funding commitments, maximum contribution amount
 
75,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partnership funding commitments, funded amount
 
30,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Target asset allocation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Target allocation (as a percent)
 
 
 
 
 
 
 
 
58.00% 
42.00% 
22.00% 
6.00% 
14.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Target allocation, minimum (as a percent)
 
 
 
 
 
 
 
 
55.00% 
39.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Target allocation, maximum (as a percent)
 
 
 
 
 
 
 
 
61.00% 
45.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual asset allocation (as a percent)
 
 
 
 
 
 
 
 
61.00% 
39.00% 
 
 
 
 
 
 
43.00% 
57.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Employer's contributions under the plan
 
 
 
 
 
175,000,000 
140,500,000 
65,000,000 
 
 
 
 
 
770,000 
14,438,000 
22,707,000 
 
 
 
 
 
 
 
 
 
175,000,000 
140,000,000 
64,000,000 
1,000,000 
14,000,000 
22,000,000 
Minimum contributions under MAP-21
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum contributions under MAP-21
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected employer contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected employer contributions
 
 
 
 
 
300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
 
 
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
 
 
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Employee savings plan benefits
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APS's employees share of total cost of the plans (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
99.00% 
 
 
 
 
 
 
 
Expenses recorded for the defined contribution savings plan
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 9,000,000 
$ 9,000,000 
$ 8,000,000 
 
 
 
 
 
 
 
 
Retirement Plans and Other Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Amortization of transition obligation
$ 0 
$ 0 
 
Pension Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost - benefits earned during the period
53,080 
64,195 
63,502 
Interest cost on benefit obligation
129,194 
112,392 
119,586 
Expected return on plan assets
(158,998)
(146,333)
(140,979)
Amortization of transition obligation
 
 
Amortization of prior service cost (credit)
869 
1,097 
1,143 
Amortization of net actuarial loss
10,963 
39,852 
44,250 
Net periodic benefit cost
35,108 
71,203 
87,502 
Portion of cost charged to expense
21,985 
38,968 
36,333 
Other Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost - benefits earned during the period
18,139 
23,597 
27,163 
Interest cost on benefit obligation
41,243 
41,536 
46,467 
Expected return on plan assets
(46,400)
(45,717)
(45,793)
Amortization of transition obligation
452 
Amortization of prior service cost (credit)
(9,626)
(179)
(179)
Amortization of net actuarial loss
1,175 
11,310 
20,233 
Net periodic benefit cost
4,531 
30,547 
48,343 
Portion of cost charged to expense
$ 6,000 
$ 18,469 
$ 19,321 
Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Pension Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
$ 2,646,530 
$ 2,850,846 
 
Service cost
53,080 
64,195 
63,502 
Interest cost
129,194 
112,392 
119,586 
Benefit payments
(128,550)
(125,269)
 
Actuarial (gain) loss
378,394 
(255,634)
 
Plan amendments
 
Benefit obligation at the end of the period
3,078,648 
2,646,530 
2,850,846 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
2,264,121 
2,079,181 
 
Actual return on plan assets
292,992 
150,546 
 
Employer's contributions under the plan
175,000 
140,500 
65,000 
Benefit payments
(116,709)
(106,106)
 
Balance at the end of the period
2,615,404 
2,264,121 
2,079,181 
Funded Status at the end of the period
(463,244)
(382,409)
 
Other Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
890,418 
990,418 
 
Service cost
18,139 
23,597 
27,163 
Interest cost
41,243 
41,536 
46,467 
Benefit payments
(29,054)
(26,675)
 
Actuarial (gain) loss
150,188 
(138,458)
 
Plan amendments
(388,599)
 
Benefit obligation at the end of the period
682,335 
890,418 
990,418 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
748,339 
684,221 
 
Actual return on plan assets
105,223 
76,995 
 
Employer's contributions under the plan
770 
14,438 
22,707 
Benefit payments
(19,707)
(27,315)
 
Balance at the end of the period
834,625 
748,339 
684,221 
Funded Status at the end of the period
$ 152,290 
$ (142,079)
 
Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) (Pension Benefits, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Pension Benefits
 
 
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
 
 
Projected benefit obligation
$ 3,078,648 
$ 2,646,530 
Accumulated benefit obligation
2,873,741 
2,469,889 
Fair value of plan assets
$ 2,615,404 
$ 2,264,121 
Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Amounts recognized on the Consolidated Balance Sheets
 
 
Assets for other postretirement benefits
$ 152,290 
$ 0 
Noncurrent liability
(453,736)
(513,628)
Pension Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Assets for other postretirement benefits
Current liability
(9,508)
(10,860)
Noncurrent liability
(453,736)
(371,549)
Net amount recognized
(463,244)
(382,409)
Other Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Assets for other postretirement benefits
152,290 
Current liability
Noncurrent liability
(142,079)
Net amount recognized
$ 152,290 
$ (142,079)
Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Details related to accumulated other comprehensive loss
 
 
Accumulated other comprehensive loss
$ 57,756 
$ 54,995 
Other Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
148,006 
57,816 
Prior service cost (credit)
(379,269)
(296)
APS's portion recorded as a regulatory asset
230,916 
(49,298)
Income tax benefit
851 
(2,528)
Accumulated other comprehensive loss
504 
5,694 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
5,651 
 
Prior service cost (credit)
(37,968)
 
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014
(32,317)
 
Pension Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
577,976 
344,540 
Prior service cost (credit)
1,203 
2,072 
APS's portion recorded as a regulatory asset
(485,037)
(265,107)
Income tax benefit
(36,890)
(32,204)
Accumulated other comprehensive loss
57,252 
49,301 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
28,180 
 
Prior service cost (credit)
595 
 
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014
$ 28,775 
 
Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
 
Rate of compensation increase (as a percent)
4.00% 
 
4.00% 
4.00% 
 
Initial pre-65 healthcare cost trend rate (as a percent)
 
 
7.00% 
7.50% 
 
Initial post-65 healthcare cost trend rate (as a percent)
 
 
5.00% 
7.50% 
 
Ultimate health care cost trend rate (as a percent)
 
 
5.00% 
5.00% 
 
Number of years to ultimate trend rate (pre-65 participants)
 
 
4 years 
4 years 
 
Number of years to ultimate trend rate (post-65 participants)
 
 
0 years 
4 years 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
 
 
Initial pre-65 health care cost trend rate (as a percent)
7.50% 
7.50% 
 
7.50% 
7.50% 
Initial post-65 health care cost trend rate (as a percent)
5.00% 
7.50% 
 
7.50% 
7.50% 
Ultimate healthcare cost trend rate (as a percent)
5.00% 
5.00% 
 
5.00% 
5.00% 
Number of years to ultimate trend rate (pre-65 participants)
4 years 
4 years 
 
4 years 
4 years 
Number of years to ultimate trend rate (post-65 participants)
0 years 
4 years 
 
