PINNACLE WEST CAPITAL CORP, 10-K filed on 2/19/2016
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2015
Feb. 12, 2016
Jun. 30, 2015
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, 2015 
 
 
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
 
 
$ 6,271,269,171 
Entity Common Stock, Shares Outstanding
 
111,004,916 
 
Document Fiscal Year Focus
2015 
 
 
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, 2015 
 
 
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
2015 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
OPERATING REVENUES
$ 3,495,443 
$ 3,491,632 
$ 3,454,628 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,101,298 
1,179,829 
1,095,709 
Operations and maintenance
868,377 
908,025 
924,727 
Depreciation and amortization
494,422 
417,358 
415,708 
Taxes other than income taxes
171,812 
172,295 
164,167 
Other expenses
4,932 
2,883 
7,994 
Total
2,640,841 
2,680,390 
2,608,305 
OPERATING INCOME
854,602 
811,242 
846,323 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
35,215 
30,790 
25,581 
Other income (Note 17)
621 
9,608 
1,704 
Other expense (Note 17)
(17,823)
(21,746)
(16,024)
Total
18,013 
18,652 
11,261 
INTEREST EXPENSE
 
 
 
Interest charges
194,964 
200,950 
201,888 
Allowance for borrowed funds used during construction (Note 1)
(16,259)
(15,457)
(14,861)
Total
178,705 
185,493 
187,027 
INCOME BEFORE INCOME TAXES
693,910 
644,401 
670,557 
INCOME TAXES (Note 4)
237,720 
220,705 
230,591 
NET INCOME
456,190 
423,696 
439,966 
Less: Net income attributable to noncontrolling interests (Note 18)
18,933 
26,101 
33,892 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
437,257 
397,595 
406,074 
Weighted Average common shares outstanding — basic (in shares)
111,026 
110,626 
109,984 
Weighted Average common shares outstanding — diluted (in shares)
111,552 
111,178 
110,806 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.94 
$ 3.59 
$ 3.69 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 3.92 
$ 3.58 
$ 3.66 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
ELECTRIC OPERATING REVENUES
3,492,357 
3,488,946 
3,451,251 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,101,298 
1,179,829 
1,095,709 
Operations and maintenance
853,135 
882,442 
897,824 
Depreciation and amortization
494,298 
417,264 
415,612 
Taxes other than income taxes
171,499 
171,583 
163,377 
Income taxes (Note 4)
260,143 
245,036 
256,864 
Total
2,880,373 
2,896,154 
2,829,386 
OPERATING INCOME
611,984 
592,792 
621,865 
OTHER INCOME (DEDUCTIONS)
 
 
 
Income taxes (Note 4)
14,302 
7,676 
11,769 
Allowance for equity funds used during construction (Note 1)
35,215 
30,790 
25,581 
Other income (Note 17)
2,834 
11,295 
3,896 
Other expense (Note 17)
(19,019)
(13,403)
(20,449)
Total
33,332 
36,358 
20,797 
INTEREST EXPENSE
 
 
 
Interest on long-term debt
180,123 
186,323 
188,011 
Interest on short-term borrowings
7,376 
6,796 
6,605 
Debt discount, premium and expense
4,793 
4,168 
4,046 
Allowance for borrowed funds used during construction (Note 1)
(16,183)
(15,457)
(14,861)
Total
176,109 
181,830 
183,801 
INCOME TAXES (Note 4)
245,841 
237,360 
245,095 
NET INCOME
469,207 
447,320 
458,861 
Less: Net income attributable to noncontrolling interests (Note 18)
18,933 
26,101 
33,892 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 450,274 
$ 421,219 
$ 424,969 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
NET INCOME
$ 456,190 
$ 423,696 
$ 439,966 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(957)
(810)
(213)
Reclassification of net realized loss, net of tax benefit
4,187 
13,483 
26,747 
Pension and other postretirement benefits activity, net of tax (expense) benefit
20,163 
(2,761)
9,421 
Total other comprehensive income
23,393 
9,912 
35,955 
COMPREHENSIVE INCOME
479,583 
433,608 
475,921 
Less: Comprehensive income attributable to noncontrolling interests
18,933 
26,101 
33,892 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
460,650 
407,507 
442,029 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
NET INCOME
469,207 
447,320 
458,861 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(957)
(809)
(214)
Reclassification of net realized loss, net of tax benefit
4,187 
13,483 
26,747 
Pension and other postretirement benefits activity, net of tax (expense) benefit
18,006 
(7,635)
9,190 
Total other comprehensive income
21,236 
5,039 
35,723 
COMPREHENSIVE INCOME
490,443 
452,359 
494,584 
Less: Comprehensive income attributable to noncontrolling interests
18,933 
26,101 
33,892 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 471,510 
$ 426,258 
$ 460,692 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Net unrealized loss, tax benefit (expense)
$ (342)
$ (438)
$ 140 
Reclassification of net realized loss, tax benefit
1,801 
7,932 
17,472 
Pension and other postretirement benefits activity, tax (expense) benefit
(13,302)
1,307 
(6,156)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net unrealized loss, tax benefit (expense)
(342)
(438)
140 
Reclassification of net realized loss, tax benefit
1,801 
7,932 
17,472 
Pension and other postretirement benefits activity, tax (expense) benefit
$ (11,776)
$ 4,655 
$ (6,003)
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 39,488 
$ 7,604 
Customer and other receivables
274,691 
297,740 
Accrued unbilled revenues
96,240 
100,533 
Allowance for doubtful accounts
(3,125)
(3,094)
Materials and supplies (at average cost)
234,234 
218,889 
Fossil fuel (at average cost)
45,697 
37,097 
Deferred income taxes (Note 4)
0 
122,232 
Income tax receivable (Note 4)
589 
3,098 
Assets from risk management activities (Note 16)
15,905 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
0 
6,926 
Other regulatory assets (Note 3)
149,555 
129,808 
Other current assets
37,242 
38,817 
Total current assets
890,516 
973,435 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
12,106 
17,620 
Nuclear decommissioning trust (Notes 13 and 19)
735,196 
713,866 
Other assets
52,518 
54,047 
Total investments and other assets
799,820 
785,533 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
16,222,232 
15,543,063 
Accumulated depreciation and amortization
(5,594,094)
(5,397,751)
Net
10,628,138 
10,145,312 
Construction work in progress
816,307 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation of $233,665 and $229,795 (Note 18)
117,385 
121,255 
Intangible assets, net of accumulated amortization of $546,038 and $489,538
123,975 
119,755 
Nuclear fuel, net of accumulated amortization of $146,228 and $143,554
123,139 
125,201 
Total property, plant and equipment
11,808,944 
11,194,330 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,214,146 
1,054,087 
Assets for other postretirement benefits (Note 7)
185,997 
152,290 
Other
128,835 
129,215 
Total deferred debits
1,528,978 
1,335,592 
Total Assets
15,028,258 
14,288,890 
CURRENT LIABILITIES
 
 
Accounts payable
297,480 
295,211 
Accrued taxes (Note 4)
138,600 
140,613 
Accrued interest
56,305 
52,603 
Common dividends payable
69,363 
65,790 
Short-term borrowings (Note 5)
0 
147,400 
Current maturities of long-term debt (Note 6)
357,580 
383,570 
Customer deposits
73,073 
72,307 
Liabilities from risk management activities (Note 16)
77,716 
59,676 
Liabilities for asset retirements (Note 11)
28,573 
32,462 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
0 
Other regulatory liabilities (Note 3)
136,078 
130,549 
Other current liabilities
197,861 
178,962 
Total current liabilities
1,442,317 
1,559,143 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
3,462,391 
3,006,573 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,723,425 
2,582,636 
Regulatory liabilities (Notes 1, 3, 4 and 7)
994,152 
1,051,196 
Liabilities for asset retirements (Note 11)
415,003 
358,288 
Liabilities for pension benefits (Note 7)
480,998 
453,736 
Liabilities from risk management activities (Note 16)
89,973 
50,602 
Customer advances
115,609 
123,052 
Coal mine reclamation
201,984 
198,292 
Deferred investment tax credit
187,080 
178,607 
Unrecognized tax benefits (Note 4)
9,524 
19,377 
Other
186,345 
188,286 
Total deferred credits and other
5,404,093 
5,204,072 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,095,402 and 110,649,762 issued at respective dates
2,541,668 
2,512,970 
Treasury stock at cost; 115,030 shares at end of 2015 and 78,400 shares at end of 2014
(5,806)
(3,401)
Total common stock
2,535,862 
2,509,569 
Retained earnings
2,092,803 
1,926,065 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(37,593)
(57,756)
Derivative instruments (Note 16)
(7,155)
(10,385)
Total accumulated other comprehensive loss
(44,748)
(68,141)
Total shareholders’ equity
4,583,917 
4,367,493 
Noncontrolling interests (Note 18)
135,540 
151,609 
Total equity
4,719,457 
4,519,102 
Total Liabilities and Equity
15,028,258 
14,288,890 
ARIZONA PUBLIC SERVICE COMPANY
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
22,056 
4,515 
Customer and other receivables
274,428 
297,712 
Accrued unbilled revenues
96,240 
100,533 
Allowance for doubtful accounts
(3,125)
(3,094)
Materials and supplies (at average cost)
234,234 
218,889 
Fossil fuel (at average cost)
45,697 
37,097 
Deferred income taxes (Note 4)
0 
55,253 
Assets from risk management activities (Note 16)
15,905 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
0 
6,926 
Other regulatory assets (Note 3)
149,555 
129,808 
Other current assets
35,765 
38,693 
Total current assets
870,755 
900,117 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
12,106 
17,620 
Nuclear decommissioning trust (Notes 13 and 19)
735,196 
713,866 
Other assets
34,455 
33,362 
Total investments and other assets
781,757 
764,848 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
16,218,724 
15,539,811 
Accumulated depreciation and amortization
(5,590,937)
(5,394,650)
Net
10,627,787 
10,145,161 
Construction work in progress
812,845 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation of $233,665 and $229,795 (Note 18)
117,385 
121,255 
Intangible assets, net of accumulated amortization of $546,038 and $489,538
123,820 
119,600 
Nuclear fuel, net of accumulated amortization of $146,228 and $143,554
123,139 
125,201 
Total property, plant and equipment
11,804,976 
11,194,024 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,214,146 
1,054,087 
Assets for other postretirement benefits (Note 7)
182,625 
149,260 
Other
127,923 
128,026 
Total deferred debits
1,524,694 
1,331,373 
Total Assets
14,982,182 
14,190,362 
CURRENT LIABILITIES
 
 
Accounts payable
291,574 
289,930 
Accrued taxes (Note 4)
144,488 
131,110 
Accrued interest
56,003 
52,358 
Common dividends payable
69,400 
65,800 
Short-term borrowings (Note 5)
0 
147,400 
Current maturities of long-term debt (Note 6)
357,580 
383,570 
Customer deposits
73,073 
72,307 
Liabilities from risk management activities (Note 16)
77,716 
59,676 
Liabilities for asset retirements (Note 11)
28,573 
32,000 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
0 
Other regulatory liabilities (Note 3)
136,078 
130,549 
Other current liabilities
180,535 
167,302 
Total current liabilities
1,424,708 
1,532,464 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,764,489 
2,571,365 
Regulatory liabilities (Notes 1, 3, 4 and 7)
994,152 
1,051,196 
Liabilities for asset retirements (Note 11)
415,003 
358,288 
Liabilities for pension benefits (Note 7)
459,065 
424,508 
Liabilities from risk management activities (Note 16)
89,973 
50,602 
Customer advances
115,609 
123,052 
Coal mine reclamation
201,984 
198,292 
Deferred investment tax credit
187,080 
178,607 
Unrecognized tax benefits (Note 4)
35,251 
45,740 
Other
142,683 
144,823 
Total deferred credits and other
5,405,289 
5,146,473 
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
2,148,493 
1,968,718 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(19,942)
(37,948)
Derivative instruments (Note 16)
(7,155)
(10,385)
Total accumulated other comprehensive loss
(27,097)
(48,333)
Total shareholders’ equity
4,679,254 
4,478,243 
Noncontrolling interests (Note 18)
135,540 
151,609 
Total equity
4,814,794 
4,629,852 
Long-term debt less current maturities (Note 6)
3,337,391 
2,881,573 
Total capitalization
8,152,185 
7,511,425 
Total Liabilities and Equity
$ 14,982,182 
$ 14,190,362 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 233,665 
$ 229,795 
Accumulated amortization on intangible assets
546,038 
489,538 
Accumulated amortization on nuclear fuel
146,228 
143,554 
EQUITY
 
 
Common stock, par value
$ 0 
$ 0 
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
111,095,402 
110,649,762 
Treasury stock at cost, shares
115,030 
78,400 
ARIZONA PUBLIC SERVICE COMPANY
 
 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
233,665 
229,795 
Accumulated amortization on intangible assets
546,038 
489,538 
Accumulated amortization on nuclear fuel
$ 146,228 
$ 143,554 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$ 456,190 
$ 423,696 
$ 439,966 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
571,664 
496,487 
492,322 
Deferred fuel and purchased power
14,997 
(26,927)
21,678 
Deferred fuel and purchased power amortization
1,617 
40,757 
31,190 
Allowance for equity funds used during construction
(35,215)
(30,790)
(25,581)
Deferred income taxes
236,819 
159,023 
249,296 
Deferred investment tax credit
8,473 
26,246 
52,542 
Change in derivative instruments fair value
(381)
339 
534 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(22,219)
(52,672)
(44,991)
Accrued unbilled revenues
4,293 
(3,737)
(1,951)
Materials, supplies and fossil fuel
(23,945)
3,724 
(11,878)
Income tax receivable
2,509 
132,419 
(133,094)
Other current assets
3,145 
4,384 
(17,913)
Accounts payable
(34,266)
(353)
45,414 
Accrued taxes
(2,013)
9,615 
6,059 
Other current liabilities
603 
17,892 
(7,513)
Change in margin and collateral accounts — assets
(324)
(343)
993 
Change in margin and collateral accounts — liabilities
22,776 
(24,975)
12,355 
Change in long-term income tax receivable
0 
0 
137,270 
Change in unrecognized tax benefits
(10,328)
2,778 
(91,425)
Change in long-term regulatory liabilities
(20,535)
59,618 
64,473 
Change in other long-term assets
2,426 
(56,561)
(42,389)
Change in other long-term liabilities
(81,959)
(80,993)
(24,050)
Net cash flow provided by operating activities
1,094,327 
1,099,627 
1,153,307 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,076,087)
(910,634)
(1,016,322)
Contributions in aid of construction
46,546 
20,325 
41,090 
Allowance for borrowed funds used during construction
(16,259)
(15,457)
(14,861)
Proceeds from nuclear decommissioning trust sales
478,813 
356,195 
446,025 
Investment in nuclear decommissioning trust
(496,062)
(373,444)
(463,274)
Other
(3,184)
347 
(2,059)
Net cash flow used for investing activities
(1,066,233)
(922,668)
(1,009,401)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
842,415 
731,126 
136,307 
Repayment of long-term debt
(415,570)
(652,578)
(122,828)
Short-term borrowings and payments — net
(147,400)
(5,725)
60,950 
Dividends paid on common stock
(260,027)
(246,671)
(235,244)
Common stock equity issuance - net of purchases
19,373 
15,288 
17,319 
Distributions to noncontrolling interests
(35,002)
(20,482)
(17,385)
Other
1 
161 
299 
Net cash flow provided by (used for) financing activities
3,790 
(178,881)
(160,582)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
31,884 
(1,922)
(16,676)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
7,604 
9,526 
26,202 
CASH AND CASH EQUIVALENTS AT END OF YEAR
39,488 
7,604 
9,526 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
6,550 
(102,154)
18,537 
Interest, net of amounts capitalized
170,209 
177,074 
184,010 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
83,798 
44,712 
33,184 
Dividends declared but not paid
69,363 
65,790 
62,528 
Liabilities assumed related to acquisition of SCE’s Four Corners’ interest
0 
0 
145,609 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
469,207 
447,320 
458,861 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
571,540 
496,393 
492,226 
Deferred fuel and purchased power
14,997 
(26,927)
21,678 
Deferred fuel and purchased power amortization
1,617 
40,757 
31,190 
Allowance for equity funds used during construction
(35,215)
(30,790)
(25,581)
Deferred income taxes
223,069 
155,401 
278,101 
Deferred investment tax credit
8,473 
26,246 
52,542 
Change in derivative instruments fair value
(381)
339 
534 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(21,040)
(52,466)
(46,552)
Accrued unbilled revenues
4,293 
(3,737)
(1,951)
Materials, supplies and fossil fuel
(23,945)
3,724 
(11,878)
Income tax receivable
0 
135,179 
(134,590)
Other current assets
4,498 
3,766 
(17,112)
Accounts payable
(34,891)
(2,355)
47,870 
Accrued taxes
13,378 
8,650 
5,760 
Other current liabilities
(3,718)
33,970 
(9,005)
Change in margin and collateral accounts — assets
(324)
(343)
993 
Change in margin and collateral accounts — liabilities
22,776 
(24,975)
12,355 
Change in long-term income tax receivable
0 
0 
137,665 
Change in unrecognized tax benefits
(10,328)
2,778 
(91,244)
Change in long-term regulatory liabilities
(20,535)
59,618 
64,473 
Change in other long-term assets
(813)
(62,739)
(46,675)
Change in other long-term liabilities
(82,628)
(85,642)
(24,969)
Net cash flow provided by operating activities
1,100,030 
1,124,167 
1,194,691 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,072,053)
(910,084)
(1,016,322)
Contributions in aid of construction
46,546 
20,325 
41,090 
Allowance for borrowed funds used during construction
(16,183)
(15,457)
(14,861)
Proceeds from nuclear decommissioning trust sales
478,813 
356,195 
446,025 
Investment in nuclear decommissioning trust
(496,062)
(373,444)
(463,274)
Other
(1,093)
347 
(2,067)
Net cash flow used for investing activities
(1,060,032)
(922,118)
(1,009,409)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
842,415 
606,126 
136,307 
Repayment of long-term debt
(415,570)
(527,578)
(122,828)
Short-term borrowings and payments — net
(147,400)
(5,725)
60,950 
Dividends paid on common stock
(266,900)
(253,600)
(242,100)
Distributions to noncontrolling interests
(35,002)
(20,482)
(17,385)
Net cash flow provided by (used for) financing activities
(22,457)
(201,259)
(185,056)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
17,541 
790 
226 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
4,515 
3,725 
3,499 
CASH AND CASH EQUIVALENTS AT END OF YEAR
22,056 
4,515 
3,725 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
14,831 
(86,054)
7,524 
Interest, net of amounts capitalized
167,670 
173,436 
180,757 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
83,798 
44,712 
33,184 
Dividends declared but not paid
69,400 
65,800 
62,500 
Liabilities assumed related to acquisition of SCE’s Four Corners’ interest
$ 0 
$ 0 
$ 145,609 
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
Beginning 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 
Beginning 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 on 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)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
9,630 
 