4 years 
4 years 
Pension Benefits
 
 
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
 
Discount rate (as a percent)
4.02% 
 
4.02% 
4.88% 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
 
 
Discount rate (as a percent)
4.88% 
4.88% 
 
4.01% 
4.42% 
Rate of compensation increase (as a percent)
4.00% 
4.00% 
 
4.00% 
4.00% 
Expected long-term return on plan assets (as a percent)
6.90% 
6.90% 
 
7.00% 
7.75% 
Other Benefits
 
 
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
 
Discount rate (as a percent)
4.14% 
 
4.14% 
5.10% 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
 
 
Discount rate (as a percent)
4.41% 
5.10% 
 
4.20% 
4.59% 
Expected long-term return on plan assets (as a percent)
4.25% 
6.80% 
 
7.00% 
7.75% 
Effects of one percentage point change in the assumed initial and ultimate health care cost trend rates
 
 
 
 
 
Effect of 1% increase on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
 
 
 10 
 
 
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
 
 
(4)
 
 
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs
 
 
12 
 
 
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs
 
 
(9)
 
 
Effect of 1% increase on the accumulated other postretirement benefit obligation
 
 
110 
 
 
Effect of 1% decrease on the accumulated other postretirement benefit obligation
 
 
 (88)
 
 
Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Pension Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
$ 2,615,404 
$ 2,264,121 
$ 2,079,181 
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Net receivables (payables)
16,883 
250 
 
Fair value of plan assets
2,615,404 
2,264,121 
 
Pension Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
556,660 
490,559 
 
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
2,013,932 
1,764,652 
 
Pension Benefits |
Significant Unobservable Inputs (Level 3) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
27,929 
8,660 
 
Other Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
834,625 
748,339 
684,221 
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Net receivables (payables)
4,100 
2,430 
 
Fair value of plan assets
834,625 
748,339 
 
Other Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
414,204 
371,777 
 
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
416,321 
374,132 
 
Other Benefits |
Significant Unobservable Inputs (Level 3) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
 
Cash and cash equivalent funds |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
387 
504 
 
Cash and cash equivalent funds |
Pension Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
387 
504 
 
Cash and cash equivalent funds |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
318 
 
 
Cash and cash equivalent funds |
Other Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
318 
 
 
Corporate debt |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
1,162,096 
898,621 
 
Corporate debt |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
1,162,096 
898,621 
 
Corporate debt |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
187,961 
153,888 
 
Corporate debt |
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
187,961 
153,888 
 
U.S. Treasury |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
291,817 
231,590 
 
U.S. Treasury |
Pension Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
291,817 
231,590 
 
U.S. Treasury |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
130,967 
98,704 
 
U.S. Treasury |
Other Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
130,967 
98,704 
 
Other |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
113,265 
84,011 
 
Other |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
113,265 
84,011 
 
Other |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
35,291 
27,936 
 
Other |
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
35,291 
27,936 
 
U.S. companies, equities |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
246,387 
239,036 
 
U.S. companies, equities |
Pension Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
246,387 
239,036 
 
U.S. companies, equities |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
265,106 
252,181 
 
U.S. companies, equities |
Other Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
265,106 
252,181 
 
International companies, equities |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
18,069 
19,429 
 
International companies, equities |
Pension Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
18,069 
19,429 
 
International companies, equities |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
17,813 
20,892 
 
International companies, equities |
Other Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
17,813 
20,892 
 
U.S. Equities |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
127,336 
116,150 
 
U.S. Equities |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
127,336 
116,150 
 
U.S. Equities |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
88,258 
80,751 
 
U.S. Equities |
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
88,258 
80,751 
 
International equities |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
317,167 
367,551 
 
International equities |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
317,167 
367,551 
 
International equities |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
85,746 
92,382 
 
International equities |
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
85,746 
92,382 
 
Fixed income securities |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
 
137,520 
 
Fixed income securities |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
 
137,520 
 
Real estate |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
129,715 
119,739 
 
Real estate |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
129,715 
119,739 
 
Real estate |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
11,657 
10,761 
 
Real estate |
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
11,657 
10,761 
 
Partnerships |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
166,266 
8,660 
 
Partnerships |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
138,337 
 
Partnerships |
Pension Benefits |
Significant Unobservable Inputs (Level 3) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
27,929 
8,660 
 
Short-term investments and other |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Net receivables (payables)
16,883 
250 
 
Fair value of plan assets
42,899 
41,310 
 
Short-term investments and other |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
26,016 
41,060 
 
Short-term investments and other |
Pension Benefits |
Significant Unobservable Inputs (Level 3)
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
27,929 
8,660 
2,419 
Short-term investments and other |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Net receivables (payables)
4,100 
2,430 
 
Fair value of plan assets
11,508 
10,844 
 
Short-term investments and other |
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
$ 7,408 
$ 8,414 
 
Retirement Plans and Other Benefits - Changes in Fair Value (Details) (Pension Benefits, USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Short-term investments and other
Significant Unobservable Inputs (Level 3)
Dec. 31, 2013
Short-term investments and other
Significant Unobservable Inputs (Level 3)
Changes in fair value for assets that are measured at fair value on a recurring basis
 
 
 
 
 
Balance at the beginning of the period
$ 2,615,404 
$ 2,264,121 
$ 2,079,181 
$ 8,660 
$ 2,419 
Actual return on assets still held
 
 
 
927 
(498)
Purchases
 
 
 
19,984 
7,377 
Sales
 
 
 
(1,642)
(638)
Transfers in and/or out of Level 3
 
 
 
Balance at the end of the period
$ 2,615,404 
$ 2,264,121 
$ 2,079,181 
$ 27,929 
$ 8,660 
Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Pension Benefits
 
Estimated Future Benefit Payments
 
2015
$ 139,013 
2016
155,968 
2017
160,080 
2018
167,600 
2019
177,470 
Years 2020-2024
983,557 
Other Benefits
 
Estimated Future Benefit Payments
 
2015
25,134 
2016
27,311 
2017
29,253 
2018
31,258 
2019
33,190 
Years 2020-2024
$ 184,772 
Leases (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Trust
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 1986
Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
2015
$ 18 
 
 
 
2016
 
 
 
2017
 
 
 
2018
 
 
 
2019
 
 
 
Thereafter
63 
 
 
 
Total future lease commitments
99 
 
 
 
Lease expense
18 
18 
19 
 
APS
 
 
 
 
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
2015
15 
 
 
 
2016
 
 
 
2017
 
 
 
2018
 
 
 
2019
 
 
 
Thereafter
62 
 
 
 
Total future lease commitments
95 
 
 
 
Lease expense
$ 15 
$ 15 
$ 16 
 
Number of VIE lessor trusts
 
 
Palo Verde Lessor Trusts
 
 
 
 
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
Number of VIE lessor trusts
 
 
 
Jointly-Owned Facilities (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Palo Verde Units 1 and 3
 
Interests in jointly-owned facilities
 
Percent Owned
29.10% 
Plant in Service
$ 1,734,918 
Accumulated Depreciation
1,051,670 
Construction Work in Progress
16,955 
Palo Verde Unit 2
 
Interests in jointly-owned facilities
 
Percent Owned
16.80% 
Plant in Service
556,472 
Accumulated Depreciation
349,960 
Construction Work in Progress
13,710 
Palo Verde Common
 