9,630 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
170,538 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(17,385)
 
 
 
 
(17,385)
(17,385)
 
 
 
 
(17,385)
Ending 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 
Ending Balance (in shares) at Dec. 31, 2013
 
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 on common stock
(256,803)
 
 
(256,803)
 
 
(256,900)
 
 
(256,900)
 
 
Other
 
 
 
 
 
 
1 
 
 
1 
 
 
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)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
8,800 
 
8,800 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
160,290 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(20,482)
 
 
 
 
(20,482)
(20,482)
 
 
 
 
(20,482)
Ending 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 
Ending Balance (in shares) at Dec. 31, 2014
110,649,762 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
456,190 
 
 
437,257 
 
18,933 
469,207 
 
 
450,274 
 
18,933 
Other comprehensive income
23,393 
 
 
 
23,393 
 
21,236 
 
 
 
21,236 
 
Dividends on common stock
(270,519)
 
 
(270,519)
 
 
(270,500)
 
 
(270,500)
 
 
Other
 
 
 
 
 
 
1 
 
 
1 
 
 
Issuance of common stock
28,698 
28,698 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
445,640 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(10,136)
 
(10,136)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(154,751)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
7,731 
 
7,731 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
118,121 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(35,002)
 
 
 
 
(35,002)
(35,002)
 
 
 
 
(35,002)
Ending Balance at Dec. 31, 2015
$ 4,719,457 
$ 2,541,668 
$ (5,806)
$ 2,092,803 
$ (44,748)
$ 135,540 
$ 4,814,794 
$ 178,162 
$ 2,379,696 
$ 2,148,493 
$ (27,097)
$ 135,540 
Ending Balance (in shares) at Dec. 31, 2015
111,095,402 
111,095,402 
115,030 
 
 
 
 
71,264,947 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.44 
$ 2.33 
$ 2.23 
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, and BCE. 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 subsidiary that was 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.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado and BCE. 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.
 
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.

Pinnacle West’s property, plant and equipment included in the December 31, 2015 and 2014 consolidated balance sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2015
 
2014
Generation
$
7,336,902

 
$
7,158,729

Transmission
2,494,744

 
2,247,309

Distribution
5,543,561

 
5,339,322

General plant
847,025

 
797,703

Plant in service and held for future use
16,222,232

 
15,543,063

Accumulated depreciation and amortization
(5,594,094
)
 
(5,397,751
)
Net
10,628,138

 
10,145,312

Construction work in progress
816,307

 
682,807

Palo Verde sale leaseback, net of accumulated depreciation
117,385

 
121,255

Intangible assets, net of accumulated amortization
123,975

 
119,755

Nuclear fuel, net of accumulated amortization
123,139

 
125,201

Total property, plant and equipment
$
11,808,944

 
$
11,194,330



Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

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, 2015 were as follows:
 
•Fossil plant — 19 years;
•Nuclear plant — 28 years;
•Other generation — 25 years;
•Transmission — 39 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 are now being amortized on the depreciation line of the Consolidated Statements of Income.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $430 million in 2015, $396 million in 2014, and $400 million in 2013. For the years 2013 through 2015, the depreciation rates ranged from a low of 0.30% to a high of 12.37%.  The weighted-average depreciation rate was 2.74% in 2015, 2.77% in 2014, and 3.00% in 2013.
 
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 8.02% for 2015, 8.47% for 2014, and 8.56% for 2013.  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 Postretirement 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 May 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,
 
2015
 
2014
 
2013
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
6,550

 
$
(102,154
)
 
$
18,537

Interest, net of amounts capitalized
170,209

 
177,074

 
184,010

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
83,798

 
$
44,712

 
$
33,184

Dividends declared but not paid
69,363

 
65,790

 
62,528

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 $58 million in 2015, $53 million in 2014, and $53 million in 2013.  Estimated amortization expense on existing intangible assets over the next five years is $48 million in 2016, $36 million in 2017, $18 million in 2018, $9 million in 2019, and $3 million in 2020.  At December 31, 2015, the weighted-average remaining amortization period for intangible assets was 5 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, 2015, 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
 
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. The new revenue standard will be effective for us on January 1, 2018. The guidance may be adopted using a 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.

In February 2015, new consolidation accounting guidance was issued that amends many aspects of the guidance relating to the analysis and consolidation of variable interest entities. The new guidance  is effective for us, and will be adopted, during the first quarter of 2016; and may be adopted using either a full retrospective or modified retrospective approach. We do not expect the adoption of this guidance to have a material impact on our financial statements.

In January 2016, new guidance was issued relating to the recognition and measurement of financial instruments. The amended guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.
During the fourth quarter of 2015 we elected to early adopt the following accounting standard updates:
 
•
Balance sheet presentation of deferred income taxes. See Note 4.

•
Balance sheet presentation of debt issuance costs: Adopted on a retrospective basis, the new guidance requires debt issuance costs to be presented on the balance sheets as a direct reduction to the related debt liabilities. Prior to the adoption of this guidance we were required to present debt issuance costs as an asset on the balance sheets. As a result of adopting this guidance, our December 31, 2015 Consolidated Balance Sheet includes $28 million of debt issuance costs as a reduction to our long-term debt. Our December 31, 2014 Consolidated Balance Sheet presents $25 million of debt issuance costs as a reduction to long-term debt; this amount was previously presented as a component of non-current other deferred debits. The adoption of this guidance did not impact our results of operations or cash flows. Debt issuance costs continue to be amortized as interest expense. See Note 6.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filings with the Arizona Corporation Commission

Upcoming Rate Case Filing

On January 29, 2016, APS filed a NOI informing the ACC that APS intends to submit a rate case application in June 2016 using an adjusted test year ending December 31, 2015.  The NOI provides an overview of the key issues APS expects to address in its formal request such as rate design changes (residential, commercial and industrial), a decoupling mechanism, permission to defer for potential future recovery costs associated with the Company’s Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items.  In its rate application, APS will request that its proposed pricing changes take effect in July 2017. APS is still developing the exact amount of the request.

Prior Rate Case Filing
 
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.
 
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;
•
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.
 
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 went into effect on April 21, 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, called the "Solar Partner 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 requested budget to approximately $152 million.

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.
 
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 from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.

On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS’s resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.
 
Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards 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 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 rulemaking 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 (liability) for 2015 and 2014 (dollars in thousands):
 
 
Year Ended December 31,
 
2015
 
2014
Beginning balance
$
6,926

 
$
20,755

Deferred fuel and purchased power costs - current period
(14,997
)
 
26,927

Amounts charged to customers
(1,617
)
 
(40,756
)
Ending balance
$
(9,688
)
 
$
6,926


 
The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh.  On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.
 
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 Charges 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.

Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 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, 2015.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future.
 
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.
 
APS files for a LFCR adjustment every January.  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, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016.

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.  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 electric grid.   The fixed charge does not increase APS's revenue because it is credited to the LFCR.

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 electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 

                On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing has been scheduled to commence in April 2016.  APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS has also requested intervention in the upcoming Tucson Electric Power Company rate case. The outcomes of these proceedings will not directly impact our financial position.

Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB")

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument is set for March 22, 2016.   If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter.

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 $70 million as of December 31, 2015 and is being amortized in rates over a total of 10 years.  On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter will be resolved.

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.  On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS has established a regulatory asset of $12 million at December 31, 2015 in connection with the expiration of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates.

Cholla
On September 11, 2014, APS announced that it would close Cholla Unit 2 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. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and plans to seek recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its next retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($122 million as of December 31, 2015), 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 thousands):
 
Amortization Through
 
December 31, 2015
 
December 31, 2014
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
619,223

 
$
—

 
$
485,037

Retired power plant costs
2033
 
9,913

 
127,518

 
9,913

 
136,182

Income taxes - AFUDC equity
2045
 
5,495

 
133,712

 
4,813

 
118,396

Deferred fuel and purchased power — mark-to-market (Note 16)
2018
 
71,852

 
69,697

 
51,209

 
46,233

Four Corners cost deferral
2024
 
6,689

 
63,582

 
6,689

 
70,565

Income taxes — investment tax credit basis adjustment
2045
 
1,766

 
48,462

 
1,716

 
46,200

Lost fixed cost recovery
2016
 
45,507

 
—

 
37,612

 
—

Palo Verde VIEs (Note 18)
2046
 
—

 
18,143

 
—

 
34,440

Deferred compensation
2036
 
—

 
34,751

 
—

 
34,162

Deferred property taxes
(d)
 
—

 
50,453

 
—

 
30,283

Loss on reacquired debt
2034
 
1,515

 
16,375

 
1,435

 
16,410

Tax expense of Medicare subsidy
2024
 
1,520

 
12,163

 
1,528

 
13,756

Transmission vegetation management
2016
 
4,543

 
—

 
9,086

 
4,543

Mead-Phoenix transmission line CIAC
2050
 
332

 
11,040

 
332

 
11,372

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

 
—

 
6,926

 
—

Coal reclamation
2026
 
418

 
6,085

 
418

 
6,503

Pension and other postretirement benefits deferral
2015
 
—

 
—

 
4,238

 
—

Other
Various
 
5

 
2,942

 
819

 
5

Total regulatory assets (e)
 
 
$
149,555

 
$
1,214,146

 
$
136,734

 
$
1,054,087


(a)
This asset represents the future recovery of pension 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 thousands):
 
Amortization Through
 
December 31, 2015
 
December 31, 2014
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
277,554

 
$
—

 
$
295,546

Removal costs
(a)
 
39,746

 
240,367

 
31,033

 
272,825

Other postretirement benefits
(d)
 
34,100

 
179,521

 
32,317

 
198,599

Income taxes — deferred investment tax credit
2045
 
3,604

 
97,175

 
3,505

 
92,727

Income taxes - change in rates
2045
 
1,113

 
72,454

 
371

 
72,423

Spent nuclear fuel
2047
 
3,051

 
67,437

 
4,396

 
65,594

Renewable energy standard (b)
2017
 
43,773

 
4,365

 
24,596

 
22,677

Demand side management (b)
2017
 
6,079

 
19,115

 
31,335

 
—

Sundance maintenance
2030
 
—

 
13,678

 
—

 
12,069

Deferred fuel and purchased power (b) (c)
2016
 
9,688

 
—

 
—

 
—

Deferred gains on utility property
2019
 
2,062

 
6,001

 
2,062

 
8,001

Four Corners coal reclamation
2031
 
—

 
8,920

 
—

 
1,200

Other
Various
 
2,550

 
7,565

 
934

 
9,535

Total regulatory liabilities
 
 
$
145,766

 
$
994,152

 
$
130,549

 
$
1,051,196


(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)
Subject to a carrying charge.
(d)
See Note 7.
Income Taxes
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, investment tax credit basis adjustment and tax expense of Medicare subsidy.  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.
 
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 Pinnacle West Consolidated and APS 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):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Total unrecognized tax benefits, January 1
$
44,775

 
$
41,997

 
$
133,422

 
$
44,775

 
$
41,997

 
$
133,241

Additions for tax positions of the current year
2,175

 
4,309

 
3,516

 
2,175

 
4,309

 
3,516

Additions for tax positions of prior years
—

 
751

 
13,158

 
—

 
751

 
13,158

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(10,244
)
 
(2,282
)
 
(108,099
)
 
(10,244
)
 
(2,282
)
 
(107,918
)
Settlements with taxing authorities
—

 
—

 
—

 
—

 
—

 
—

Lapses of applicable statute of limitations
(2,259
)
 
—

 
—

 
(2,259
)
 
—

 
—

Total unrecognized tax benefits, December 31
$
34,447

 
$
44,775

 
$
41,997

 
$
34,447

 
$
44,775

 
$
41,997



During the year ended December 31, 2013, Internal Revenue Service ("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, materially offset by an increase in deferred tax liabilities, resulted in a cash refund that was received in the first quarter of 2014.

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Tax positions, that if recognized, would decrease our effective tax rate
$
9,523

 
$
11,207

 
$
9,827

 
$
9,523

 
$
11,207

 
$
9,827


 
As of the balance sheet date, the tax year ended December 31, 2012 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 2011.
 
We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.  The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Unrecognized tax benefit interest expense/(benefit) recognized
$
(161
)
 
$
752

 
$
(3,716
)
 
$
(161
)
 
$
752

 
$
(3,716
)

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Unrecognized tax benefit interest accrued
$
804

 
$
965

 
$
213

 
$
804

 
$
965

 
$
213



Additionally, as of December 31, 2015, 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):
 
Pinnacle West Consolidated
 
APS Consolidated
 
Year Ended December 31,
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Current:
 

 
 

 
 

 
 
 
 
 
 
Federal
$
(12,335
)
 
$
25,054

 
$
(81,784
)
 
$
6,485

 
$
40,115

 
$
(97,531
)
State
4,763

 
10,382

 
10,537

 
7,813

 
15,598

 
11,983

Total current
(7,572
)
 
35,436

 
(71,247
)
 
14,298

 
55,713

 
(85,548
)
Deferred:
 

 
 

 
 

 
 

 
 

 
 

Federal
221,505

 
167,365

 
279,973

 
208,326

 
165,027

 
305,389

State
23,787

 
17,904

 
21,865

 
23,217

 
16,620

 
25,254

Total deferred
245,292

 
185,269

 
301,838

 
231,543

 
181,647

 
330,643

Income tax expense
$
237,720

 
$
220,705

 
$
230,591

 
$
245,841

 
$
237,360

 
$
245,095



On the APS Consolidated Statements of Income, federal and state income taxes are allocated between operating income and other income.

The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
 
 
Pinnacle West Consolidated
 
APS Consolidated
 
Year Ended December 31,
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Federal income tax expense at 35% statutory rate
$
242,869

 
$
225,540

 
$
234,695

 
$
250,267

 
$
239,638

 
$
246,384

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

 
 

 
 

 
 

State income tax net of federal income tax benefit
18,265

 
18,149

 
21,387

 
20,433

 
21,148

 
23,970

Credits and favorable adjustments related to prior years resolved in current year
(2,169
)
 
—

 
(3,356
)
 
(1,892
)
 
—

 
(3,231
)
Medicare Subsidy Part-D
837

 
830

 
823

 
837

 
830

 
823

Allowance for equity funds used during construction (see Note 1)
(9,711
)
 
(8,523
)
 
(6,997
)
 
(9,711
)
 
(8,523
)
 
(6,997
)
Palo Verde VIE noncontrolling interest (see Note 18)
(6,626
)
 
(9,135
)
 
(11,862
)
 
(6,626
)
 
(9,135
)
 
(11,862
)
Investment tax credit amortization
(5,527
)
 
(4,928
)
 
(3,548
)
 
(5,527
)
 
(4,928
)
 
(3,548
)
Other
(218
)
 
(1,228
)
 
(551
)
 
(1,940
)
 
(1,670
)
 
(444
)
Income tax expense
$
237,720

 
$
220,705

 
$
230,591

 
$
245,841

 
$
237,360

 
$
245,095


 
During the fourth quarter of 2015, we prospectively adopted guidance requiring deferred income tax assets and liabilities to be presented as non-current on the balance sheet and eliminating the requirement to present a current portion. As a result of this guidance all deferred income tax assets and liabilities are presented as net non-current deferred income tax liabilities on the Consolidated Balance Sheet as of December 31, 2015. Prior periods have not been restated.