Interests in jointly-owned facilities
 
Percent Owned
28.00% 
Plant in Service
612,190 
Accumulated Depreciation
224,208 
Construction Work in Progress
68,896 
Palo Verde Sale Leaseback
 
Interests in jointly-owned facilities
 
Plant in Service
351,050 
Accumulated Depreciation
229,795 
Construction Work in Progress
Four Corners Units 4, 5 and Common
 
Interests in jointly-owned facilities
 
Percent Owned
63.00% 
Plant in Service
811,648 
Accumulated Depreciation
578,772 
Construction Work in Progress
33,150 
Navajo Generating Station Units 1, 2 and 3
 
Interests in jointly-owned facilities
 
Percent Owned
14.00% 
Plant in Service
272,208 
Accumulated Depreciation
159,198 
Construction Work in Progress
2,716 
Cholla common facilities
 
Interests in jointly-owned facilities
 
Percent Owned
63.30% 
Plant in Service
155,856 
Accumulated Depreciation
49,954 
Construction Work in Progress
866 
ANPP 500kV System
 
Interests in jointly-owned facilities
 
Percent Owned
33.60% 
Plant in Service
106,369 
Accumulated Depreciation
35,035 
Construction Work in Progress
3,731 
Navajo Southern System
 
Interests in jointly-owned facilities
 
Percent Owned
22.50% 
Plant in Service
59,994 
Accumulated Depreciation
18,119 
Construction Work in Progress
1,113 
Palo Verde - Yuma 500kV System
 
Interests in jointly-owned facilities
 
Percent Owned
18.20% 
Plant in Service
12,925 
Accumulated Depreciation
4,943 
Construction Work in Progress
12 
Four Corners Switchyards
 
Interests in jointly-owned facilities
 
Percent Owned
47.50% 
Plant in Service
33,034 
Accumulated Depreciation
10,035 
Construction Work in Progress
386 
Phoenix - Mead System
 
Interests in jointly-owned facilities
 
Percent Owned
17.10% 
Plant in Service
39,777 
Accumulated Depreciation
12,843 
Construction Work in Progress
105 
Palo Verde - Estrella 500kV System
 
Interests in jointly-owned facilities
 
Percent Owned
50.00% 
Plant in Service
89,572 
Accumulated Depreciation
16,491 
Construction Work in Progress
736 
Morgan-Pinnacle Peak System
 
Interests in jointly-owned facilities
 
Percent Owned
64.40% 
Plant in Service
130,840 
Accumulated Depreciation
8,970 
Construction Work in Progress
1,690 
Round Valley System
 
Interests in jointly-owned facilities
 
Percent Owned
50.00% 
Plant in Service
497 
Accumulated Depreciation
276 
Construction Work in Progress
Palo Verde - Morgan System
 
Interests in jointly-owned facilities
 
Percent Owned
90.00% 
Plant in Service
Accumulated Depreciation
Construction Work in Progress
69,377 
Hassayampa - North Gila System
 
Interests in jointly-owned facilities
 
Percent Owned
80.00% 
Plant in Service
8,902 
Accumulated Depreciation
3,634 
Construction Work in Progress
$ 142,645 
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)
0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended
Jul. 7, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Coal take-or-pay commitments
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Coal take-or-pay commitments
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Coal take-or-pay commitments
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Renewable energy credits
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Obligations
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Obligations
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 [Abstract]
 
 
 
 
 
 
 
 
 
 
 
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 assessment per reactor for each nuclear incident
 
127,300,000 
 
 
 
 
 
 
 
 
 
Annual limit per incident with respect to maximum assessment
 
19,000,000 
 
 
 
 
 
 
 
 
 
Number of VIE lessor trusts
 
 
 
 
 
 
 
 
 
Maximum potential retrospective assessment per incident of APS
 
111,000,000 
 
 
 
 
 
 
 
 
 
Annual payment limitation with respect to maximum potential retrospective 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 
 
 
 
 
 
 
 
 
 
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
 
 
 
 
 
 
 
 
 
 
 
2015
 
723,000,000 
 
151,000,000 
 
 
46,000,000 
1,000,000 
 
 
 
2016
 
747,000,000 
 
171,000,000 
 
 
42,000,000 
15,000,000 
 
 
 
2017
 
630,000,000 
 
195,000,000 
 
 
42,000,000 
17,000,000 
 
 
 
2018
 
610,000,000 
 
190,000,000 
 
 
42,000,000 
18,000,000 
 
 
 
2019
 
583,000,000 
 
194,000,000 
 
 
42,000,000 
19,000,000 
 
 
 
Thereafter
 
8,200,000,000 
 
2,469,000,000 
 
 
448,000,000 
281,000,000 
 
 
 
Total obligation
 
 
 
3,400,000,000 
 
 
 
198,000,000 
207,000,000 
 
 
Present value of commitments
 
 
 
2,200,000,000 
 
 
 
 
 
 
 
Total purchases
 
 
 
$ 237,000,000 
$ 188,000,000 
$ 196,000,000 
 
 
 
 
 
Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)
12 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2014
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Cholla
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Cholla Units 1-3
ARIZONA PUBLIC SERVICE COMPANY
May 23, 2013
New Mexico Tax Matter
Four Corners
May 23, 2013
New Mexico Tax Matter
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Equity Lessors Sale Leaseback Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Natural Gas Tolling Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Four Corners Units 4 and 5
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Four Corners Units 4 and 5
Navajo Plant
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Four Corners Units 4 and 5
Cholla
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Four Corners Units 4 and 5
Natural Gas Tolling Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Minimum
Four Corners Units 4 and 5
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of share of cost of control
 
 
 
 
 
 
 
 
 
 
 
63.00% 
 
Expected environmental cost
 
 
$ 130,000,000 
 
 
 
 
 
 
$ 200,000,000 
$ 200,000,000 
 
$ 350,000,000 
Additional percentage share of cost of control
 
 
 
 
 
 
 
 
 
 
 
7.00% 
 
Additional expected environment cost
15,000,000 
85,000,000 
 
 
 
 
 
 
40,000,000 
 
 
 
 
Coal severance surtax, penalty, and interest
 
 
 
30,000,000 
 
 
 
 
 
 
 
 
 
Share of the assessment
 
 
 
 
12,000,000 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
$ 109,000,000 
$ 23,000,000 
$ 5,000,000 
 
 
 
 
 
Asset Retirement Obligations (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Changes attributable to:
 
 
Asset retirement obligations, current
$ 32,462,000 
$ 32,896,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Change in asset retirement obligations
 
 
Beginning balance
347,000,000 
357,000,000 
Changes attributable to:
 
 
Accretion expense
24,000,000 
24,000,000 
Settlements
(30,000,000)
(12,000,000)
Assumed SCE's obligation
34,000,000 
Estimated cash flow revisions
44,000,000 
(56,000,000)
Newly incurred obligation
6,000,000 
Ending balance
391,000,000 
347,000,000 
Asset retirement obligations, current
32,462,000 
32,896,000 
Four Corners Units 1 Through 3 |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Estimated cash flow revisions
24,000,000 
4,000,000 
Solar Facility |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Newly incurred obligation
6,000,000 
 