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
December 31,
 
December 31,
 
2015
 
2014
 
2015
 
2014
Current asset
$
—

 
$
122,232

 
$
—

 
$
55,253

Long-term liability
(2,723,425
)
 
(2,582,636
)
 
(2,764,489
)
 
(2,571,365
)
Deferred income taxes — net
$
(2,723,425
)
 
$
(2,460,404
)
 
$
(2,764,489
)
 
$
(2,516,112
)


    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, 2015, APS has recorded a regulatory liability of $75 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, 2015, 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):
 
 
Pinnacle West Consolidated
 
APS Consolidated
 
December 31,
 
December 31,
 
2015
 
2014
 
2015
 
2014
DEFERRED TAX ASSETS
 

 
 

 
 
 
 
Risk management activities
$
70,498

 
$
57,505

 
$
70,498

 
$
57,505

Regulatory liabilities:
 

 
 

 
 

 
 
Asset retirement obligation and removal costs
216,765

 
229,772

 
216,765

 
229,772

Unamortized investment tax credits
100,779

 
96,232

 
100,779

 
96,232

Other postretirement benefits
83,034

 
90,496

 
83,034

 
90,496

Other
60,707

 
60,409

 
60,707

 
60,409

Pension liabilities
191,028

 
205,227

 
181,787

 
194,541

Renewable energy incentives
60,956

 
65,169

 
60,956

 
65,169

Credit and loss carryforwards
59,557

 
68,347

 
—

 
—

Other
149,033

 
138,729

 
176,016

 
161,379

Total deferred tax assets
992,357

 
1,011,886

 
950,542

 
955,503

DEFERRED TAX LIABILITIES
 

 
 

 
 

 
 
Plant-related
(3,116,752
)
 
(2,958,369
)
 
(3,116,752
)
 
(2,958,369
)
Risk management activities
(10,626
)
 
(12,171
)
 
(10,626
)
 
(12,171
)
Other postretirement assets
(71,737
)
 
(59,170
)
 
(70,986
)
 
(58,495
)
Regulatory assets:
 

 
 

 
 
 
 

Allowance for equity funds used during construction
(54,110
)
 
(48,286
)
 
(54,110
)
 
(48,286
)
Deferred fuel and purchased power
—

 
(2,498
)
 
—

 
(2,498
)
Deferred fuel and purchased power — mark-to-market
(55,020
)
 
(38,187
)
 
(55,020
)
 
(38,187
)
Pension benefits
(240,692
)
 
(191,747
)
 
(240,692
)
 
(191,747
)
Retired power plant costs (see Note 3)
(53,420
)
 
(57,255
)
 
(53,420
)
 
(57,255
)
Other
(108,441
)
 
(99,123
)
 
(108,441
)
 
(99,123
)
Other
(4,984
)
 
(5,484
)
 
(4,984
)
 
(5,484
)
Total deferred tax liabilities
(3,715,782
)
 
(3,472,290
)
 
(3,715,031
)
 
(3,471,615
)
Deferred income taxes — net
$
(2,723,425
)
 
$
(2,460,404
)
 
$
(2,764,489
)
 
$
(2,516,112
)

 
As of December 31, 2015, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $82 million, which first begin to expire in 2031, and other federal and state loss carryforwards of $3 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.
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, to refinance indebtedness, and for other general corporate purposes.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2015 and 2014 (dollars in thousands):
 
 
December 31, 2015
 
December 31, 2014
 
Pinnacle West
APS
Total
 
Pinnacle West
APS
Total
Commitments under Credit Facility
$
200,000

$
1,000,000

$
1,200,000

 
$
200,000

$
1,000,000

$
1,200,000

Outstanding Commercial Paper Borrowings
—

—

—

 
—

(147,400
)
(147,400
)
Amount of Credit Facility Available
$
200,000

$
1,000,000

$
1,200,000

 
$
200,000

$
852,600

$
1,052,600

 
 
 
 
 
 
 
 
Weighted-Average Commitment Fees
0.125%
0.100%
 
 
0.175%
0.125%
 

Pinnacle West
 
At December 31, 2015, Pinnacle West had a $200 million revolving credit facility that matures in May 2019.  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, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS
 
On September 2, 2015, APS replaced its $500 million revolving credit facility that would have matured in April 2018, with a new $500 million facility that matures in September 2020.

At December 31, 2015, APS had two credit facilities totaling $1 billion, including the $500 million credit facility that matures in September 2020 and a $500 million credit facility that matures in May 2019. APS may increase the amount of each facility up to a maximum of $700 million each, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2015, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 10 for a discussion of APS's other outstanding letters of credit.

Debt Provisions
 
On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of 7% of APS’s capitalization, and $500 million (which is required to be used for costs relating to purchases of natural gas and power). This financing order is set to expire on December 31, 2017. See Note 6 for additional long-term debt provisions.
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, 2015 and 2014 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2015
 
2014
APS
 
 
 
 
 

 
 

Pollution control bonds:
 
 
 
 
 

 
 

Variable
2029-2038
 
(b)
 
$
92,405

 
$
156,405

Fixed
2024-2034
 
1.75%-5.75%
 
211,150

 
249,300

Total pollution control bonds
 
 
 
 
303,555

 
405,705

Senior unsecured notes
2016-2045
 
2.20%-8.75%
 
3,375,000

 
2,875,000

Palo Verde sale leaseback lessor notes
2015
 
8.00%
 
—

 
13,420

Term loan
2018
 
(c)
 
50,000

 
—

Unamortized discount
 
 
 
 
(10,374
)
 
(9,206
)
Unamortized premium
 
 
 
 
4,686

 
4,866

Unamortized debt issuance cost
(d)
 
 
 
(27,896
)
 
(24,642
)
Total APS long-term debt
 
 
 
 
3,694,971

 
3,265,143

Less current maturities
(e)
 
 
 
357,580

 
383,570

Total APS long-term debt less current maturities
 
 
 
 
3,337,391

 
2,881,573

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(f)
 
125,000

 
125,000

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
3,462,391

 
$
3,006,573


(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 0.01%-0.24% at December 31, 2015 and 0.03%-0.27% at December 31, 2014.
(c)
The weighted-average interest rate was 1.024% at December 31, 2015.
(d)
In the fourth quarter of 2015, we adopted a new accounting standard related to balance sheet presentation of debt issuance costs. See Note 2 for additional details.
(e)                                  Current maturities include $108 million of pollution control bonds expected to be remarketed in 2016 and $250 million in senior unsecured notes that mature in 2016.
(f)                                 The weighted-average interest rate was 1.174% at December 31, 2015 and 1.019% at December 31, 2014.

 
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):
Year
 
Consolidated
Pinnacle West
 
Consolidated
APS
2016
 
$
357,580

 
$
357,580

2017
 
125,000

 
—

2018
 
82,000

 
82,000

2019
 
500,000

 
500,000

2020
 
250,000

 
250,000

Thereafter
 
2,538,975

 
2,538,975

Total
 
$
3,853,555

 
$
3,728,555


 
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 thousands):
 
 
As of
December 31, 2015
 
As of
December 31, 2014
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
3,694,971

 
3,981,367

 
3,265,143

 
3,714,108

Total
$
3,819,971

 
$
4,106,367

 
$
3,390,143

 
$
3,839,108


 
Credit Facilities and Debt Issuances
 
APS
 
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.

On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% notes due May 15, 2015.

On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014.
 
On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

On November 6, 2015, APS issued $250 million of 4.35% unsecured senior notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance via redemption and cancellation at par our indebtedness related to the principal amounts of the Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A and 2009 Series C both due June 1, 2034, and repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On November 17, 2015, APS redeemed at par and canceled all $38 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014.

On November 17, 2015, APS canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series B, purchased in connection with the mandatory tender provision on May 30, 2014.

On December 8, 2015, APS redeemed at par and canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series C.
 
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, 2015, the ratio was approximately 47% for Pinnacle West and 46% 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, 2015, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.7 billion, and total capitalization was approximately $8.6 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.4 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.

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 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 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. See Note 5 for additional short-term debt provisions.
Retirement Plans and Other Benefits
Retirement Plans and Other Benefits
Retirement Plans and Other Postretirement 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). The remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income.
 
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 three years beginning in July 2012.  We amortized approximately $5 million in 2015, $8 million in 2014, $8 million in 2013 and $4 million in 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
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Service cost-benefits earned during the period
$
59,627

 
$
53,080

 
$
64,195

 
$
16,827

 
$
18,139

 
$
23,597

Interest cost on benefit obligation
123,983

 
129,194

 
112,392

 
28,102

 
41,243

 
41,536

Expected return on plan assets
(179,231
)
 
(158,998
)
 
(146,333
)
 
(36,855
)
 
(46,400
)
 
(45,717
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
594

 
869

 
1,097

 
(37,968
)
 
(9,626
)
 
(179
)
Net actuarial loss
31,056

 
10,963

 
39,852

 
4,881

 
1,175

 
11,310

Net periodic benefit cost
$
36,029

 
$
35,108

 
$
71,203

 
$
(25,013
)
 
$
4,531

 
$
30,547

Portion of cost charged to expense
$
20,036

 
$
21,985

 
$
38,968

 
$
(10,391
)
 
$
6,000

 
$
18,469


 
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2015 and 2014 (dollars in thousands):
 
Pension
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
3,078,648

 
$
2,646,530

 
$
682,335

 
$
890,418

Service cost
59,627

 
53,080

 
16,827

 
18,139

Interest cost
123,983

 
129,194

 
28,102

 
41,243

Benefit payments
(137,115
)
 
(128,550
)
 
(24,988
)
 
(29,054
)
Actuarial (gain) loss
(91,340
)
 
378,394

 
(55,256
)
 
150,188

Plan amendments
—

 
—

 
—

 
(388,599
)
Benefit obligation at December 31
3,033,803

 
3,078,648

 
647,020

 
682,335

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,615,404

 
2,264,121

 
834,625

 
748,339

Actual return on plan assets
(44,690
)
 
292,992

 
(2,399
)
 
105,223

Employer contributions
100,000

 
175,000

 
791

 
770

Benefit payments
(127,940
)
 
(116,709
)
 
—

 
(19,707
)
Fair value of plan assets at December 31
2,542,774

 
2,615,404

 
833,017

 
834,625

Funded Status at December 31
$
(491,029
)
 
$
(463,244
)
 
$
185,997

 
$
152,290



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, 2015 and 2014 (dollars in thousands):
 
2015
 
2014
Projected benefit obligation
$
3,033,803

 
$
3,078,648

Accumulated benefit obligation
2,873,467

 
2,873,741

Fair value of plan assets
2,542,774

 
2,615,404


 
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2015 and 2014 (dollars in thousands):
 
Pension
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
Noncurrent asset
$
—

 
$
—

 
$
185,997

 
$
152,290

Current liability
(10,031
)
 
(9,508
)
 
—

 
—

Noncurrent liability
(480,998
)
 
(453,736
)
 
—

 
—

Net amount recognized
$
(491,029
)
 
$
(463,244
)
 
$
185,997

 
$
152,290


 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2015 and 2014 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
Net actuarial loss
$
679,501

 
$
577,976

 
$
127,124

 
$
148,006

Prior service cost (credit)
609

 
1,203

 
(341,301
)
 
(379,269
)
APS’s portion recorded as a regulatory (asset) liability
(619,223
)
 
(485,037
)
 
213,621

 
230,916

Income tax expense (benefit)
(23,663
)
 
(36,890
)
 
925

 
851

Accumulated other comprehensive loss
$
37,224

 
$
57,252

 
$
369

 
$
504


 
The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2016 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
38,923

 
$
3,784

Prior service cost (credit)
527

 
(37,884
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2016
$
39,450

 
$
(34,100
)


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,
 
2015
 
2014
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
January - September
October - December
 
 
Discount rate – pension
4.37
%
 
4.02
%
 
4.02
%
 
4.88
%
4.88
%
 
4.01
%
Discount rate – other benefits
4.52
%
 
4.14
%
 
4.14
%
 
5.10
%
4.41
%
 
4.20
%
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
%
6.90
%
 
7.00
%
Expected long-term return on plan assets - other benefits
N/A

 
N/A

 
4.45
%
 
6.80
%
4.25
%
 
7.00
%
Initial healthcare cost trend rate (pre-65 participants)
7.00
%
 
7.00
%
 
7.00
%
 
7.50
%
7.50
%
 
7.50
%
Initial healthcare cost trend rate (post-65 participants)
5.00
%
 
5.00
%
 
5.00
%
 
7.50
%
5.00
%
 
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

 
0

 
0

 
4

0

 
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 2016, 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 thousands): 
 
1% Increase
 
1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
$
8,834

 
$
(5,890
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
9,069

 
(6,949
)
Effect on the accumulated other postretirement benefit obligation
100,322

 
(80,332
)

 
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 2015, 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, 2015, long-term fixed income assets represented 60% of total pension plan assets, and return-generating assets represented 40% of total pension plan assets.
 
As of December 31, 2015, 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, 2015, investment in fixed income assets represented 40% of the other postretirement benefit plan total assets, and non-fixed income assets represented 60% 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 mutual funds, 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.
 
Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (NAV) concept or its equivalent. Exchange traded mutual funds, are classified as Level 1, as the valuation for these instruments is based on the active market in which the fund trades.

Common and collective trusts, 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).  The trust's shares are offered to a limited group of investors, and are not traded in an active market. The NAV for trusts investing in exchange traded equities is derived from the quoted active market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets.  As of December 31, 2015, the plans were able to transact in the common and collective trusts at NAV and classifies these investments as Level 2.

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. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, 2015, approximately $40 million of these commitments have been funded. Partnerships are classified as Level 2 if the plan is able to transact in the partnership at the NAV, otherwise the partnership is classified as Level 3.
 
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, 2015, 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, 2015
Pension Plan:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
1,893

 
$
—

 
$
—

 
$
—

 
$
1,893

Fixed income securities:
 

 
 

 
 

 
 

 
 

Corporate
—

 
1,108,736

 
—

 
—

 
1,108,736

U.S. Treasury
274,778

 
—

 
—

 
—

 
274,778

Other (a)
—

 
113,008

 
—

 
—

 
113,008

Equities:
 

 
 

 
 

 
 

 
 

U.S. companies
233,021

 
—

 
—

 
—

 
233,021

International companies
14,680

 
—

 
—

 
—

 
14,680

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. equities
—

 
130,097

 
—

 
—

 
130,097

International equities
—

 
185,892

 
—

 
—

 
185,892

Real estate
—

 
150,359

 
—

 
—

 
150,359

Partnerships
—

 
127,840

 
42,097

 
—

 
169,937

Mutual funds - International equities
116,307

 
—

 
—

 
—

 
116,307

Short-term investments and other
—

 
29,599

 
—

 
14,467

 
44,066

Total Pension Plan
$
640,679

 
$
1,845,531

 
$
42,097

 
$
14,467

 
$
2,542,774

Other Benefits:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
240

 
$
—

 
$
—

 
$
—

 
$
240

Fixed income securities:
 

 
 

 
 

 
 

 
 

Corporate
—

 
217,026

 
—

 
—

 
217,026

U.S. Treasury
131,435

 
—

 
—

 
—

 
131,435

Other (a)
—

 
31,106

 
—

 
—

 
31,106

Equities:
 

 
 

 
 

 
 

 
 

U.S. companies
253,193

 
—

 
—

 
—

 
253,193

International companies
12,390

 
—

 
—

 
—

 
12,390

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. equities
—

 
81,516

 
—

 
—

 
81,516

International equities
—

 
28,539

 
—

 
—

 
28,539

Real estate
—

 
13,512

 
—

 
—

 
13,512

Mutual funds - International equities
52,568

 
—

 
—

 
—

 
52,568

Short-term investments and other
5,065

 
3,331

 
—

 
3,096

 
11,492

Total Other Benefits
$
454,891

 
$
375,030

 
$
—

 
$
3,096

 
$
833,017


(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, 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 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, 2015 and 2014 (dollars in thousands):
 
 
Pension
Partnerships
 
2015
 
2014
Beginning balance at January 1
 
$
27,929

 
$
8,660

Actual return on assets still held at December 31
 
2,789

 
927

Purchases
 
13,187

 
19,984

Sales
 
(1,808
)
 
(1,642
)
Transfers in and/or out of Level 3
 
—

 
—

Ending balance at December 31
 
$
42,097

 
$
27,929


 
Contributions
 
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $100 million in 2015, $175 million in 2014, and $141 million in 2013.  The minimum required contributions for the pension plan are zero for the next three years.  We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period.  With regard to contributions to our other postretirement benefit plans, we made a contribution of $1 million in 2015, $1 million in 2014, and $14 million in 2013.  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 $100 million in 2015, $175 million in 2014, and $140 million in 2013.  APS’s share of the contributions to the other postretirement benefit plan was $1 million in 2015, $1 million in 2014, and $14 million in 2013.
 
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
2016
 
$
152,146

 
$
26,468

2017
 
171,005

 
28,444

2018
 
170,534

 
30,490

2019
 
180,700

 
32,438

2020
 
188,988

 
33,982

Years 2021-2025
 
1,023,451

 
184,335


 
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 2015, 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 2015, $9 million for 2014, and $9 million for 2013.
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 $17 million in 2015, $18 million in 2014, and $18 million in 2013.  APS’s lease expense was $14 million in 2015, $15 million in 2014, and $15 million in 2013.
 
Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands):
Year
 
Pinnacle West
Consolidated
 
APS
2016
 
$
9,182

 
$
8,797

2017
 
8,557

 
8,317

2018
 
7,045

 
6,880

2019
 
6,121

 
5,961

2020
 
4,835

 
4,680

Thereafter
 
61,251

 
61,101

Total future lease commitments
 
$
96,991

 
$
95,736


 
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 which are included in the corresponding operating expenses on our consolidated statement of income. We are also responsible 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, 2015 (dollars in thousands):

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

 
 
 
 

 
 

 
 

Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,744,137

 
$
1,067,376

 
$
22,228

Palo Verde Unit 2 (a)
 
16.8
%
 

 
583,633

 
356,767

 
4,142

Palo Verde Common
 
28.0
%
 
(b)
 
643,201

 
231,609

 
64,069

Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
233,665

 
—

Four Corners Generating Station
 
63.0
%
 

 
857,555

 
577,321

 
77,317

Navajo Generating Station Units 1, 2 and 3
 
14.0
%
 

 
274,640

 
168,132

 
4,460

Cholla common facilities (c)
 
63.3
%
 
(b)
 
158,623

 
53,777

 
1,390

Transmission facilities:
 
 

 
 
 
 

 
 

 
 

ANPP 500kV System
 
33.4
%
 
 (b)
 
109,348

 
36,576

 
1,594

Navajo Southern System
 
22.7
%
 
(b)
 
62,139

 
19,361

 
397

Palo Verde — Yuma 500kV System
 
19.3
%
 
(b)
 
14,043

 
5,226

 
133

Four Corners Switchyards
 
49.8
%
 
 (b)
 
38,420

 
9,833

 
1,687

Phoenix — Mead System
 
17.1
%
 
(b)
 
39,089

 
13,173

 
151

Palo Verde — Estrella 500kV System
 
50.0
%
 
(b)
 
89,832

 
18,359

 
1,008

Morgan — Pinnacle Peak System
 
64.6
%
 
 (b)
 
129,855

 
11,087

 
2,592

Round Valley System
 
50.0
%
 
(b)
 
703

 
286

 
—

Palo Verde — Morgan System
 
87.7
%
 
(b)
 
12

 
—

 
133,813

Hassayampa - North Gila System
 
80.0
%
 
(b)
 
164,854

 
1,159

 
—

Cholla 500 Switchyard
 
85.7
%
 
(b)
 
547

 
15

 
—

Saguaro 500 Switchyard
 
75.0
%
 
(b)
 
773

 
26

 
—


(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 second breach of contract lawsuit against DOE in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of current reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

APS’s first claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2011 through June 30, 2014, and was for $42.0 million (APS’s share of this amount was $12.2 million), was received on June 1, 2015. APS's $12.2 million share was recorded as an adjustment to a regulatory liability and had no impact on the amount of current reported net income. APS’s second claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2014 through June 30, 2015, was filed for $12.0 million (APS's share of this amount would be $3.6 million), and has been submitted to, but not yet approved by, the DOE in the fourth quarter of 2015.
  
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 $13.5 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of $13.1 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 $16.6 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 $2.8 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 $23.1 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 $61.7 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 various fuel and purchased power contracts and purchase obligations with terms expiring between 2016 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $876 million in 2016; $949 million in 2017; $737 million in 2018; $603 million in 2019; $498 million in 2020; and $7.8 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 thousands):
 
 
 Years Ended December 31,
 
2016
 
2017
 
2018
 
2019
 
2020
 
Thereafter
Coal take-or-pay commitments (a)
$
170,714

 
$
195,428

 
$
189,588

 
$
193,818

 
$
198,160

 
$
2,270,974

 
(a)
Total take-or-pay commitments are approximately $3.2 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 thousands):
 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Total payments
$
211,327

 
$
236,773

 
$
188,496


 
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 $42 million in 2016; $40 million in 2017; $40 million in 2018; $40 million in 2019; $40 million in 2020; and $432 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.
 
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 $202 million at December 31, 2015 and $198 million at December 31, 2014.  Under our current coal supply agreements, we expect to make payments for the final mine reclamation as follows:  $15 million in 2016; $16 million in 2017; $18 million in 2018; $19 million in 2019; $20 million in 2020; and $262 million thereafter.  Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

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.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  We are unable to predict the outcome of these matters; 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
 
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.
 
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 United States Court of Appeals for the Ninth Circuit, which heard oral argument on February 9, 2016.  A written decision on the case is expected 30-60 days after oral argument. We believe the District Court's decision will be upheld on appeal, but cannot predict the outcome at the appellate court. If the District Court's decision is reversed, the case would be remanded for discovery and trial, and there is insufficient information at this time to reasonably estimate any possible loss or range of loss to APS and Pinnacle West.

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.  The case was held in abeyance while APS negotiated a settlement with DOJ and environmental plaintiffs.  In March 2015, the parties agreed in principle to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On August 17, 2015, the consent decree was entered by the district court.

The settlement requires installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two Four Corners units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule requirements. The settlement also requires the Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.7 million for certain environmental mitigation projects to benefit the Navajo Nation. APS is responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows.
 
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 BART to lessen the impacts of emissions on visibility surrounding the plants.

Four Corners. 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 approximately $400 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. When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. APS is negotiating a definitive purchase agreement with NTEC for the purchase of the 7% interest. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP, could be up to approximately $200 million.  In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process.

Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015), 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.

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 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/or 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. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On October 16, 2015, ADEQ issued the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  APS is unable to predict when or whether APS's proposal may ultimately be approved by the EPA.
 
Mercury and Air Toxic Standards ("MATS").  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 $8 million for Cholla (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015). 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, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. The United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS proceeding back to the DC Circuit Court. The Circuit Court then remanded the MATS rule back to EPA to address rulemaking deficiencies identified by the Supreme Court. Further EPA action on the MATS rule is pending.  This proceeding does not materially impact APS.  Regardless of how EPA addresses the deficiencies in the MATS rulemaking, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla.
 
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. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for existing, new, modified, and reconstructed EGUs. EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal.

With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO2 emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below.

ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, is presently working to develop a compliance plan for submittal to EPA. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation.

The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such delay.

With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances.

As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation.

Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material.

Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes.

In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output, as an alternative to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, and additional information or considerations may arise that change our expectations.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, greenhouse gas emissions, and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and 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.
 



Notice of Intent to Sue Related to Four Corners

On December 21, 2015, several environmental groups filed a notice of intent to sue with OSM and other federal agencies under the Endangered Species Act alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the DOI's review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. We are monitoring this matter and will intervene if a lawsuit is filed. We cannot predict the timing or outcome of this matter.


New Mexico Tax Matter
 
On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") 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 NMTRD 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.  On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed an appeal of the decision on August 31, 2015. The parties are engaged in settlement discussions and we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Financial Assurances
 
In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of December 31, 2015, standby letters of credit totaled $79 million and will expire in 2016. As of December 31, 2015, surety bonds expiring through 2018 totaled $158 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
 
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, 2015.
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 2015, a revision to the estimated cash flows for the decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the ARO in the amount of $24 million. Also in 2015, Four Corners spent $32 million in actual decommissioning costs. In addition, APS recognized an ARO for Cholla as a result of new CCR environmental rules that were published in the Federal Register in the second quarter of 2015. See Note 10 for additional information related to the CCR environmental rules. This resulted in an increase to the ARO in the amount of $39 million, an increase in plant in service of $23 million and a reduction of the regulatory liability of $16 million. Finally, in 2015 there was a revision in estimated cash flows for the Cholla decommissioning, which resulted in a decrease of the ARO in the amount of $3 million.

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.
 
The following table shows the change in our asset retirement obligations for 2015 and 2014 (dollars in thousands):

 
2015
 
2014
Asset retirement obligations at the beginning of year
$
390,750

 
$
346,729

Changes attributable to:
 

 
 

Accretion expense
25,163

 
23,567

Settlements
(32,048
)
 
(29,497
)
Estimated cash flow revisions
17,556

 
43,899

Newly incurred obligation
42,155

 
6,052

Asset retirement obligations at the end of year
$
443,576

 
$
390,750


 
As mentioned above, decommissioning activities for Four Corners Units 1-3 began in January 2014. Decommissioning activities for Cholla ash ponds began in January 2015. Thus, $29 million of the total ARO of $444 million at December 31, 2015, is classified as a current liability on the balance sheet. At December 31, 2014, $32 million of the total ARO of $391 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) 
Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2015 and 2014 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.

 
2015 Quarter Ended
 
2015
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
671,219

 
$
890,648

 
$
1,199,146

 
$
734,430

 
$
3,495,443

Operations and maintenance
214,944

 
210,965

 
220,449

 
222,019

 
868,377

Operating income
67,684

 
231,973

 
445,111

 
109,834

 
854,602

Income taxes
7,947

 
67,371

 
139,555

 
22,847

 
237,720

Net income
20,727

 
127,507

 
261,978

 
45,978

 
456,190

Net income attributable to common shareholders
16,122

 
122,902

 
257,116

 
41,117

 
437,257

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.15

 
$
1.11

 
$
2.32

 
$
0.37

 
$
3.94

Net income attributable to common shareholders — Diluted
0.14

 
1.10

 
2.30

 
0.37

 
3.92

 
 
2014 Quarter Ended
 
2014
 
March 31,
 
June 30,
 
September 30,
 
December 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

Net income
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

Selected Quarterly Financial Data (Unaudited) 
Selected Quarterly Financial Data (Unaudited) - APS
 
APS's quarterly financial information for 2015 and 2014 is as follows (dollars in thousands):
 
 
2015 Quarter Ended,
 
2015
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
670,668

 
$
889,723

 
$
1,198,380

 
$
733,586

 
$
3,492,357

Operations and maintenance
209,947

 
208,031

 
216,011

 
219,146

 
853,135

Operating income
61,333

 
162,704

 
301,238

 
86,709

 
611,984

Net income attributable to common shareholder
19,868

 
125,362

 
261,187

 
43,857

 
450,274

 
 
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

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, exchange traded mutual funds, 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 certain investments that are valued and redeemable 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.  We classify these investments as Level 2. The commingled 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 1 represent investments held in a short-term investment exchange-traded mutual fund, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper.
 
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 typically 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, 2015 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

 
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, 2015
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
22,992

 
$
30,364

 
$
(25,345
)
 
(b)
 
$
28,011

Nuclear decommissioning trust:
 

 
 

 
 

 
 
 
 
 
 

U.S. commingled equity funds
—

 
314,957

 
—

 
—

 

 
314,957

Fixed income securities:
 

 
 

 
 

 
 
 
 
 
 

     Cash and cash equivalent funds
12,260

 
—

 
—

 
(335
)
 
(c)
 
11,925

U.S. Treasury
117,245

 
—

 
—

 
—

 
 
 
117,245

Corporate debt
—

 
96,243

 
—

 
—

 
 
 
96,243

Mortgage-backed securities
—

 
99,065

 
—

 
—

 
 
 
99,065

Municipal bonds
—

 
72,206

 
—

 
—

 
 
 
72,206

Other
—

 
23,555

 
—

 
—

 
 
 
23,555

Subtotal nuclear decommissioning trust
129,505

 
606,026

 
—

 
(335
)
 

 
735,196

Total
$
129,505

 
$
629,018

 
$
30,364

 
$
(25,680
)
 

 
$
763,207

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(144,044
)
 
$
(63,343
)
 
$
39,698

 
(b)
 
$
(167,689
)

(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, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
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
$
—

 
$
20,769

 
$
32,598

 
$
(21,962
)
 
(b)
 
$
31,405

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
309,620

 
—

 
—

 

 
309,620

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
118,843

 
—

 
—

 
—

 
 
 
118,843

Cash and cash equivalent funds
—

 
11,453

 
—

 
(7,245
)
 
(c)
 
4,208

Corporate debt
—

 
109,379

 
—

 
—

 
 
 
109,379

Mortgage-backed securities
—

 
88,465

 
—

 
—

 
 
 
88,465

Municipal bonds
—

 
69,139

 
—

 
—

 
 
 
69,139

Other
—

 
14,212

 
—

 
—

 
 
 
14,212

Subtotal nuclear decommissioning trust
118,843

 
602,268

 
—

 
(7,245
)
 

 
713,866

Total
$
118,843

 
$
623,037

 
$
32,598

 
$
(29,207
)
 

 
$
745,271

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(95,061
)
 
$
(73,984
)
 
$
58,767

 
(b)
 
$
(110,278
)

(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 at December 31, 2015 for these instruments include electricity prices, and volatilities. The significant unobservable inputs at December 31, 2014 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, 2015 and December 31, 2014:
 
 
December 31, 2015
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
24,543

 
$
54,679

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$15.92 - $40.73
 
$
26.86

Option Contracts (b)
—

 
5,628

 
Option model
 
Electricity forward price (per MWh)
 
$23.87 - $44.13
 
$
33.91

 
 

 
 

 
 
 
Electricity price volatilities
 
40% - 59%
 
52
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
32% - 40%
 
35
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
5,821

 
3,036

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.18 - $3.14
 
$
2.61

Total
$
30,364

 
$
63,343

 
 
 
 
 
 
 
 


(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, 2014
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
29,471

 
$
55,894

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

Option Contracts (b)
—

 
15,035

 
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)
3,127

 
3,055

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

Total
$
32,598

 
$
73,984

 
 
 
 
 
 
 
 


(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, 2015 and 2014 (dollars in thousands):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2015
 
2014
Net derivative balance at beginning of period
 
$
(41,386
)
 
$
(49,165
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 
—

 
102

Included in OCI
 
(452
)
 
(239
)
Deferred as a regulatory asset or liability
 
(4,009
)
 
(482
)
Settlements
 
14,809

 
12,080

Transfers into Level 3 from Level 2
 
(6,256
)
 
(2,090
)
Transfers from Level 3 into Level 2
 
4,315

 
(1,592
)
Net derivative balance at end of period
 
$
(32,979
)
 
$
(41,386
)
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, 2015, 2014 and 2013 (in thousands, except per share amounts):
 
2015
 
2014
 
2013
Net income attributable to common shareholders
$
437,257

 
$
397,595

 
$
406,074

Weighted average common shares outstanding — basic
111,026

 
110,626

 
109,984

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
526

 
552

 
822

Weighted average common shares outstanding — diluted
111,552

 
111,178

 
110,806

Earnings per average common share attributable to common shareholders — basic
$
3.94

 
$
3.59

 
$
3.69

Earnings per average common share attributable to common shareholders — diluted
$
3.92

 
$
3.58

 
$
3.66

Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
 
Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.  The 2012 Plan authorizes up to 4.6 million common shares to be available for grant.  As of December 31, 2015, 2.8 million common shares were available for issuance under the 2012 Plan. During 2015, 2014, and 2013, the Company has granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. The Company has not granted stock options since 2004 and has no stock options outstanding. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

Stock-Based Compensation Expense and Activity
 
Compensation cost included in net income for stock-based compensation plans was $19 million in 2015, $33 million in 2014, and $25 million in 2013.  The compensation cost capitalized is immaterial for all years.  Income tax benefits related to stock-based compensation arrangements were $7 million in 2015, $13 million in 2014, and $10 million in 2013.

As of December 31, 2015, there were approximately $14 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements.  These costs are expected to be recognized over a weighted-average period of 2 years.  The total fair value of shares vested was $21 million in 2015, $20 million in 2014 and $20 million in 2013.
 
The following table is a summary of awards granted and the weighted-average fair value for the three years ended 2015, 2014 and 2013.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Units granted
152,651

 
179,291

 
182,240

 
151,430

 
166,244

 
176,332

Weighted-average grant date fair value
$
64.12

 
$
54.89

 
$
55.14

 
$
64.97

 
$
54.86

 
$
55.45

(a)
Units granted includes awards that will be cash settled of 45,104 in 2015, 49,018 in 2014, and 52,620 in 2013.
(b)
Reflects the target payout level.
 
The following table is a summary of the status of non-vested awards as of December 31, 2015 and changes during the year.

 
Restricted Stock Units, Stock Grants, and Stock Units
 
Performance Shares
 
Shares
 
Weighted-Average
Grant Date
Fair Value
 
Shares (b)
 
Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2015
480,933

(a)
$
51.27

 
324,230

 
$
54.92

Granted
152,651

 
64.12

 
151,430

 
64.97

Change in performance factor
—

 
—

 
40,496

 
54.98

Vested
(198,424
)
 
49.20

 
(202,480
)
 
54.98

Forfeited
(6,873
)
 
56.78

 
(7,844
)
 
57.89

Nonvested at December 31, 2015
428,287

 
56.69

 
305,832

 
59.78

Vested Awards Outstanding at December 31, 2015
106,712

 


 
202,480

 



 
(a)
Includes 127,634 of awards that will be cash settled and 353,299 of awards that will be settled in shares.
(b)
Nonvested performance 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.

Share-based liabilities paid relating to restricted stock unit awards was $10 million, $9 million and $10 million in 2015, 2014 and 2013, respectively. This includes cash used to settle restricted stock units of $3 million, $3 million and $4 million in 2015, 2014 and 2013, respectively. Share-based liabilities paid relating to performance share awards was $16 million, $12 million and $15 million in 2015, 2014 and 2013, respectively.
 
Restricted Stock Units, Stock Grants, and Stock Units
 
Restricted stock units have been granted to officers and key employees.  Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date.  Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights, 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. If the award is forfeited the employee is not entitled to the dividends on those shares.
 