Palo Verde Nuclear Facilities and Certain other Generation Transmission and Distribution Assets |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Estimated cash flow revisions
20,000,000 
52,000,000 
Four Corners |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Assumed SCE's obligation
 
$ 34,000,000 
Selected Quarterly Financial Data (Unaudited) (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
OPERATING REVENUES
$ 726,450 
$ 1,172,667 
$ 906,264 
$ 686,251 
$ 699,762 
$ 1,152,392 
$ 915,822 
$ 686,652 
$ 3,491,632 
$ 3,454,628 
$ 3,301,804 
Operations and maintenance
260,503 
223,418 
211,222 
212,882 
238,854 
233,323 
229,300 
223,250 
908,025 
924,727 
884,769 
Operating income
60,184 
421,775 
254,113 
75,170 
83,900 
415,688 
259,812 
86,923 
811,242 
846,323 
851,755 
Income taxes
5,007 
134,753 
74,540 
6,405 
9,167 
131,912 
77,043 
12,469 
220,705 
230,591 
237,317 
Income from continuing operations
9,535 
248,086 
141,384 
24,691 
32,814 
234,718 
139,598 
32,836 
423,696 
439,966 
418,993 
Net income attributable to common shareholders
5,410 
243,961 
132,458 
15,766 
24,260 
226,163 
131,207 
24,444 
397,595 
406,074 
381,542 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.05 
$ 2.20 
$ 1.20 
$ 0.14 
$ 0.22 
$ 2.06 
$ 1.19 
$ 0.22 
$ 3.59 
$ 3.69 
$ 3.48 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 0.05 
$ 2.20 
$ 1.19 
$ 0.14 
$ 0.22 
$ 2.04 
$ 1.18 
$ 0.22 
$ 3.58 
$ 3.66 
$ 3.45 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Electric domestic regulated revenue
725,633 
1,172,190 
905,578 
685,545 
698,824 
1,151,535 
915,065 
685,827 
3,488,946 
3,451,251 
3,293,489 
Operations and maintenance
253,668 
212,430 
208,059 
208,285 
229,505 
222,617 
224,950 
220,752 
882,442 
897,824 
873,916 
Operating income
54,835 
287,928 
180,394 
69,635 
79,024 
284,251 
183,728 
74,862 
592,792 
621,865 
605,529 
Income taxes
 
 
 
 
 
 
 
 
237,360 
245,095 
244,396 
Net income attributable to common shareholders
$ 15,738 
$ 251,047 
$ 134,916 
$ 19,518 
$ 30,024 
$ 234,954 
$ 133,949 
$ 26,042 
$ 421,219 
$ 424,969 
$ 395,497 
Fair Value Measurements - Fair Value of Assets and Liabilities (Details) (USD $)
Dec. 31, 2014
Dec. 31, 2013
Assets
 
 
Nuclear decommissioning trust
$ 713,866,000 
$ 642,007,000 
Total assets
33,000,000 
41,000,000 
Fair value measurement on a recurring basis
 
 
Assets
 
 
Other
(23,000,000)
(9,000,000)
Derivative assets
31,000,000 
41,000,000 
Other
(7,000,000)
(3,000,000)
Nuclear decommissioning trust
714,000,000 
642,000,000 
Other
(30,000,000)
(12,000,000)
Total assets
745,000,000 
683,000,000 
Liabilities
 
 
Other
59,000,000 
21,000,000 
Derivative Liability
(110,000,000)
(102,000,000)
Fair value measurement on a recurring basis |
US commingled equity funds
 
 
Assets
 
 
Nuclear decommissioning trust
310,000,000 
272,000,000 
Fair value measurement on a recurring basis |
U.S. Treasury
 
 
Assets
 
 
Nuclear decommissioning trust
119,000,000 
107,000,000 
Fair value measurement on a recurring basis |
Cash and cash equivalent funds
 
 
Assets
 
 
Other
(7,000,000)
(3,000,000)
Nuclear decommissioning trust
4,000,000 
8,000,000 
Fair value measurement on a recurring basis |
Corporate debt
 
 
Assets
 
 
Nuclear decommissioning trust
109,000,000 
88,000,000 
Fair value measurement on a recurring basis |
Mortgage-backed securities
 
 
Assets
 
 
Nuclear decommissioning trust
89,000,000 
85,000,000 
Fair value measurement on a recurring basis |
Municipality bonds
 
 
Assets
 
 
Nuclear decommissioning trust
69,000,000 
71,000,000 
Fair value measurement on a recurring basis |
Other
 
 
Assets
 
 
Nuclear decommissioning trust
14,000,000 
11,000,000 
Fair value measurement on a recurring basis |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
119,000,000 
107,000,000 
Gross assets, fair value disclosure
119,000,000 
107,000,000 
Fair value measurement on a recurring basis |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
U.S. Treasury
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
119,000,000 
107,000,000 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Gross derivative assets
21,000,000 
9,000,000 
Decommissioning fund investments, gross fair value
602,000,000 
538,000,000 
Gross assets, fair value disclosure
623,000,000 
547,000,000 
Liabilities
 
 
Gross derivative liability
(95,000,000)
(33,000,000)
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
US commingled equity funds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
310,000,000 
272,000,000 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Cash and cash equivalent funds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
11,000,000 
11,000,000 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Corporate debt
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
109,000,000 
88,000,000 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
89,000,000 
85,000,000 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Municipality bonds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
69,000,000 
71,000,000 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Other
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
14,000,000 
11,000,000 
Fair value measurement on a recurring basis |
Significant Unobservable Inputs (Level 3)
 
 
Assets
 
 
Gross derivative assets
33,000,000 
41,000,000 
Gross assets, fair value disclosure
33,000,000 
41,000,000 
Liabilities
 
 
Gross derivative liability
$ (74,000,000)
$ (90,000,000)
Fair Value Measurements - Level 3 Quantative Information (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
$ 33 
$ 41 
Liabilities
74 
90 
Electricity forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
30 
40 
Liabilities
56 
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)
19.51 
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)
56.72 
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)
35.27 
41.09 
Option Contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
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)
32.14 
39.91 
Natural gas forward price (per MMbtu)
3.18 
3.57 
Implied electricity price volatilities (as a percent)
23.00% 
35.00% 
Implied natural gas price volatilities (as a percent)
23.00% 
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)
66.09 
85.41 
Natural gas forward price (per MMbtu)
3.29 
3.80 
Implied electricity price volatilities (as a percent)
63.00% 
94.00% 
Implied natural gas price volatilities (as a percent)
41.00% 
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)
45.83 
58.70 
Natural gas forward price (per MMbtu)
3.25 
3.71 
Implied electricity price volatilities (as a percent)
41.00% 
59.00% 
Implied natural gas price volatilities (as a percent)
31.00% 
27.00% 
Natural gas forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
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)
2.98 
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)
4.13 
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)
3.45 
3.87 
Fair Value Measurements Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Total net gains (losses) realized/unrealized:
 
 
Net derivative beginning balance
$ (49,000,000)
$ (48,000,000)
Included in earnings
Included in OCI
Deferred as a regulatory asset or liability
(10,000,000)
Settlements
12,000,000 
10,000,000 
Transfers into Level 3 from Level 2
(2,000,000)
Transfers from Level 3 into Level 2
(2,000,000)
(1,000,000)
Net derivative ending balance
(41,000,000)
(49,000,000)
Net unrealized gains included in earnings related to instruments still held at end of period
Significant level 1 transfers
$ 0 
 
Earnings Per Share (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Earnings Per Share [Abstract]
 
 
 
Income from continuing operations attributable to common shareholders
$ 397,595 
$ 406,074 
$ 387,380 
Average common shares outstanding — basic (in shares)
110,626 
109,984 
109,510 
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
 
 
 
Contingently issuable performance shares and restricted stock units
552 
822 
1,017 
Average common shares outstanding — diluted
111,178 
110,806 
110,527 
Income from continuing operations attributable to common shareholders — basic (in dollars per share)
$ 3.59 
$ 3.69 
$ 3.54 
Income from continuing operations attributable to common shareholders — diluted (in dollars per share)
$ 3.58 
$ 3.66 
$ 3.50 
Stock-Based Compensation Stock-Based Compensation - Summary of Restricted Stock and Stock Units Grants (Details) (Restricted stock units and stock grants, USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Restricted stock units and stock grants
 
 
 
Stocks granted and the weighted average fair value
 
 
 
Units granted (in shares)
130,273 
129,620 
202,278 
Grant date fair value (in dollars per share)
$ 54.91 
$ 55.21 
$ 49.31 
Stock-Based Compensation Stock-Based Compensation - Status of Restricted Stock Units and Stock Grants (Details) (Restricted stock units and stock grants, USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Restricted stock units and stock grants
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
397,976 
 
 
Granted (in shares)
130,273 
 
 
Vested (in shares)
(161,283)
 
 
Forfeited (in shares)
(13,067)
 
 
Balance at the end of the period (in shares)
353,899 
397,976 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 47.74 
 
 
Granted (in dollars per share)
$ 54.91 
$ 55.21 
$ 49.31 
Vested (in dollars per share)
$ 45.55 
 
 
Forfeited (in dollars per share)
$ 51.53 
 
 
Balance at the end of the period (in dollars per share)
$ 51.23 
$ 47.74 
 
Stock-Based Compensation Stock-Based Compensation - Cash Required to Settle Payments on Restricted Stock Units (Details) (Restricted stock units and stock grants, USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
2008 Grant
 
 
 
Stock-Based Compensation
 
 
 
Cash required to settle the payment for grant
$ 0 
$ 0 
$ 1.9 
2009 Grant
 
 
 
Stock-Based Compensation
 
 
 
Cash required to settle the payment for grant
3.0 
1.7 
2010 Grant
 
 
 
Stock-Based Compensation
 
 
 
Cash required to settle the payment for grant
2.3 
2.3 
0.6 
2011 Grant
 
 
 
Stock-Based Compensation
 
 
 
Cash required to settle the payment for grant
2.4 
2.5 
0.7 
2012 Grant
 
 
 
Stock-Based Compensation
 
 
 
Cash required to settle the payment for grant
2.1 
2.2 
2013 Grant
 
 
 
Stock-Based Compensation
 
 
 
Cash required to settle the payment for grant
$ 2.1 
$ 0 
$ 0 
Stock-Based Compensation Stock-Based Compensation - Summary of Performance Shares (Details) (Performance Share Awards, USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Performance Share Awards
 
 
 
Stock-Based Compensation
 
 
 
Units granted (in shares)
166,244 
176,332 
185,878 
Grant date fair value (in dollars per share)
$ 54.86 
$ 55.45 
$ 47.40 
Stock-Based Compensation Stock-Based Compensation - Performance Shares Roll-Forward (Details) (Performance Share Awards, USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Performance Share Awards
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
344,396 
 
 
Granted (in shares)
166,244 
 
 
Increase in performance factor
86,558 
 
 
Vested (in shares)
(258,224)
 
 
Forfeited (in shares)
(14,744)
 
 
Balance at the end of the period (in shares)
324,230 
344,396 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 51.13 
 
 
Grant date fair value (in dollars per share)
$ 54.86 
$ 55.45 
$ 47.40 
Increase in performance factor (in dollars per share)
$ 47.40 
 
 
Vested (in dollars per share)
$ 47.40 
 
 
Forfeited (in dollars per share)
$ 53.30 
 
 
Balance at the end of the period (in dollars per share)
$ 54.92 
$ 51.13 
 
Stock-Based Compensation (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 0 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 3 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
May 16, 2012
2013 Grant
Feb. 15, 2014
Restricted stock unit awards
Feb. 15, 2013
Restricted stock unit awards
Dec. 31, 2014
Restricted stock unit awards
Dec. 31, 2014
Restricted stock units and stock grants
Dec. 31, 2014
Performance Share Awards
Dec. 31, 2013
Performance Share Awards
2013 Grant
metric
Dec. 31, 2012
Performance Share Awards
2013 Grant
Dec. 31, 2012
Performance Share Awards
2013 Grant
Maximum
Dec. 31, 2012
Performance Share Awards
2013 Grant
Minimum
Dec. 31, 2014
Performance Share Awards
2008 Grant
element
Dec. 31, 2014
Performance Share Awards
2012 Grant
metric
Dec. 31, 2013
Performance Share Awards
2012 Grant
Maximum
Dec. 31, 2013
Performance Share Awards
2012 Grant
Minimum
Dec. 31, 2013
Performance Share Awards
2014 Grant
Dec. 31, 2012
Performance Share Awards
2014 Grant
metric
Dec. 31, 2014
Performance Share Awards
2014 Grant
Maximum
Dec. 31, 2014
Performance Share Awards
2014 Grant
Minimum
Dec. 31, 2012
Retention Units
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Feb. 15, 2015
Subsequent event
Restricted stock unit awards
Dec. 31, 2014
Chief Executive Officer
Restricted stock unit awards
Mar. 31, 2014
Officer
Restricted stock unit awards
Stock-Based Compensation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares to be available for grant under the 2012 Long Term Incentive Plan
 
 
 
4,595,500 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Stock Unit Awards and Stock Grants
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of cash that the participant may elect as a dividend for the first option available under the plan
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of cash that the participant may elect as a dividend equivalent deferral under the first option available under the plan
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of cash that the participant may elect as a dividend equivalent deferral under the first option available under the plan
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vesting period
 
 
 
 
 
 
4 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Granted (in shares)
 
 
 
 
 
 
 
130,273 
166,244 
 
 
 
 
 
 
 
 
 
 
 
 
50,617 
 
 
 
 
 
 
Number of shares of stock awarded for each unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional shares to be granted as retention award if performance requirements are met
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
33,745 
 
 
 
 
 
 
Percentage of awards vesting on February 15, 2013
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of awards vesting on February 15, 2014
 