In December 2012, a retention award of 50,617 restricted stock units was granted to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West.  This 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 can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met.

Restricted stock unit 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.
 
Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant.  The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, or 50% in cash and 50% in stock.  The 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.
 
Performance Share Awards
 
Performance share awards have been granted to officers and key employees.  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 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. If the award is forfeited or if the performance criteria are not achieved the employee is not entitled to the dividends on those shares.
 
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.  Management 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.
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.  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, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
Commodity
 
Quantity
Power
 
2,487

 
GWh
Gas
 
182

 
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, 2015, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2015
 
2014
 
2013
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(615
)
 
$
(372
)
 
$
(353
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(5,988
)
 
(21,415
)
 
(44,219
)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Fuel and purchased power (b)
 
—

 
—

 
—


(a)
During the years ended December 31, 2015, 2014, and 2013, we had no 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 $4 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, most 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, 2015, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2015
 
2014
 
2013
Net Gain Recognized in Income
 
Operating revenues
 
$
574

 
$
324

 
$
289

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(108,973
)
 
(66,367
)
 
(10,449
)
Total
 
 
 
$
(108,399
)
 
$
(66,043
)
 
$
(10,160
)

(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, 2015 and December 31, 2014, include gross liabilities of $3 million and $4 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, 2015 and 2014.  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, 2015:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
37,396

 
$
(22,163
)
 
$
15,233

 
$
672

 
$
15,905

Investments and other assets
 
15,960

 
(3,854
)
 
12,106

 
—

 
12,106

Total assets
 
53,356

 
(26,017
)
 
27,339

 
672

 
28,011

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(113,560
)
 
40,223

 
(73,337
)
 
(4,379
)
 
(77,716
)
Deferred credits and other
 
(93,827
)
 
3,854

 
(89,973
)
 
—

 
(89,973
)
Total liabilities
 
(207,387
)
 
44,077

 
(163,310
)
 
(4,379
)
 
(167,689
)
Total
 
$
(154,031
)
 
$
18,060

 
$
(135,971
)
 
$
(3,707
)
 
$
(139,678
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $18,060.
(c)
Represents cash collateral and cash 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 $4,379, and cash margin provided to counterparties of $672.
 
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
 
$
28,557

 
$
(15,127
)
 
$
13,430

 
$
355

 
$
13,785

Investments and other assets
 
24,810

 
(7,190
)
 
17,620

 
—

 
17,620

Total assets
 
53,367

 
(22,317
)
 
31,050

 
355

 
31,405

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(86,055
)
 
33,829

 
(52,226
)
 
(7,443
)
 
(59,669
)
Deferred credits and other
 
(82,990
)
 
32,388

 
(50,602
)
 
—

 
(50,602
)
Total liabilities
 
(169,045
)
 
66,217

 
(102,828
)
 
(7,443
)
 
(110,271
)
Total
 
$
(115,678
)
 
$
43,900

 
$
(71,778
)
 
$
(7,088
)
 
$
(78,866
)

(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 $355. 

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 87% of Pinnacle West’s $28 million of risk management assets as of December 31, 2015.  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, 2015 (dollars in thousands):
 
 
December 31, 2015
Aggregate fair value of derivative instruments in a net liability position
$
207,387

Cash collateral posted
18,060

Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)
112,301


(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 $161 million if our debt credit ratings were to fall below investment grade.
Other Income and Other Expense
Other Income and Other Expense 
Other Income and Other Expense
 
The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2015, 2014 and 2013 (dollars in thousands):
 
 
2015
 
2014
 
2013
Other income:
 

 
 

 
 

Interest income
$
493

 
$
1,010

 
$
1,629

Debt return on the purchase of Four Corners units 4 & 5
—

 
8,386

 
—

Miscellaneous
128

 
212

 
75

Total other income
$
621

 
$
9,608

 
$
1,704

Other expense:
 

 
 

 
 

Non-operating costs
$
(11,292
)
 
$
(9,657
)
 
$
(8,207
)
Investment loss — net
(2,080
)
 
(9,426
)
 
(3,711
)
Miscellaneous
(4,451
)
 
(2,663
)
 
(4,106
)
Total other expense
$
(17,823
)
 
$
(21,746
)
 
$
(16,024
)
Other Income and Other Expense 
Other Income and Other Expense - APS
 
The following table provides detail of APS’s other income and other expense for 2015, 2014 and 2013 (dollars in thousands):
 
 
2015
 
2014
 
2013
Other income:
 

 
 

 
 

Interest income
$
163

 
$
689

 
$
1,234

Debt return on the purchase of Four Corners units 4 & 5
—

 
8,386

 
—

Gain on disposition of property
716

 
1,197

 
1,024

Miscellaneous
1,955

 
1,023

 
1,638

Total other income
$
2,834

 
$
11,295

 
$
3,896

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(11,648
)
 
$
(10,397
)
 
$
(9,626
)
Loss on disposition of property
(2,219
)
 
(615
)
 
(4,992
)
Miscellaneous
(5,152
)
 
(2,391
)
 
(5,831
)
Total other expense
$
(19,019
)
 
$
(13,403
)
 
$
(20,449
)

(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 trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  The original lease was scheduled to end on December 31, 2015; however, the lease agreements include fixed rate renewal options which APS exercised on July 7, 2014.  As a result, APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases 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.
 
The fixed rate renewal periods give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for 2015, 2014 and 2013 of $19 million, $26 million and $34 million, respectively, entirely attributable to the noncontrolling interests.  The income attributable to the noncontrolling interests decreased in 2015 and 2014 compared with the prior year because of lower rent income resulting from the lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income that resulted from the lease extensions. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. 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, 2015 and December 31, 2014 include the following amounts relating to the VIEs (dollars in thousands):
 
 
December 31, 2015
 
December 31, 2014
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation
$
117,385

 
$
121,255

Current maturities of long-term debt
—

 
13,420

Equity-Noncontrolling interests
135,540

 
151,609


 
Assets of the VIEs are restricted and may only be used 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 could be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease extension period, APS may be required to pay the noncontrolling equity participants approximately $288 million beginning in 2016, and up to $465 million over the lease extension term.
 
For regulatory ratemaking purposes, the agreements continue to be 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, 2015 and December 31, 2014 (dollars in thousands):
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2015
 

 
 

 
 

Equity securities
$
314,957

 
$
157,098

 
$
(115
)
Fixed income securities
420,574

 
11,955

 
(2,645
)
Net payables (a)
(335
)
 
—

 
—

Total
$
735,196

 
$
169,053

 
$
(2,760
)
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2014
 

 
 

 
 

Equity securities
$
309,620

 
$
159,274

 
$
(15
)
Fixed income securities
411,491

 
17,260

 
(1,073
)
Net payables (a)
(7,245
)
 
—

 
—

Total
$
713,866

 
$
176,534

 
$
(1,088
)

(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 thousands):
 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Realized gains
$
5,189

 
$
4,725

 
$
5,459

Realized losses
(6,225
)
 
(4,525
)
 
(6,706
)
Proceeds from the sale of securities (a)
478,813

 
356,195

 
446,025


(a)
Proceeds are reinvested in the trust.
 
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2015 is as follows (dollars in thousands):
 
 
Fair Value
Less than one year
$
14,001

1 year – 5 years
117,356

5 years – 10 years
114,769

Greater than 10 years
174,448

Total
$
420,574

Changes in Accumulated Other Comprehensive Loss
Changes in Accumulated Other Comprehensive Loss 
Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2015 and 2014 (dollars in thousands): 
 
Year Ended December 31,
 
2015
 
2014
Balance at beginning of period
$
(68,141
)
 
$
(78,053
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(957
)
 
(810
)
Amounts reclassified from accumulated other comprehensive loss (a)
4,187

 
13,483

Net current period OCI (loss)
3,230

 
12,673

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
16,980

 
(5,419
)
Amounts reclassified from accumulated other comprehensive loss (b)
3,183

 
2,658

Net current period OCI (loss)
20,163

 
(2,761
)
Balance at end of period
$
(44,748
)
 
$
(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.
Changes in Accumulated Other Comprehensive Loss 
Changes in Accumulated Other Comprehensive Loss - APS
 
The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2015 and 2014 (dollars in thousands): 
 
Year Ended December 31,
 
2015
 
2014
Balance at beginning of period
$
(48,333
)
 
$
(53,372
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(957
)
 
(809
)
Amounts reclassified from accumulated other comprehensive loss (a)
4,187

 
13,483

Net current period OCI (loss)
3,230

 
12,674

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
14,726

 
(10,415
)
Amounts reclassified from accumulated other comprehensive loss (b)
3,280

 
2,780

Net current period OCI (loss)
18,006

 
(7,635
)
Balance at end of period
$
(27,097
)
 
$
(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.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Operating revenues
$
550

 
$
642

 
$
799

Operating expenses
12,733

 
23,507

 
24,930

Operating loss
(12,183
)
 
(22,865
)
 
(24,131
)
Other
 

 
 

 
 

Equity in earnings of subsidiaries
446,508

 
411,528

 
420,926

Other expense
(3,302
)
 
(3,276
)
 
(1,999
)
Total
443,206

 
408,252

 
418,927

Interest expense
2,672

 
3,663

 
3,226

Income before income taxes
428,351

 
381,724

 
391,570

Income tax benefit
(8,906
)
 
(15,871
)
 
(14,504
)
Net income attributable to common shareholders
437,257

 
397,595

 
406,074

Other comprehensive income — attributable to common shareholders
23,393

 
9,912

 
35,955

Total comprehensive income — attributable to common shareholders
$
460,650

 
$
407,507

 
$
442,029


 
See Combined Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(dollars in thousands)
 
 
December 31,
 
2015
 
2014
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
17,432

 
$
3,088

Accounts receivable
93,093

 
99,958

Current deferred income taxes
—

 
66,979

Income tax receivable
14,895

 
7,329

Other current assets
197

 
124

Total current assets
125,617

 
177,478

Investments and other assets
 

 
 

Investments in subsidiaries
4,815,236

 
4,630,570

Deferred income taxes
41,065

 
—

Other assets
43,422

 
43,051

Total investments and other assets
4,899,723

 
4,673,621

Total Assets
$
5,025,340

 
$
4,851,099

LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
$
5,901

 
$
5,250

Accrued taxes
6,904

 
12,220

Common dividends payable
69,363

 
65,790

Other current liabilities
33,120

 
38,992

Total current liabilities
115,288

 
122,252

Long-term debt less current maturities
125,000

 
125,000

Deferred credits and other
 
 
 

Deferred income taxes
—

 
12,055

Pension liabilities
21,933

 
29,228

Other
43,662

 
43,462

Total deferred credits and other
65,595

 
84,745

Common stock equity
 
 
 
Common stock
2,535,862

 
2,509,569

Accumulated other comprehensive loss
(44,748
)
 
(68,141
)
Retained earnings
2,092,803

 
1,926,065

Total Pinnacle West Shareholders’ equity
4,583,917

 
4,367,493

Noncontrolling interests
135,540

 
151,609

Total Equity
4,719,457

 
4,519,102

Total Liabilities and Equity
$
5,025,340

 
$
4,851,099


 
See Combined Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(dollars in thousands)
 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Cash flows from operating activities
 

 
 

 
 

Net income
$
437,257

 
$
397,595

 
$
406,074

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

Equity in earnings of subsidiaries — net
(446,508
)
 
(411,528
)
 
(420,926
)
Depreciation and amortization
92

 
94

 
95

Deferred income taxes
12,967

 
4,406

 
(28,806
)
Accounts receivable
11,336

 
(22,945
)
 
21,671

Accounts payable
637

 
2,017

 
(2,449
)
Accrued taxes and income tax receivables — net
(12,882
)
 
(1,795
)
 
1,402

Dividends received from subsidiaries
266,900

 
253,600

 
242,100

Other
(6,995
)
 
18,432

 
(15,065
)
Net cash flow provided by operating activities
262,804

 
239,876

 
204,096

Cash flows from investing activities
 

 
 

 
 

Construction work in progress
(3,462
)
 
—

 
—

Investments in subsidiaries
(3,491
)
 
(10,236
)
 
(3,400
)
Repayments of loans from subsidiaries
157

 
322

 
2,149

Advances of loans to subsidiaries
(1,010
)
 
(1,450
)
 
(2,099
)
Net cash flow used for investing activities
(7,806
)
 
(11,364
)
 
(3,350
)
Cash flows from financing activities
 

 
 

 
 

Issuance of long-term debt
—

 
125,000

 
—

Dividends paid on common stock
(260,027
)
 
(246,671
)
 
(235,244
)
Repayment of long-term debt
—

 
(125,000
)
 
—

Common stock equity issuance
19,373

 
15,288

 
17,319

Other
—

 
161

 
298

Net cash flow used for financing activities
(240,654
)
 
(231,222
)
 
(217,627
)
Net increase (decrease) in cash and cash equivalents
14,344

 
(2,710
)
 
(16,881
)
Cash and cash equivalents at beginning of year
3,088

 
5,798

 
22,679

Cash and cash equivalents at end of year
$
17,432

 
$
3,088

 
$
5,798


 
See Combined Notes to Consolidated Financial Statements.
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES 
SCHEDULE II — RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
 
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:
 

 
 

 
 

 
 

 
 

2015
$
3,094

 
$
4,073

 
$
—

 
$
4,042

 
$
3,125

2014
3,203

 
3,942

 
—

 
4,051

 
3,094

2013
3,340

 
4,923

 
—

 
5,060

 
3,203

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES 
ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II — RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
 
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:
 
 

 
 

 
 

 
 

 
 

2015
 
$
3,094

 
$
4,073

 
$
—

 
$
4,042

 
$
3,125

2014
 
3,203

 
3,942

 
—

 
4,051

 
3,094

2013
 
3,340

 
4,923

 
—

 
5,060

 
3,203

Summary of Significant Accounting Policies (Policies)
Description of Business and Basis of Presentation 
Description of Business and Basis of Presentation
 
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, and BCE. 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 subsidiary that was 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.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado and BCE. 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 
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 
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 
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.
 
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 
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 
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.
Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

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.
Allowance for Funds Used During Construction 
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 8.02% for 2015, 8.47% for 2014, and 8.56% for 2013.  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 
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 
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 
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 
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 Postretirement Benefits 
Retirement Plans and Other Postretirement 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 
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 May 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
 
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 
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 
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 
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 
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.

New Accounting Standards 
New Accounting Standards
 
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. The new revenue standard will be effective for us on January 1, 2018. The guidance may be adopted using a 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.

In February 2015, new consolidation accounting guidance was issued that amends many aspects of the guidance relating to the analysis and consolidation of variable interest entities. The new guidance  is effective for us, and will be adopted, during the first quarter of 2016; and may be adopted using either a full retrospective or modified retrospective approach. We do not expect the adoption of this guidance to have a material impact on our financial statements.

In January 2016, new guidance was issued relating to the recognition and measurement of financial instruments. The amended guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.
During the fourth quarter of 2015 we elected to early adopt the following accounting standard updates:
 
•
Balance sheet presentation of deferred income taxes. See Note 4.

•
Balance sheet presentation of debt issuance costs: Adopted on a retrospective basis, the new guidance requires debt issuance costs to be presented on the balance sheets as a direct reduction to the related debt liabilities. Prior to the adoption of this guidance we were required to present debt issuance costs as an asset on the balance sheets. As a result of adopting this guidance, our December 31, 2015 Consolidated Balance Sheet includes $28 million of debt issuance costs as a reduction to our long-term debt. Our December 31, 2014 Consolidated Balance Sheet presents $25 million of debt issuance costs as a reduction to long-term debt; this amount was previously presented as a component of non-current other deferred debits. The adoption of this guidance did not impact our results of operations or cash flows. Debt issuance costs continue to be amortized as interest expense. See Note 6.