 
 
 
25.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of awards vesting on February 15, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25.00% 
 
 
Performance Shares
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of performance element criteria
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Performance period
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
3 years 
 
 
 
3 years 
 
 
 
 
 
 
 
 
 
 
Percentage of the awards that vest based on a percentile ranking of total shareholder return
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
50.00% 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
Percentage of the awards that vest based on non-financial separate performance metrics
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
50.00% 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
Number of non-financial separate performance metrics based on which awards vest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exact number of shares issued as a percentage of the target award
 
 
 
 
 
 
 
 
 
 
 
200.00% 
0.00% 
 
 
200.00% 
0.00% 
 
 
200.00% 
0.00% 
 
 
 
 
 
 
 
Stock Options
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted
$ 15 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected weighted-average period of recognition of unrecognized compensation cost
2 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total fair value of shares vested
20 
20 
19 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Compensation cost that has been charged against income
33 
25 
32 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
33 
25 
32 
 
 
 
Total income tax benefit recognized
$ 13 
$ 10 
$ 13 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative Accounting (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Counterparty
Dec. 31, 2013
Derivative Accounting
 
 
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment
100.00% 
 
Designated as Hedging Instruments
 
 
Derivative Accounting
 
 
Derivative Liability
$ 4,000,000 
$ 5,000,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Derivative Accounting
 
 
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change
100.00% 
 
Commodity Contracts
 
 
Derivative Accounting
 
 
Derivative Liability
110,278,000 
102,207,000 
Concentration of credit risk, number of counterparties
 
Concentration risk
90.00% 
 
Derivative assets
31,405,000 
40,984,000 
Additional collateral to counterparties for energy related non-derivative instrument contracts
175,000,000 
 
Commodity Contracts |
Designated as Hedging Instruments
 
 
Derivative Accounting
 
 
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income
$ (6,000,000)
 
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details)
Dec. 31, 2014
GW
Commodity - Power
 
Outstanding gross notional amount of derivatives
 
Outstanding gross notional amount of derivative instruments
3,915 
Commodity - Gas
 
Outstanding gross notional amount of derivatives
 
Outstanding gross notional amount of derivative instruments
136,000 
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Designated as Hedging Instruments
 
 
 
Derivative Instruments in Designated Cash Flows Hedges
 
 
 
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
$ (372,000)
$ (353,000)
$ (37,663,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)
(21,415,000)
(44,219,000)
(99,007,000)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
117,000 
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges
1,800,000 
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
(66,043,000)
(10,160,000)
(2,644,000)
Revenue |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
324,000 
289,000 
103,000 
Fuel and purchased power |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
$ (66,367,000)
$ (10,449,000)
$ (2,747,000)
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Commodity Contracts
 
 
Assets
 
 
Gross Recognized Derivatives
$ 53,372 
$ 49,951 
Amounts Offset
(22,317)
(8,974)
Net Recognized Derivatives
31,055 
40,977 
Other
350 
Amount Reported on Balance Sheet
31,405 
40,984 
Liabilities
 
 
Gross Recognized Derivatives
(169,052)
(122,663)
Amounts Offset
66,217 
27,974 
Net Recognized Derivatives
(102,835)
(94,689)
Other
(7,443)
(7,518)
Amount Reported on Balance Sheet
(110,278)
(102,207)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(115,680)
(72,712)
Amounts Offset
43,900 
19,000 
Net Recognized Derivatives
(71,780)
(53,712)
Other
(7,093)
(7,511)
Amount Reported on Balance Sheet
(78,873)
(61,223)
Commodity Contracts |
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
28,562 
24,587 
Amounts Offset
(15,127)
(7,425)
Net Recognized Derivatives
13,435 
17,162 
Other
350 
Amount Reported on Balance Sheet
13,785 
17,169 
Commodity Contracts |
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
24,810 
25,364 
Amounts Offset
(7,190)
(1,549)
Net Recognized Derivatives
17,620 
23,815 
Other
Amount Reported on Balance Sheet
17,620 
23,815 
Commodity Contracts |
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(86,062)
(50,540)
Amounts Offset
33,829 
26,166 
Net Recognized Derivatives
(52,233)
(24,374)
Other
(7,443)
(7,518)
Amount Reported on Balance Sheet
(59,676)
(31,892)
Assets and Liabilities
 
 
Amounts Offset
43,900 
19,000 
Commodity Contracts |
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(82,990)
(72,123)
Amounts Offset
32,388 
1,808 
Net Recognized Derivatives
(50,602)
(70,315)
Other
Amount Reported on Balance Sheet
(50,602)
(70,315)
Designated as Hedging Instruments
 
 
Liabilities
 
 
Amount Reported on Balance Sheet
$ (4,000)
$ (5,000)
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Other income:
 
 
 
Interest income
$ 1,010 
$ 1,629 
$ 1,239 
Investment gains - net
8,386 
 
Miscellaneous
212 
75 
367 
Total other income
9,608 
1,704 
1,606 
Other expense:
 
 
 
Non-operating costs
(9,657)
(8,207)
(7,777)
Investment loss - net
(9,426)
(3,711)
(2,453)
Miscellaneous
(2,663)
(4,106)
(9,612)
Total other expense
(21,746)
(16,024)
(19,842)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Other income:
 
 
 
Interest income
689 
1,234 
310 
Investment gains - net
8,386 
Miscellaneous
2,220 
2,662 
2,558 
Total other income
11,295 
3,896 
2,868 
Other expense:
 
 
 
Non-operating costs
(10,397)
(9,626)
(8,706)
Asset dispositions
(615)
(4,992)
(1,511)
Miscellaneous
(2,391)
(5,831)
(10,933)
Total other expense
$ (13,403)
$ (20,449)
$ (21,150)
Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)
12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Jul. 7, 2014
Period Through 2023
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Lease
Jul. 7, 2014
Period Through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Lease
Dec. 31, 2014
Period 2016 through 2023
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2014
Period 2024 through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Jul. 7, 2014
Maximum
Period 2024 through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of VIE lessor trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual lease payments
 
 
 
$ 49,000,000 
 
 
 
 
 
 
 
 
$ 23,000,000 
$ 16,000,000 
 
Number of leases under which assets are retained
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 years 
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts
26,101,000 
33,892,000 
31,622,000 
26,101,000 
33,892,000 
31,613,000 
 
26,000,000 
34,000,000 
32,000,000 
 
 
 
 
 
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events
 
 
 
 
 
 
 
123,000,000 
 
 
 
 
 
 
 
VIE debt to be assumed upon the occurrence of certain unlikely events
 
 
 
 
 
 
 
$ 13,000,000 
 
 
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities Palo Verde Leaseback Variable Interest Entities - Schedule of VIEs (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 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
$ 121,255 
$ 125,125 
Current maturities of long-term debt (Note 6)
383,570 
540,424 
Equity - noncontrolling interests
151,609 
145,990 
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
121,255 
125,125 
Current maturities of long-term debt (Note 6)
383,570 
540,424 
Equity - noncontrolling interests
151,609 
145,990 
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
121,000 
125,000 
Current maturities of long-term debt (Note 6)
13,000 
26,000 
Long-term debt excluding current maturities
13,000 
Equity - noncontrolling interests
$ 152,000 
$ 146,000 
Nuclear Decommissioning Trusts (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
$ 713,866,000 
$ 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
356,195,000 
446,025,000 
417,603,000 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
713,866,000 
642,007,000 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
713,866,000 
642,007,000 
 
Unrealized Gains
176,000,000 
140,000,000 
 
Unrealized Losses
(1,000,000)
(6,000,000)
 
Net payables for securities purchases
(7,000,000)
(3,000,000)
 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
Realized gains
5,000,000 
6,000,000 
7,000,000 
Realized losses
(5,000,000)
(7,000,000)
(4,000,000)
Proceeds from the sale of securities
356,195,000 
446,025,000 
417,603,000 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
713,866,000 
642,007,000 
 
ARIZONA PUBLIC SERVICE COMPANY |
Equity Securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
310,000,000 
272,000,000 
 
Unrealized Gains
159,000,000 
129,000,000 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
310,000,000 
272,000,000 
 
ARIZONA PUBLIC SERVICE COMPANY |
Fixed income securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
411,000,000 
373,000,000 
 
Unrealized Gains
17,000,000 
11,000,000 
 
Unrealized Losses
(1,000,000)
(6,000,000)
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Less than one year
14,000,000 
 
 
1 year - 5 years
116,000,000 
 
 
5 years - 10 years
122,000,000 
 
 
Greater than 10 years
159,000,000 
 
 
Total
$ 411,000,000 
$ 373,000,000 
 
Changes in Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
$ (78,053)
$ (114,008)
 
OCI (loss) before reclassifications
(6,229)
5,381 
 
Amounts reclassified from accumulated other comprehensive loss
16,141 
30,574 
 
Total other comprehensive income
9,912 
35,955 
38,155 
Ending balance
(68,141)
(78,053)
(114,008)
Derivative Instruments
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
(23,058)
(49,592)
 
OCI (loss) before reclassifications
(810)
(213)
 
Amounts reclassified from accumulated other comprehensive loss
13,483 
26,747 
 
Total other comprehensive income
12,673 
26,534 
 
Ending balance
(10,385)
(23,058)
 
Pension and other postretirement benefits
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
(54,995)
(64,416)
 
OCI (loss) before reclassifications
(5,419)
5,594 
 
Amounts reclassified from accumulated other comprehensive loss
2,658 
3,827 
 
Total other comprehensive income
(2,761)
9,421 
 
Ending balance
(57,756)
(54,995)
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
(53,372)
(89,095)
 
OCI (loss) before reclassifications
(11,224)
5,173 
 
Amounts reclassified from accumulated other comprehensive loss
16,263 
30,550 
 
Total other comprehensive income
5,039 
35,723 
36,496 
Ending balance
(48,333)
(53,372)
(89,095)
ARIZONA PUBLIC SERVICE COMPANY |
Derivative Instruments
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
(23,059)
(49,592)
 
OCI (loss) before reclassifications
(809)
(214)
 
Amounts reclassified from accumulated other comprehensive loss
13,483 
26,747 
 
Total other comprehensive income
12,674 
26,533 
 
Ending balance
(10,385)
(23,059)
 
ARIZONA PUBLIC SERVICE COMPANY |
Pension and other postretirement benefits
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
(30,313)
(39,503)
 
OCI (loss) before reclassifications
(10,415)
5,387 
 
Amounts reclassified from accumulated other comprehensive loss
2,780 
3,803 
 
Total other comprehensive income
(7,635)
9,190 
 
Ending balance
$ (37,948)
$ (30,313)
 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Statement of Comprehensive Income (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 726,450 
$ 1,172,667 
$ 906,264 
$ 686,251 
$ 699,762 
$ 1,152,392 
$ 915,822 
$ 686,652 
$ 3,491,632 
$ 3,454,628 
$ 3,301,804 
Operating expenses
 
 
 
 
 
 
 
 
2,680,390 
2,608,305 
2,450,049 
OPERATING INCOME
60,184 
421,775 
254,113 
75,170 
83,900 
415,688 
259,812 
86,923 
811,242 
846,323 
851,755 
Other
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
18,652 
11,261 
4,200 
Interest expense
 
 
 
 
 
 
 
 
200,950 
201,888 
214,616 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
 
 
 
 
 
 
 
 
644,401 
670,557 
656,310 
Income tax benefit
5,007 
134,753 
74,540 
6,405 
9,167 
131,912 
77,043 
12,469 
220,705 
230,591 
237,317 
INCOME FROM CONTINUING OPERATIONS
9,535 
248,086 
141,384 
24,691 
32,814 
234,718 
139,598 
32,836 
423,696 
439,966 
418,993 
Income (loss) from discontinued operations - net of income taxes
 
 
 
 
 
 
 
 
(5,829)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
5,410 
243,961 
132,458 
15,766 
24,260 
226,163 
131,207 
24,444 
397,595 
406,074 
381,542 
Other comprehensive income
 
 
 
 
 
 
 
 
9,912 
35,955 
38,155 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
407,507 
442,029 
419,697 
Pinnacle West
 
 
 
 
 
 
 
 
 
 
 
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
642 
799 
6,133 
Operating expenses
 
 
 
 
 
 
 
 
23,507 
24,930 
12,125 
OPERATING INCOME
 
 
 
 
 
 
 
 
(22,865)
(24,131)
(5,992)
Other
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
 
 
 
 
 
 
 
 
411,528 
420,926 
391,528 
Other expense
 
 
 
 
 
 
 
 
(3,276)
(1,999)
(2,001)
Total
 
 
 
 
 
 
 
 
408,252 
418,927 
389,527 
Interest expense
 
 
 
 
 
 
 
 
3,663 
3,226 
4,868 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
 
 
 
 
 
 
 
 
381,724 
391,570 
378,667 
Income tax benefit
 
 
 
 
 
 
 
 
(15,871)
(14,504)
(7,079)
INCOME FROM CONTINUING OPERATIONS
 
 
 
 
 
 
 
 
397,595 
406,074 
385,746 
Income (loss) from discontinued operations - net of income taxes
 
 
 
 
 
 
 
 
 
(4,204)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
397,595 
406,074 
381,542 
Other comprehensive income
 
 
 
 
 
 
 
 
9,912 
35,955 
38,155 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
$ 407,507 
$ 442,029 
$ 419,697 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT- Consolidated Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Current assets
 
 
 
 
Cash and cash equivalents
$ 7,604 
$ 9,526 
$ 26,202 
$ 33,583 
Accounts receivable
297,740 
299,904 
 
 
Income tax receivable
3,098 
135,517 
 
 
Other current assets
38,817 
39,895 
 
 
Total current assets
973,435 
1,043,609 
 
 
Investments and other assets
 
 
 
 
Other assets
54,047 
60,875 
 
 
Total investments and other assets
785,533 
726,697 
 
 
Total Assets
14,313,532 
13,508,686 
 
 
Current liabilities
 
 
 