Summary of Significant Accounting Policies (Tables)
Schedule of property, plant and equipment 
Pinnacle West’s property, plant and equipment included in the December 31, 2015 and 2014 consolidated balance sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2015
 
2014
Generation
$
7,336,902

 
$
7,158,729

Transmission
2,494,744

 
2,247,309

Distribution
5,543,561

 
5,339,322

General plant
847,025

 
797,703

Plant in service and held for future use
16,222,232

 
15,543,063

Accumulated depreciation and amortization
(5,594,094
)
 
(5,397,751
)
Net
10,628,138

 
10,145,312

Construction work in progress
816,307

 
682,807

Palo Verde sale leaseback, net of accumulated depreciation
117,385

 
121,255

Intangible assets, net of accumulated amortization
123,975

 
119,755

Nuclear fuel, net of accumulated amortization
123,139

 
125,201

Total property, plant and equipment
$
11,808,944

 
$
11,194,330

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,
 
2015
 
2014
 
2013
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
6,550

 
$
(102,154
)
 
$
18,537

Interest, net of amounts capitalized
170,209

 
177,074

 
184,010

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
83,798

 
$
44,712

 
$
33,184

Dividends declared but not paid
69,363

 
65,790

 
62,528

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

 
—

 
145,609


Regulatory Matters (Tables)
Schedule of changes in the deferred fuel and purchased power regulatory asset 
The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2015 and 2014 (dollars in thousands):
 
 
Year Ended December 31,
 
2015
 
2014
Beginning balance
$
6,926

 
$
20,755

Deferred fuel and purchased power costs - current period
(14,997
)
 
26,927

Amounts charged to customers
(1,617
)
 
(40,756
)
Ending balance
$
(9,688
)
 
$
6,926

Schedule of regulatory assets 
The detail of regulatory assets is as follows (dollars in thousands):
 
Amortization Through
 
December 31, 2015
 
December 31, 2014
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
619,223

 
$
—

 
$
485,037

Retired power plant costs
2033
 
9,913

 
127,518

 
9,913

 
136,182

Income taxes - AFUDC equity
2045
 
5,495

 
133,712

 
4,813

 
118,396

Deferred fuel and purchased power — mark-to-market (Note 16)
2018
 
71,852

 
69,697

 
51,209

 
46,233

Four Corners cost deferral
2024
 
6,689

 
63,582

 
6,689

 
70,565

Income taxes — investment tax credit basis adjustment
2045
 
1,766

 
48,462

 
1,716

 
46,200

Lost fixed cost recovery
2016
 
45,507

 
—

 
37,612

 
—

Palo Verde VIEs (Note 18)
2046
 
—

 
18,143

 
—

 
34,440

Deferred compensation
2036
 
—

 
34,751

 
—

 
34,162

Deferred property taxes
(d)
 
—

 
50,453

 
—

 
30,283

Loss on reacquired debt
2034
 
1,515

 
16,375

 
1,435

 
16,410

Tax expense of Medicare subsidy
2024
 
1,520

 
12,163

 
1,528

 
13,756

Transmission vegetation management
2016
 
4,543

 
—

 
9,086

 
4,543

Mead-Phoenix transmission line CIAC
2050
 
332

 
11,040

 
332

 
11,372

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

 
—

 
6,926

 
—

Coal reclamation
2026
 
418

 
6,085

 
418

 
6,503

Pension and other postretirement benefits deferral
2015
 
—

 
—

 
4,238

 
—

Other
Various
 
5

 
2,942

 
819

 
5

Total regulatory assets (e)
 
 
$
149,555

 
$
1,214,146

 
$
136,734

 
$
1,054,087


(a)
This asset represents the future recovery of pension 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.”
Schedule of regulatory liabilities 
The detail of regulatory liabilities is as follows (dollars in thousands):
 
Amortization Through
 
December 31, 2015
 
December 31, 2014
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
277,554

 
$
—

 
$
295,546

Removal costs
(a)
 
39,746

 
240,367

 
31,033

 
272,825

Other postretirement benefits
(d)
 
34,100

 
179,521

 
32,317

 
198,599

Income taxes — deferred investment tax credit
2045
 
3,604

 
97,175

 
3,505

 
92,727

Income taxes - change in rates
2045
 
1,113

 
72,454

 
371

 
72,423

Spent nuclear fuel
2047
 
3,051

 
67,437

 
4,396

 
65,594

Renewable energy standard (b)
2017
 
43,773

 
4,365

 
24,596

 
22,677

Demand side management (b)
2017
 
6,079

 
19,115

 
31,335

 
—

Sundance maintenance
2030
 
—

 
13,678

 
—

 
12,069

Deferred fuel and purchased power (b) (c)
2016
 
9,688

 
—

 
—

 
—

Deferred gains on utility property
2019
 
2,062

 
6,001

 
2,062

 
8,001

Four Corners coal reclamation
2031
 
—

 
8,920

 
—

 
1,200

Other
Various
 
2,550

 
7,565

 
934

 
9,535

Total regulatory liabilities
 
 
$
145,766

 
$
994,152

 
$
130,549

 
$
1,051,196


(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)
Subject to a carrying charge.
(d)
See Note 7.
Income Taxes (Tables)
Schedule of unrecognized tax benefits roll forward 
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):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Total unrecognized tax benefits, January 1
$
44,775

 
$
41,997

 
$
133,422

 
$
44,775

 
$
41,997

 
$
133,241

Additions for tax positions of the current year
2,175

 
4,309

 
3,516

 
2,175

 
4,309

 
3,516

Additions for tax positions of prior years
—

 
751

 
13,158

 
—

 
751

 
13,158

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(10,244
)
 
(2,282
)
 
(108,099
)
 
(10,244
)
 
(2,282
)
 
(107,918
)
Settlements with taxing authorities
—

 
—

 
—

 
—

 
—

 
—

Lapses of applicable statute of limitations
(2,259
)
 
—

 
—

 
(2,259
)
 
—

 
—

Total unrecognized tax benefits, December 31
$
34,447

 
$
44,775

 
$
41,997

 
$
34,447

 
$
44,775

 
$
41,997

Summary of unrecognized tax benefits 
Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Tax positions, that if recognized, would decrease our effective tax rate
$
9,523

 
$
11,207

 
$
9,827

 
$
9,523

 
$
11,207

 
$
9,827

The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Unrecognized tax benefit interest expense/(benefit) recognized
$
(161
)
 
$
752

 
$
(3,716
)
 
$
(161
)
 
$
752

 
$
(3,716
)

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Unrecognized tax benefit interest accrued
$
804

 
$
965

 
$
213

 
$
804

 
$
965

 
$
213

Components of income tax expense 
The components of income tax expense are as follows (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
Year Ended December 31,
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Current:
 

 
 

 
 

 
 
 
 
 
 
Federal
$
(12,335
)
 
$
25,054

 
$
(81,784
)
 
$
6,485

 
$
40,115

 
$
(97,531
)
State
4,763

 
10,382

 
10,537

 
7,813

 
15,598

 
11,983

Total current
(7,572
)
 
35,436

 
(71,247
)
 
14,298

 
55,713

 
(85,548
)
Deferred:
 

 
 

 
 

 
 

 
 

 
 

Federal
221,505

 
167,365

 
279,973

 
208,326

 
165,027

 
305,389

State
23,787

 
17,904

 
21,865

 
23,217

 
16,620

 
25,254

Total deferred
245,292

 
185,269

 
301,838

 
231,543

 
181,647

 
330,643

Income tax expense
$
237,720

 
$
220,705

 
$
230,591

 
$
245,841

 
$
237,360

 
$
245,095

Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations 
The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
 
 
Pinnacle West Consolidated
 
APS Consolidated
 
Year Ended December 31,
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Federal income tax expense at 35% statutory rate
$
242,869

 
$
225,540

 
$
234,695

 
$
250,267

 
$
239,638

 
$
246,384

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

 
 

 
 

 
 

State income tax net of federal income tax benefit
18,265

 
18,149

 
21,387

 
20,433

 
21,148

 
23,970

Credits and favorable adjustments related to prior years resolved in current year
(2,169
)
 
—

 
(3,356
)
 
(1,892
)
 
—

 
(3,231
)
Medicare Subsidy Part-D
837

 
830

 
823

 
837

 
830

 
823

Allowance for equity funds used during construction (see Note 1)
(9,711
)
 
(8,523
)
 
(6,997
)
 
(9,711
)
 
(8,523
)
 
(6,997
)
Palo Verde VIE noncontrolling interest (see Note 18)
(6,626
)
 
(9,135
)
 
(11,862
)
 
(6,626
)
 
(9,135
)
 
(11,862
)
Investment tax credit amortization
(5,527
)
 
(4,928
)
 
(3,548
)
 
(5,527
)
 
(4,928
)
 
(3,548
)
Other
(218
)
 
(1,228
)
 
(551
)
 
(1,940
)
 
(1,670
)
 
(444
)
Income tax expense
$
237,720

 
$
220,705

 
$
230,591

 
$
245,841

 
$
237,360

 
$
245,095

Net deferred income tax liability recognized on the Consolidated Balance Sheets 
The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
December 31,
 
December 31,
 
2015
 
2014
 
2015
 
2014
Current asset
$
—

 
$
122,232

 
$
—

 
$
55,253

Long-term liability
(2,723,425
)
 
(2,582,636
)
 
(2,764,489
)
 
(2,571,365
)
Deferred income taxes — net
$
(2,723,425
)
 
$
(2,460,404
)
 
$
(2,764,489
)
 
$
(2,516,112
)
Components of the net deferred income tax liability 
The components of the net deferred income tax liability were as follows (dollars in thousands):
 
 
Pinnacle West Consolidated
 
APS Consolidated
 
December 31,
 
December 31,
 
2015
 
2014
 
2015
 
2014
DEFERRED TAX ASSETS
 

 
 

 
 
 
 
Risk management activities
$
70,498

 
$
57,505

 
$
70,498

 
$
57,505

Regulatory liabilities:
 

 
 

 
 

 
 
Asset retirement obligation and removal costs
216,765

 
229,772

 
216,765

 
229,772

Unamortized investment tax credits
100,779

 
96,232

 
100,779

 
96,232

Other postretirement benefits
83,034

 
90,496

 
83,034

 
90,496

Other
60,707

 
60,409

 
60,707

 
60,409

Pension liabilities
191,028

 
205,227

 
181,787

 
194,541

Renewable energy incentives
60,956

 
65,169

 
60,956

 
65,169

Credit and loss carryforwards
59,557

 
68,347

 
—

 
—

Other
149,033

 
138,729

 
176,016

 
161,379

Total deferred tax assets
992,357

 
1,011,886

 
950,542

 
955,503

DEFERRED TAX LIABILITIES
 

 
 

 
 

 
 
Plant-related
(3,116,752
)
 
(2,958,369
)
 
(3,116,752
)
 
(2,958,369
)
Risk management activities
(10,626
)
 
(12,171
)
 
(10,626
)
 
(12,171
)
Other postretirement assets
(71,737
)
 
(59,170
)
 
(70,986
)
 
(58,495
)
Regulatory assets:
 

 
 

 
 
 
 

Allowance for equity funds used during construction
(54,110
)
 
(48,286
)
 
(54,110
)
 
(48,286
)
Deferred fuel and purchased power
—

 
(2,498
)
 
—

 
(2,498
)
Deferred fuel and purchased power — mark-to-market
(55,020
)
 
(38,187
)
 
(55,020
)
 
(38,187
)
Pension benefits
(240,692
)
 
(191,747
)
 
(240,692
)
 
(191,747
)
Retired power plant costs (see Note 3)
(53,420
)
 
(57,255
)
 
(53,420
)
 
(57,255
)
Other
(108,441
)
 
(99,123
)
 
(108,441
)
 
(99,123
)
Other
(4,984
)
 
(5,484
)
 
(4,984
)
 
(5,484
)
Total deferred tax liabilities
(3,715,782
)
 
(3,472,290
)
 
(3,715,031
)
 
(3,471,615
)
Deferred income taxes — net
$
(2,723,425
)
 
$
(2,460,404
)
 
$
(2,764,489
)
 
$
(2,516,112
)
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, 2015 and 2014 (dollars in thousands):
 
 
December 31, 2015
 
December 31, 2014
 
Pinnacle West
APS
Total
 
Pinnacle West
APS
Total
Commitments under Credit Facility
$
200,000

$
1,000,000

$
1,200,000

 
$
200,000

$
1,000,000

$
1,200,000

Outstanding Commercial Paper Borrowings
—

—

—

 
—

(147,400
)
(147,400
)
Amount of Credit Facility Available
$
200,000

$
1,000,000

$
1,200,000

 
$
200,000

$
852,600

$
1,052,600

 
 
 
 
 
 
 
 
Weighted-Average Commitment Fees
0.125%
0.100%
 
 
0.175%
0.125%
 

Long-Term Debt and Liquidity Matters (Tables)
Components of long-term debt on the Consolidated Balance Sheets 
The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2015 and 2014 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2015
 
2014
APS
 
 
 
 
 

 
 

Pollution control bonds:
 
 
 
 
 

 
 

Variable
2029-2038
 
(b)
 
$
92,405

 
$
156,405

Fixed
2024-2034
 
1.75%-5.75%
 
211,150

 
249,300

Total pollution control bonds
 
 
 
 
303,555

 
405,705

Senior unsecured notes
2016-2045
 
2.20%-8.75%
 
3,375,000

 
2,875,000

Palo Verde sale leaseback lessor notes
2015
 
8.00%
 
—

 
13,420

Term loan
2018
 
(c)
 
50,000

 
—

Unamortized discount
 
 
 
 
(10,374
)
 
(9,206
)
Unamortized premium
 
 
 
 
4,686

 
4,866

Unamortized debt issuance cost
(d)
 
 
 
(27,896
)
 
(24,642
)
Total APS long-term debt
 
 
 
 
3,694,971

 
3,265,143

Less current maturities
(e)
 
 
 
357,580

 
383,570

Total APS long-term debt less current maturities
 
 
 
 
3,337,391

 
2,881,573

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(f)
 
125,000

 
125,000

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
3,462,391

 
$
3,006,573


(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 0.01%-0.24% at December 31, 2015 and 0.03%-0.27% at December 31, 2014.
(c)
The weighted-average interest rate was 1.024% at December 31, 2015.
(d)
In the fourth quarter of 2015, we adopted a new accounting standard related to balance sheet presentation of debt issuance costs. See Note 2 for additional details.
(e)                                  Current maturities include $108 million of pollution control bonds expected to be remarketed in 2016 and $250 million in senior unsecured notes that mature in 2016.
(f)                                 The weighted-average interest rate was 1.174% at December 31, 2015 and 1.019% at December 31, 2014.

Principal payments due on Pinnacle West's and APS's total long-term debt 
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):
Year
 
Consolidated
Pinnacle West
 
Consolidated
APS
2016
 
$
357,580

 
$
357,580

2017
 
125,000

 
—

2018
 
82,000

 
82,000

2019
 
500,000

 
500,000

2020
 
250,000

 
250,000

Thereafter
 
2,538,975

 
2,538,975

Total
 
$
3,853,555

 
$
3,728,555

Schedule of estimated fair value of long-term debt, including current maturities 
The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
 
 
As of
December 31, 2015
 
As of
December 31, 2014
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
3,694,971

 
3,981,367

 
3,265,143

 
3,714,108

Total
$
3,819,971

 
$
4,106,367

 
$
3,390,143

 
$
3,839,108

Retirement Plans and Other Benefits (Tables)
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) 
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):
 
Pension
 
Other Benefits
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Service cost-benefits earned during the period
$
59,627

 
$
53,080

 
$
64,195

 
$
16,827

 
$
18,139

 
$
23,597

Interest cost on benefit obligation
123,983

 
129,194

 
112,392

 
28,102

 
41,243

 
41,536

Expected return on plan assets
(179,231
)
 
(158,998
)
 
(146,333
)
 
(36,855
)
 
(46,400
)
 
(45,717
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
594

 
869

 
1,097

 
(37,968
)
 
(9,626
)
 
(179
)
Net actuarial loss
31,056

 
10,963

 
39,852

 
4,881

 
1,175

 
11,310

Net periodic benefit cost
$
36,029

 
$
35,108

 
$
71,203

 
$
(25,013
)
 
$
4,531

 
$
30,547

Portion of cost charged to expense
$
20,036

 
$
21,985

 
$
38,968

 
$
(10,391
)
 
$
6,000

 
$
18,469

Schedule of changes in the benefit obligations and funded status 
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2015 and 2014 (dollars in thousands):
 
Pension
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
3,078,648

 
$
2,646,530

 
$
682,335

 
$
890,418

Service cost
59,627

 
53,080

 
16,827

 
18,139

Interest cost
123,983

 
129,194

 
28,102

 
41,243

Benefit payments
(137,115
)
 
(128,550
)
 
(24,988
)
 
(29,054
)
Actuarial (gain) loss
(91,340
)
 
378,394

 
(55,256
)
 
150,188

Plan amendments
—

 
—

 
—

 
(388,599
)
Benefit obligation at December 31
3,033,803

 
3,078,648

 
647,020

 
682,335

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,615,404

 
2,264,121

 
834,625

 
748,339

Actual return on plan assets
(44,690
)
 
292,992

 
(2,399
)
 
105,223

Employer contributions
100,000

 
175,000

 
791

 
770

Benefit payments
(127,940
)
 
(116,709
)
 
—

 
(19,707
)
Fair value of plan assets at December 31
2,542,774

 
2,615,404

 
833,017

 
834,625

Funded Status at December 31
$
(491,029
)
 
$
(463,244
)
 
$
185,997

 
$
152,290

Schedule of projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets 
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, 2015 and 2014 (dollars in thousands):
 
2015
 
2014
Projected benefit obligation
$
3,033,803

 
$
3,078,648

Accumulated benefit obligation
2,873,467

 
2,873,741

Fair value of plan assets
2,542,774

 
2,615,404

Schedule of amounts recognized on the Consolidated Balance Sheets 
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2015 and 2014 (dollars in thousands):
 
Pension
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
Noncurrent asset
$
—

 
$
—

 
$
185,997

 
$
152,290

Current liability
(10,031
)
 
(9,508
)
 
—

 
—

Noncurrent liability
(480,998
)
 
(453,736
)
 
—

 
—

Net amount recognized
$
(491,029
)
 
$
(463,244
)
 
$
185,997

 
$
152,290

Schedule of accumulated other comprehensive loss 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2015 and 2014 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
Net actuarial loss
$
679,501

 
$
577,976

 
$
127,124

 
$
148,006

Prior service cost (credit)
609

 
1,203

 
(341,301
)
 
(379,269
)
APS’s portion recorded as a regulatory (asset) liability
(619,223
)
 