 
Accounts payable
295,211 
284,516 
 
 
Accrued taxes (Note 4)
140,613 
130,998 
 
 
Common dividends payable
65,790 
62,528 
 
 
Other current liabilities
178,962 
158,540 
 
 
Total current liabilities
1,559,143 
1,618,644 
 
 
Long-term debt less current maturities
3,031,215 
2,796,465 
 
 
Deferred credits and other
 
 
 
 
Deferred income taxes
2,582,636 
2,351,882 
 
 
Pension and other postretirement liabilities
453,736 
513,628 
 
 
Other
188,286 
185,659 
 
 
Total deferred credits and other
5,204,072 
4,753,117 
 
 
Common stock equity
 
 
 
 
Common stock
2,512,970 
2,491,558 
 
 
Accumulated other comprehensive loss
(68,141)
(78,053)
(114,008)
 
Retained earnings
1,926,065 
1,785,273 
 
 
Total shareholders’ equity
4,367,493 
4,194,470 
 
 
Noncontrolling interests
151,609 
145,990 
 
 
Total equity
4,519,102 
4,340,460 
4,102,289 
3,930,586 
Total Liabilities and Equity
14,313,532 
13,508,686 
 
 
Pinnacle West
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
3,088 
5,798 
22,679 
12,710 
Accounts receivable
99,958 
80,108 
 
 
Current deferred income taxes
66,979 
93,185 
 
 
Income tax receivable
7,329 
1,853 
 
 
Other current assets
124 
242 
 
 
Total current assets
177,478 
181,186 
 
 
Investments and other assets
 
 
 
 
Investments in subsidiaries
4,630,570 
4,455,049 
 
 
Other assets
43,051 
13,789 
 
 
Total investments and other assets
4,673,621 
4,468,838 
 
 
Total Assets
4,851,099 
4,650,024 
 
 
Current liabilities
 
 
 
 
Accounts payable
5,250 
3,279 
 
 
Accrued taxes (Note 4)
12,220 
8,538 
 
 
Common dividends payable
65,790 
62,528 
 
 
Other current liabilities
38,992 
31,295 
 
 
Total current liabilities
122,252 
105,640 
 
 
Long-term debt less current maturities
125,000 
125,000 
 
 
Deferred credits and other
 
 
 
 
Deferred income taxes
12,055 
4,158 
 
 
Pension and other postretirement liabilities
29,228 
37,611 
 
 
Other
43,462 
37,155 
 
 
Total deferred credits and other
84,745 
78,924 
 
 
Common stock equity
 
 
 
 
Common stock
2,509,569 
2,487,250 
 
 
Accumulated other comprehensive loss
(68,141)
(78,053)
 
 
Retained earnings
1,926,065 
1,785,273 
 
 
Total shareholders’ equity
4,367,493 
4,194,470 
 
 
Noncontrolling interests
151,609 
145,990 
 
 
Total equity
4,519,102 
4,340,460 
 
 
Total Liabilities and Equity
$ 4,851,099 
$ 4,650,024 
 
 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Statements of Cash Flows (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Cash Flows from Operating Activities
 
 
 
Net Income
$ 423,696,000 
$ 439,966,000 
$ 413,164,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
496,487,000 
492,322,000 
481,262,000 
Deferred income taxes
159,023,000 
249,296,000 
187,023,000 
Accounts receivable
(52,672,000)
(44,991,000)
14,587,000 
Accounts payable
(353,000)
45,414,000 
(96,600,000)
Net cash flow provided by operating activities
1,099,627,000 
1,153,307,000 
1,171,122,000 
Cash flows from investing activities
 
 
 
Net cash flow used for investing activities
(922,668,000)
(1,009,401,000)
(872,994,000)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
731,126,000 
136,307,000 
476,081,000 
Dividends paid on common stock
(246,671,000)
(235,244,000)
(225,075,000)
Repayment of long-term debt
(652,578,000)
(122,828,000)
(654,286,000)
Common stock equity issuance
15,288,000 
17,319,000 
15,955,000 
Other
161,000 
299,000 
170,000 
Net cash flow used for financing activities
(178,881,000)
(160,582,000)
(305,509,000)
NET DECREASE IN CASH AND CASH EQUIVALENTS
(1,922,000)
(16,676,000)
(7,381,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
9,526,000 
26,202,000 
33,583,000 
CASH AND CASH EQUIVALENTS AT END OF YEAR
7,604,000 
9,526,000 
26,202,000 
Pinnacle West
 
 
 
Cash Flows from Operating Activities
 
 
 
Net Income
397,595,000 
406,074,000 
381,542,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Equity in earnings of subsidiaries - net
(411,528,000)
(420,926,000)
(391,528,000)
Depreciation and amortization
94,000 
95,000 
94,000 
Deferred income taxes
4,406,000 
(28,806,000)
(15,135,000)
Accounts receivable
(22,945,000)
21,671,000 
28,763,000 
Accounts payable
2,017,000 
(2,449,000)
879,000 
Accrued taxes and income tax receivable - net
(1,795,000)
1,402,000 
(3,103,000)
Dividends received from subsidiaries
253,600,000 
242,100,000 
222,200,000 
Other
18,432,000 
(15,065,000)
(4,589,000)
Net cash flow provided by operating activities
239,876,000 
204,096,000 
219,123,000 
Cash flows from investing activities
 
 
 
Investments in subsidiaries
(10,236,000)
(3,400,000)
Repayments of loans from subsidiaries
322,000 
2,149,000 
996,000 
Advances of loans to subsidiaries
(1,450,000)
(2,099,000)
(1,200,000)
Net cash flow used for investing activities
(11,364,000)
(3,350,000)
(204,000)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
125,000,000 
125,000,000 
Dividends paid on common stock
(246,671,000)
(235,244,000)
(225,075,000)
Repayment of long-term debt
(125,000,000)
(125,000,000)
Common stock equity issuance
15,288,000 
17,319,000 
15,955,000 
Other
161,000 
298,000 
170,000 
Net cash flow used for financing activities
(231,222,000)
(217,627,000)
(208,950,000)
NET DECREASE IN CASH AND CASH EQUIVALENTS
(2,710,000)
(16,881,000)
9,969,000 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
5,798,000 
22,679,000 
12,710,000 
CASH AND CASH EQUIVALENTS AT END OF YEAR
$ 3,088,000 
$ 5,798,000 
$ 22,679,000 
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) (Reserve for uncollectibles., USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
$ 3,203 
$ 3,340 
$ 3,748 
Additions, Charged to cost and expenses
3,942 
4,923 
5,290 
Additions, Charged to other accounts
Deductions
4,051 
5,060 
5,698 
Balance at end of period
3,094 
3,203 
3,340 
Pinnacle West
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
3,203 
3,340 
3,748 
Additions, Charged to cost and expenses
3,942 
4,923 
5,290 
Additions, Charged to other accounts
Deductions
4,051 
5,060 
5,698 
Balance at end of period
$ 3,094 
$ 3,203 
$ 3,340