(485,037
)
 
213,621

 
230,916

Income tax expense (benefit)
(23,663
)
 
(36,890
)
 
925

 
851

Accumulated other comprehensive loss
$
37,224

 
$
57,252

 
$
369

 
$
504

Schedule of estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost 
The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2016 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
38,923

 
$
3,784

Prior service cost (credit)
527

 
(37,884
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2016
$
39,450

 
$
(34,100
)
Schedule of weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs 
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,
 
2015
 
2014
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
January - September
October - December
 
 
Discount rate – pension
4.37
%
 
4.02
%
 
4.02
%
 
4.88
%
4.88
%
 
4.01
%
Discount rate – other benefits
4.52
%
 
4.14
%
 
4.14
%
 
5.10
%
4.41
%
 
4.20
%
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
%
6.90
%
 
7.00
%
Expected long-term return on plan assets - other benefits
N/A

 
N/A

 
4.45
%
 
6.80
%
4.25
%
 
7.00
%
Initial healthcare cost trend rate (pre-65 participants)
7.00
%
 
7.00
%
 
7.00
%
 
7.50
%
7.50
%
 
7.50
%
Initial healthcare cost trend rate (post-65 participants)
5.00
%
 
5.00
%
 
5.00
%
 
7.50
%
5.00
%
 
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

 
0

 
0

 
4

0

 
4

Schedule of effects of one percentage point change in the assumed initial and ultimate health care cost trend rates 
A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in thousands): 
 
1% Increase
 
1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
$
8,834

 
$
(5,890
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
9,069

 
(6,949
)
Effect on the accumulated other postretirement benefit obligation
100,322

 
(80,332
)
Schedule of fair value of pension plan and other postretirement benefit plan assets, by asset category 
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, 2015, 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, 2015
Pension Plan:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
1,893

 
$
—

 
$
—

 
$
—

 
$
1,893

Fixed income securities:
 

 
 

 
 

 
 

 
 

Corporate
—

 
1,108,736

 
—

 
—

 
1,108,736

U.S. Treasury
274,778

 
—

 
—

 
—

 
274,778

Other (a)
—

 
113,008

 
—

 
—

 
113,008

Equities:
 

 
 

 
 

 
 

 
 

U.S. companies
233,021

 
—

 
—

 
—

 
233,021

International companies
14,680

 
—

 
—

 
—

 
14,680

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. equities
—

 
130,097

 
—

 
—

 
130,097

International equities
—

 
185,892

 
—

 
—

 
185,892

Real estate
—

 
150,359

 
—

 
—

 
150,359

Partnerships
—

 
127,840

 
42,097

 
—

 
169,937

Mutual funds - International equities
116,307

 
—

 
—

 
—

 
116,307

Short-term investments and other
—

 
29,599

 
—

 
14,467

 
44,066

Total Pension Plan
$
640,679

 
$
1,845,531

 
$
42,097

 
$
14,467

 
$
2,542,774

Other Benefits:
 

 
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
240

 
$
—

 
$
—

 
$
—

 
$
240

Fixed income securities:
 

 
 

 
 

 
 

 
 

Corporate
—

 
217,026

 
—

 
—

 
217,026

U.S. Treasury
131,435

 
—

 
—

 
—

 
131,435

Other (a)
—

 
31,106

 
—

 
—

 
31,106

Equities:
 

 
 

 
 

 
 

 
 

U.S. companies
253,193

 
—

 
—

 
—

 
253,193

International companies
12,390

 
—

 
—

 
—

 
12,390

Common and collective trusts:
 

 
 

 
 

 
 

 
 

U.S. equities
—

 
81,516

 
—

 
—

 
81,516

International equities
—

 
28,539

 
—

 
—

 
28,539

Real estate
—

 
13,512

 
—

 
—

 
13,512

Mutual funds - International equities
52,568

 
—

 
—

 
—

 
52,568

Short-term investments and other
5,065

 
3,331

 
—

 
3,096

 
11,492

Total Other Benefits
$
454,891

 
$
375,030

 
$
—

 
$
3,096

 
$
833,017


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

Schedule of changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) 
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, 2015 and 2014 (dollars in thousands):
 
 
Pension
Partnerships
 
2015
 
2014
Beginning balance at January 1
 
$
27,929

 
$
8,660

Actual return on assets still held at December 31
 
2,789

 
927

Purchases
 
13,187

 
19,984

Sales
 
(1,808
)
 
(1,642
)
Transfers in and/or out of Level 3
 
—

 
—

Ending balance at December 31
 
$
42,097

 
$
27,929

Schedule of estimated future benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter 
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
2016
 
$
152,146

 
$
26,468

2017
 
171,005

 
28,444

2018
 
170,534

 
30,490

2019
 
180,700

 
32,438

2020
 
188,988

 
33,982

Years 2021-2025
 
1,023,451

 
184,335

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 thousands):
Year
 
Pinnacle West
Consolidated
 
APS
2016
 
$
9,182

 
$
8,797

2017
 
8,557

 
8,317

2018
 
7,045

 
6,880

2019
 
6,121

 
5,961

2020
 
4,835

 
4,680

Thereafter
 
61,251

 
61,101

Total future lease commitments
 
$
96,991

 
$
95,736

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, 2015 (dollars in thousands):

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

 
 
 
 

 
 

 
 

Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,744,137

 
$
1,067,376

 
$
22,228

Palo Verde Unit 2 (a)
 
16.8
%
 

 
583,633

 
356,767

 
4,142

Palo Verde Common
 
28.0
%
 
(b)
 
643,201

 
231,609

 
64,069

Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
233,665

 
—

Four Corners Generating Station
 
63.0
%
 

 
857,555

 
577,321

 
77,317

Navajo Generating Station Units 1, 2 and 3
 
14.0
%
 

 
274,640

 
168,132

 
4,460

Cholla common facilities (c)
 
63.3
%
 
(b)
 
158,623

 
53,777

 
1,390

Transmission facilities:
 
 

 
 
 
 

 
 

 
 

ANPP 500kV System
 
33.4
%
 
 (b)
 
109,348

 
36,576

 
1,594

Navajo Southern System
 
22.7
%
 
(b)
 
62,139

 
19,361

 
397

Palo Verde — Yuma 500kV System
 
19.3
%
 
(b)
 
14,043

 
5,226

 
133

Four Corners Switchyards
 
49.8
%
 
 (b)
 
38,420

 
9,833

 
1,687

Phoenix — Mead System
 
17.1
%
 
(b)
 
39,089

 
13,173

 
151

Palo Verde — Estrella 500kV System
 
50.0
%
 
(b)
 
89,832

 
18,359

 
1,008

Morgan — Pinnacle Peak System
 
64.6
%
 
 (b)
 
129,855

 
11,087

 
2,592

Round Valley System
 
50.0
%
 
(b)
 
703

 
286

 
—

Palo Verde — Morgan System
 
87.7
%
 
(b)
 
12

 
—

 
133,813

Hassayampa - North Gila System
 
80.0
%
 
(b)
 
164,854

 
1,159

 
—

Cholla 500 Switchyard
 
85.7
%
 
(b)
 
547

 
15

 
—

Saguaro 500 Switchyard
 
75.0
%
 
(b)
 
773

 
26

 
—


(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)
Summary of estimated coal take-or-pay commitments 
The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):
 
 
 Years Ended December 31,
 
2016
 
2017
 
2018
 
2019
 
2020
 
Thereafter
Coal take-or-pay commitments (a)
$
170,714

 
$
195,428

 
$
189,588

 
$
193,818

 
$
198,160

 
$
2,270,974

 
(a)
Total take-or-pay commitments are approximately $3.2 billion.  The total net present value of these commitments is approximately $2.2 billion.
Summary of actual take-or-pay commitments 
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 thousands):
 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Total payments
$
211,327

 
$
236,773

 
$
188,496

Asset Retirement Obligations (Tables)
Change in asset retirement obligations
The following table shows the change in our asset retirement obligations for 2015 and 2014 (dollars in thousands):

 
2015
 
2014
Asset retirement obligations at the beginning of year
$
390,750

 
$
346,729

Changes attributable to:
 

 
 

Accretion expense
25,163

 
23,567

Settlements
(32,048
)
 
(29,497
)
Estimated cash flow revisions
17,556

 
43,899

Newly incurred obligation
42,155

 
6,052

Asset retirement obligations at the end of year
$
443,576

 
$
390,750

Selected Quarterly Financial Data (Unaudited) (Tables)
Schedule of quarterly financial information 
Consolidated quarterly financial information for 2015 and 2014 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.

 
2015 Quarter Ended
 
2015
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
671,219

 
$
890,648

 
$
1,199,146

 
$
734,430

 
$
3,495,443

Operations and maintenance
214,944

 
210,965

 
220,449

 
222,019

 
868,377

Operating income
67,684

 
231,973

 
445,111

 
109,834

 
854,602

Income taxes
7,947

 
67,371

 
139,555

 
22,847

 
237,720

Net income
20,727

 
127,507

 
261,978

 
45,978

 
456,190

Net income attributable to common shareholders
16,122

 
122,902

 
257,116

 
41,117

 
437,257

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.15

 
$
1.11

 
$
2.32

 
$
0.37

 
$
3.94

Net income attributable to common shareholders — Diluted
0.14

 
1.10

 
2.30

 
0.37

 
3.92

 
 
2014 Quarter Ended
 
2014
 
March 31,
 
June 30,
 
September 30,
 
December 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

Net income
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

Schedule of quarterly financial information 
APS's quarterly financial information for 2015 and 2014 is as follows (dollars in thousands):
 
 
2015 Quarter Ended,
 
2015
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
670,668

 
$
889,723

 
$
1,198,380

 
$
733,586

 
$
3,492,357

Operations and maintenance
209,947

 
208,031

 
216,011

 
219,146

 
853,135

Operating income
61,333

 
162,704

 
301,238

 
86,709

 
611,984

Net income attributable to common shareholder
19,868

 
125,362

 
261,187

 
43,857

 
450,274

 
 
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

Fair Value Measurements (Tables)
Fair value of assets and liabilities that are measured at fair value on a recurring basis 
The following table presents the fair value at December 31, 2015 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

 
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, 2015
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
22,992

 
$
30,364

 
$
(25,345
)
 
(b)
 
$
28,011

Nuclear decommissioning trust:
 

 
 

 
 

 
 
 
 
 
 

U.S. commingled equity funds
—

 
314,957

 
—

 
—

 

 
314,957

Fixed income securities:
 

 
 

 
 

 
 
 
 
 
 

     Cash and cash equivalent funds
12,260

 
—

 
—

 
(335
)
 
(c)
 
11,925

U.S. Treasury
117,245

 
—

 
—

 
—

 
 
 
117,245

Corporate debt
—

 
96,243

 
—

 
—

 
 
 
96,243

Mortgage-backed securities
—

 
99,065

 
—

 
—

 
 
 
99,065

Municipal bonds
—

 
72,206

 
—

 
—

 
 
 
72,206

Other
—

 
23,555

 
—

 
—

 
 
 
23,555

Subtotal nuclear decommissioning trust
129,505

 
606,026

 
—

 
(335
)
 

 
735,196

Total
$
129,505

 
$
629,018

 
$
30,364

 
$
(25,680
)
 

 
$
763,207

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(144,044
)
 
$
(63,343
)
 
$
39,698

 
(b)
 
$
(167,689
)

(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, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
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
$
—

 
$
20,769

 
$
32,598

 
$
(21,962
)
 
(b)
 
$
31,405

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
309,620

 
—

 
—

 

 
309,620

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

U.S. Treasury
118,843

 
—

 
—

 
—

 
 
 
118,843

Cash and cash equivalent funds
—

 
11,453

 
—

 
(7,245
)
 
(c)
 
4,208

Corporate debt
—

 
109,379

 
—

 
—

 
 
 
109,379

Mortgage-backed securities
—

 
88,465

 
—

 
—

 
 
 
88,465

Municipal bonds
—

 
69,139

 
—

 
—

 
 
 
69,139

Other
—

 
14,212

 
—

 
—

 
 
 
14,212

Subtotal nuclear decommissioning trust
118,843

 
602,268

 
—

 
(7,245
)
 

 
713,866

Total
$
118,843

 
$
623,037

 
$
32,598

 
$
(29,207
)
 

 
$
745,271

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(95,061
)
 
$
(73,984
)
 
$
58,767

 
(b)
 
$
(110,278
)

(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 purch
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments 
s.
 
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2015 and December 31, 2014:
 
 
December 31, 2015
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
24,543

 
$
54,679

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$15.92 - $40.73
 
$
26.86

Option Contracts (b)
—

 
5,628

 
Option model
 
Electricity forward price (per MWh)
 
$23.87 - $44.13
 
$
33.91

 
 

 
 

 
 
 
Electricity price volatilities
 
40% - 59%
 
52
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
32% - 40%
 
35
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
5,821

 
3,036

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.18 - $3.14
 
$
2.61

Total
$
30,364

 
$
63,343

 
 
 
 
 
 
 
 


(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, 2014
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
29,471

 
$
55,894

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

Option Contracts (b)
—

 
15,035

 
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)
3,127

 
3,055

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

Total
$
32,598

 
$
73,984

 
 
 
 
 
 
 
 


(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 volatili
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs 
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2015 and 2014 (dollars in thousands):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2015
 
2014
Net derivative balance at beginning of period
 
$
(41,386
)
 
$
(49,165
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 
—

 
102

Included in OCI
 
(452
)
 
(239
)
Deferred as a regulatory asset or liability
 
(4,009
)
 
(482
)
Settlements
 
14,809

 
12,080

Transfers into Level 3 from Level 2
 
(6,256
)
 
(2,090
)
Transfers from Level 3 into Level 2
 
4,315

 
(1,592
)
Net derivative balance at end of period
 
$
(32,979
)
 
$
(41,386
)
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, 2015, 2014 and 2013 (in thousands, except per share amounts):
 
2015
 
2014
 
2013
Net income attributable to common shareholders
$
437,257

 
$
397,595

 
$
406,074

Weighted average common shares outstanding — basic
111,026

 
110,626

 
109,984

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
526

 
552

 
822

Weighted average common shares outstanding — diluted
111,552

 
111,178

 
110,806

Earnings per average common share attributable to common shareholders — basic
$
3.94

 
$
3.59

 
$
3.69

Earnings per average common share attributable to common shareholders — diluted
$
3.92

 
$
3.58

 
$
3.66

Stock-Based Compensation (Tables)
Summary of Nonvested Restricted Stock, Stock Grants and Stock Units 
The following table is a summary of the status of non-vested awards as of December 31, 2015 and changes during the year.

 
Restricted Stock Units, Stock Grants, and Stock Units
 
Performance Shares
 
Shares
 
Weighted-Average
Grant Date
Fair Value
 
Shares (b)
 
Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2015
480,933

(a)
$
51.27

 
324,230

 
$
54.92

Granted
152,651

 
64.12

 
151,430

 
64.97

Change in performance factor
—

 
—

 
40,496

 
54.98

Vested
(198,424
)
 
49.20

 
(202,480
)
 
54.98

Forfeited
(6,873
)
 
56.78

 
(7,844
)
 
57.89

Nonvested at December 31, 2015
428,287

 
56.69

 
305,832

 
59.78

Vested Awards Outstanding at December 31, 2015
106,712

 


 
202,480

 



 
(a)
Includes 127,634 of awards that will be cash settled and 353,299 of awards that will be settled in shares.
(b)
Nonvested performance 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.

The following table is a summary of awards granted and the weighted-average fair value for the three years ended 2015, 2014 and 2013.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Units granted
152,651

 
179,291

 
182,240

 
151,430

 
166,244

 
176,332

Weighted-average grant date fair value
$
64.12

 
$
54.89

 
$
55.14

 
$
64.97

 
$
54.86

 
$
55.45

(a)
Units granted includes awards that will be cash settled of 45,104 in 2015, 49,018 in 2014, and 52,620 in 2013.
(b)
Reflects the target payout level.
Summary of Nonvested Performance Shares 
The following table is a summary of awards granted and the weighted-average fair value for the three years ended 2015, 2014 and 2013.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Units granted
152,651

 
179,291

 
182,240

 
151,430

 
166,244

 
176,332

Weighted-average grant date fair value
$
64.12

 
$
54.89

 
$
55.14

 
$
64.97

 
$
54.86

 
$
55.45

(a)
Units granted includes awards that will be cash settled of 45,104 in 2015, 49,018 in 2014, and 52,620 in 2013.
(b)
Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2015 and changes during the year.

 
Restricted Stock Units, Stock Grants, and Stock Units
 
Performance Shares
 
Shares
 
Weighted-Average
Grant Date
Fair Value
 
Shares (b)
 
Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2015
480,933

(a)
$
51.27

 
324,230

 
$
54.92

Granted
152,651

 
64.12

 
151,430

 
64.97

Change in performance factor
—

 
—

 
40,496

 
54.98

Vested
(198,424
)
 
49.20

 
(202,480
)
 
54.98

Forfeited
(6,873
)
 
56.78

 
(7,844
)
 
57.89

Nonvested at December 31, 2015
428,287

 
56.69

 
305,832

 
59.78

Vested Awards Outstanding at December 31, 2015
106,712

 


 
202,480

 



 
(a)
Includes 127,634 of awards that will be cash settled and 353,299 of awards that will be settled in shares.
(b)
Nonvested performance 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)
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) 
As of December 31, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
Commodity
 
Quantity
Power
 
2,487

 
GWh
Gas
 
182

 
Billion cubic feet
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2015, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2015
 
2014
 
2013
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(615
)
 
$
(372
)
 
$
(353
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(5,988
)
 
(21,415
)
 
(44,219
)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Fuel and purchased power (b)
 
—

 
—

 
—


(a)
During the years ended December 31, 2015, 2014, and 2013, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments 
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2015, 2014 and 2013 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2015
 
2014
 
2013
Net Gain Recognized in Income
 
Operating revenues
 
$
574

 
$
324

 
$
289

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(108,973
)
 
(66,367
)
 
(10,449
)
Total
 
 
 
$
(108,399
)
 
$
(66,043
)
 
$
(10,160
)

(a)
Amounts are before the effect of PSA deferrals.
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting liabilities 
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, 2015 and 2014.  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, 2015:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
37,396

 
$
(22,163
)
 
$
15,233

 
$
672

 
$
15,905

Investments and other assets
 
15,960

 
(3,854
)
 
12,106

 
—

 
12,106

Total assets
 
53,356

 
(26,017
)
 
27,339

 
672

 
28,011

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(113,560
)
 
40,223

 
(73,337
)
 
(4,379
)
 
(77,716
)
Deferred credits and other
 
(93,827
)
 
3,854

 
(89,973
)
 
—

 
(89,973
)
Total liabilities
 
(207,387
)
 
44,077

 
(163,310
)
 
(4,379
)
 
(167,689
)
Total
 
$
(154,031
)
 
$
18,060

 
$
(135,971
)
 
$
(3,707
)
 
$
(139,678
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $18,060.
(c)
Represents cash collateral and cash 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 $4,379, and cash margin provided to counterparties of $672.
 
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
 
$
28,557

 
$
(15,127
)
 
$
13,430

 
$
355

 
$
13,785

Investments and other assets
 
24,810

 
(7,190
)
 
17,620

 
—

 
17,620

Total assets
 
53,367

 
(22,317
)
 
31,050

 
355

 
31,405

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(86,055
)
 
33,829

 
(52,226
)
 
(7,443
)
 
(59,669
)
Deferred credits and other
 
(82,990
)
 
32,388

 
(50,602
)
 
—

 
(50,602
)
Total liabilities
 
(169,045
)
 
66,217

 
(102,828
)
 
(7,443
)
 
(110,271
)
Total
 
$
(115,678
)
 
$
43,900

 
$
(71,778
)
 
$
(7,088
)
 
$
(78,866
)

(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 $355.
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting assets 
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, 2015 and 2014.  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, 2015:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
37,396

 
$
(22,163
)
 
$
15,233

 
$
672

 
$
15,905

Investments and other assets
 
15,960

 
(3,854
)
 
12,106

 
—

 
12,106

Total assets
 
53,356

 
(26,017
)
 
27,339

 
672

 
28,011

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(113,560
)
 
40,223

 
(73,337
)
 
(4,379
)
 
(77,716
)
Deferred credits and other
 
(93,827
)
 
3,854

 
(89,973
)
 
—

 
(89,973
)
Total liabilities
 
(207,387
)
 
44,077

 
(163,310
)
 
(4,379
)
 
(167,689
)
Total
 
$
(154,031
)
 
$
18,060

 
$
(135,971
)
 
$
(3,707
)
 
$
(139,678
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $18,060.
(c)
Represents cash collateral and cash 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 $4,379, and cash margin provided to counterparties of $672.
 
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
 
$
28,557

 
$
(15,127
)
 
$
13,430

 
$
355

 
$
13,785

Investments and other assets
 
24,810

 
(7,190
)
 
17,620

 
—

 
17,620

Total assets
 
53,367

 
(22,317
)
 
31,050

 
355

 
31,405

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(86,055
)
 
33,829

 
(52,226
)
 
(7,443
)
 
(59,669
)
Deferred credits and other
 
(82,990
)
 
32,388

 
(50,602
)
 
—

 
(50,602
)
Total liabilities
 
(169,045
)
 
66,217

 
(102,828
)
 
(7,443
)
 
(110,271
)
Total
 
$
(115,678
)
 
$
43,900

 
$
(71,778
)
 
$
(7,088
)
 
$
(78,866
)

(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 $355.
Information about derivative instruments that have credit-risk-related contingent features 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2015 (dollars in thousands):
 
 
December 31, 2015
Aggregate fair value of derivative instruments in a net liability position
$
207,387

Cash collateral posted
18,060

Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)
112,301


(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)
Detail of other income and other expense 
The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2015, 2014 and 2013 (dollars in thousands):
 
 
2015
 
2014
 
2013
Other income:
 

 
 

 
 

Interest income
$
493

 
$
1,010

 
$
1,629

Debt return on the purchase of Four Corners units 4 & 5
—

 
8,386

 
—

Miscellaneous
128

 
212

 
75

Total other income
$
621

 
$
9,608

 
$
1,704

Other expense:
 

 
 

 
 

Non-operating costs
$
(11,292
)
 
$
(9,657
)
 
$
(8,207
)
Investment loss — net
(2,080
)
 
(9,426
)
 
(3,711
)
Miscellaneous
(4,451
)
 
(2,663
)
 
(4,106
)
Total other expense
$
(17,823
)
 
$
(21,746
)
 
$
(16,024
)
Detail of other income and other expense 
The following table provides detail of APS’s other income and other expense for 2015, 2014 and 2013 (dollars in thousands):
 
 
2015
 
2014
 
2013
Other income:
 

 
 

 
 

Interest income
$
163

 
$
689

 
$
1,234

Debt return on the purchase of Four Corners units 4 & 5
—

 
8,386

 
—

Gain on disposition of property
716

 
1,197

 
1,024

Miscellaneous
1,955

 
1,023

 
1,638

Total other income
$
2,834

 
$
11,295

 
$
3,896

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(11,648
)
 
$
(10,397
)
 
$
(9,626
)
Loss on disposition of property
(2,219
)
 
(615
)
 
(4,992
)
Miscellaneous
(5,152
)
 
(2,391
)
 
(5,831
)
Total other expense
$
(19,019
)
 
$
(13,403
)
 
$
(20,449
)

(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, 2015 and December 31, 2014 include the following amounts relating to the VIEs (dollars in thousands):
 
 
December 31, 2015
 
December 31, 2014
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation
$
117,385

 
$
121,255

Current maturities of long-term debt
—

 
13,420

Equity-Noncontrolling interests
135,540

 
151,609

Nuclear Decommissioning Trusts (Tables)
Fair value of APS's nuclear decommissioning trust fund assets 
The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2015 and December 31, 2014 (dollars in thousands):
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2015
 

 
 

 
 

Equity securities
$
314,957

 
$
157,098

 
$
(115
)
Fixed income securities
420,574

 
11,955

 
(2,645
)
Net payables (a)
(335
)
 
—

 
—

Total
$
735,196

 
$
169,053

 
$
(2,760
)
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2014
 

 
 

 
 

Equity securities
$
309,620

 
$
159,274

 
$
(15
)
Fixed income securities
411,491

 
17,260

 
(1,073
)
Net payables (a)
(7,245
)
 
—

 
—

Total
$
713,866

 
$
176,534

 
$
(1,088
)

(a)
Net payables relate to pending purchases and sales of securities.
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds 
The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):
 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Realized gains
$
5,189

 
$
4,725

 
$
5,459

Realized losses
(6,225
)
 
(4,525
)
 
(6,706
)
Proceeds from the sale of securities (a)
478,813

 
356,195

 
446,025


(a)
Proceeds are reinvested in the trust.
Fair value of fixed income securities, summarized by contractual maturities 
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2015 is as follows (dollars in thousands):
 
 
Fair Value
Less than one year
$
14,001

1 year – 5 years
117,356

5 years – 10 years
114,769

Greater than 10 years
174,448

Total
$
420,574

Changes in Accumulated Other Comprehensive Loss (Tables)
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component 
The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2015 and 2014 (dollars in thousands): 
 
Year Ended December 31,
 
2015
 
2014
Balance at beginning of period
$
(68,141
)
 
$
(78,053
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(957
)
 
(810
)
Amounts reclassified from accumulated other comprehensive loss (a)
4,187

 
13,483

Net current period OCI (loss)
3,230

 
12,673

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
16,980

 
(5,419
)
Amounts reclassified from accumulated other comprehensive loss (b)
3,183

 
2,658

Net current period OCI (loss)
20,163

 
(2,761
)
Balance at end of period
$
(44,748
)
 
$
(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.
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component 
The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2015 and 2014 (dollars in thousands): 
 
Year Ended December 31,
 
2015
 
2014
Balance at beginning of period
$
(48,333
)
 
$
(53,372
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(957
)
 
(809
)
Amounts reclassified from accumulated other comprehensive loss (a)
4,187

 
13,483

Net current period OCI (loss)
3,230

 
12,674

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
14,726

 
(10,415
)
Amounts reclassified from accumulated other comprehensive loss (b)
3,280

 
2,780

Net current period OCI (loss)
18,006

 
(7,635
)
Balance at end of period
$
(27,097
)
 
$
(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.
Summary of Significant Accounting Policies - Narrative (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 1 Months Ended 36 Months Ended 12 Months Ended 36 Months Ended 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
May 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Pinnacle West
Dec. 31, 2015
Minimum
Dec. 31, 2015
Maximum
Dec. 31, 2015
Maximum
Dec. 31, 2015
Fossil plant
Dec. 31, 2015
Nuclear plant
Dec. 31, 2015
Other generation
Dec. 31, 2015
Transmission
Dec. 31, 2015
Distribution
Dec. 31, 2015
Other
Approximate remaining average useful lives of utility property
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average useful life
 
 
 
 
 
 
 
 
 
19 years 
28 years 
25 years 
39 years 
33 years 
7 years 
Cost of services, depreciation
$ 430 
$ 396 
$ 400 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation rates (as a percent)
2.74% 
2.77% 
3.00% 
 
 
 
0.30% 
 
12.37% 
 
 
 
 
 
 
Allowance for Funds Used During Construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Composite rate used to calculate AFUDC (as a percent)
8.02% 
8.47% 
8.56% 
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear Fuel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh)
 
 
 
0.001 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percent likelihood largest tax benefit amount is realized (greater than)
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Intangible Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization expense
58 
53 
53 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated amortization expense on existing intangible assets over the next five years
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016
48 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
36 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
18 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$ 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average remaining amortization period for intangible assets
5 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 - Summary of Property, Plant and Equipment (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Utility Plant and Depreciation [Line Items]
 
 
Net
$ 10,628,138 
$ 10,145,312 
Construction work in progress
816,307 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation
117,385 
121,255 
Intangible assets, net of accumulated amortization
123,975 
119,755 
Nuclear fuel, net of accumulated amortization
123,139 
125,201 
Total property, plant and equipment
11,808,944 
11,194,330 
Electric Service
 
 
Utility Plant and Depreciation [Line Items]
 
 
Generation
7,336,902 
7,158,729 
Transmission
2,494,744 
2,247,309 
Distribution
5,543,561 
5,339,322 
General plant
847,025 
797,703 
Plant in service and held for future use
16,222,232 
15,543,063 
Accumulated depreciation and amortization
(5,594,094)
(5,397,751)
Net
10,628,138 
10,145,312 
Construction work in progress
816,307 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation
117,385 
121,255 
Intangible assets, net of accumulated amortization
123,975 
119,755 
Nuclear fuel, net of accumulated amortization
123,139 
125,201 
Total property, plant and equipment
$ 11,808,944 
$ 11,194,330 
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Accounting Policies [Abstract]
 
 
 
Income tax (benefit), net of refunds
$ 6,550 
$ (102,154)
$ 18,537 
Interest, net of amounts capitalized
170,209 
177,074 
184,010 
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
 
 
 
Accrued capital expenditures
83,798 
44,712 
33,184 
Dividends declared but not paid
69,363 
65,790 
62,528 
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)
$ 0 
$ 0 
$ 145,609 
New Accounting Standards - Narrative (Details) (New Accounting Pronouncement, Early Adoption, Effect, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Long-term Debt
 
 
New Accounting Pronouncement, Early Adoption [Line Items]
 
 
Unamortized debt issue costs
$ (28,000)
$ (25,000)
Deferred Debits
 
 
New Accounting Pronouncement, Early Adoption [Line Items]
 
 
Unamortized debt issue costs
$ 28,000 
$ 25,000 
Regulatory Matters (Details) (APS, USD $)
2 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended 3 Months Ended
Dec. 31, 2015
Lost Fixed Cost Recovery Mechanism
Apr. 30, 2014
ACC
Electric Energy Efficiency Standard
workshop
Jan. 1, 2014
ACC
Net Metering
Sep. 30, 2015
ACC
Net Metering
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. 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
Mar. 2, 2015
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Mar. 1, 2014
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Dec. 31, 2015
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Mar. 11, 2014
Cost Recovery Mechanisms
ACC
2013 DSMAC
Dec. 31, 2012
Cost Recovery Mechanisms
ACC
2013 DSMAC
Jun. 1, 2012
Cost Recovery Mechanisms
ACC
2013 DSMAC
Mar. 11, 2014
Cost Recovery Mechanisms
ACC
2014 DSMAC
Mar. 20, 2015
Cost Recovery Mechanisms
ACC
2015 DSMAC
project
Jun. 1, 2015
Cost Recovery Mechanisms
ACC
2016 DSMAC
Dec. 31, 2015
Cost Recovery Mechanisms
ACC
RES
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. 1, 2015
Cost Recovery Mechanisms
ACC
Arizona Renewable Energy Standard and Tariff 2016
Feb. 1, 2015
Cost Recovery Mechanisms
ACC
Power Supply Adjustor (PSA)
Jun. 1, 2015
Cost Recovery Mechanisms
FERC
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters
Jun. 1, 2014
Cost Recovery Mechanisms
FERC
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters
Apr. 15, 2014
AZ Sun Program
Filing with the Arizona Corporation Commission
Arizona Renewable Energy Standard and Tariff 2014
MW
Apr. 15, 2014
Alternative to AZ Sun Program
Filing with the Arizona Corporation Commission
Arizona Renewable Energy Standard and Tariff 2014
Customer
MW
Apr. 15, 2014
Alternative to AZ Sun Program
Filing with the Arizona Corporation Commission
Arizona Renewable Energy Standard and Tariff 2014
MW
Dec. 19, 2014
Alternative to AZ Sun Program, Phase 1
Filing with the Arizona Corporation Commission
Arizona Renewable Energy Standard and Tariff 2014
MW
Dec. 19, 2014
Alternative to AZ Sun Program Phase 2
Filing with the Arizona Corporation Commission
Arizona Renewable Energy Standard and Tariff 2014
MW
Jan. 15, 2016
Subsequent Event
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Feb. 1, 2016
Subsequent Event
Cost Recovery Mechanisms
ACC
Power Supply Adjustor (PSA)
Jan. 31, 2016
Subsequent Event
Cost Recovery Mechanisms
ACC
Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net retail rate increase
 
 
 
 
 
$ 95,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in the average retail customer bill
 
 
 
 
 
6.60% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Settlement Agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net change in base rates
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-fuel base rate increase
 
 
 
 
116,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel-related base rate decrease
 
 
 
 
153,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current base fuel rate (in dollars per kWh)
 
 
 
 
0.03757 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approved base fuel rate (in dollars per kWh)
 
 
 
 
0.03207 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates
 
 
 
 
36,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorized return on common equity (as a percent)
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of debt in capital structure
 
 
 
 
46.10% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of common equity in capital structure
 
 
 
 
53.90% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
25.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
75.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent)
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual cost recovery due to modifications to the Environmental Improvement Surcharge
 
 
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Elimination of the sharing provision of fuel and purchased power costs
 
 
 
 
9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Period to process the subsequent rate cases
 
 
 
 
12 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ACC staff sufficiency findings, general period of time
 
 
 
 
30 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plan term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter additional capacity from AZ Sun projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20 
 
10 
8 
2 
 
 
 
Request to build additional utility scale solar, number of customers
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,500 
 
 
 
 
 
 
Amount of proposed budget
 
 
 
 
 
 
 
 
 
 
 
 
87,600,000 
 
 
68,900,000 
68,900,000 
 
 
154,000,000 
148,000,000 
 
 
 
 
 
 
 
 
 
 
 
Amount of approved budget
 
 
 
 
 
 
 
 
 
 
 
68,900,000 
 
 
68,900,000 
 
 
 
152,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter, cumulative energy savings for current year percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
5.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter number of resource savings projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter, proposed rate reduction percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public utilities, cost effective energy efficiency programs, number of workshops
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum increase (decrease) in PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.004 
 
 
 
 
 
 
 
 
 
 
PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.000887 
 
 
 
 
 
 
 
 
0.001678 
 
Forward component of PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001975 
 
Historical component of PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.000297)
 
Transition component of PSA rate (in dollars per KWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.004936)
increase (decrease) in annual wholesale transmission rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(17,600,000)
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
 
 
 
 
 
 
 
 
38,500,000 
25,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of adjustment representing prorated sales losses pending approval
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46,400,000 
 
 
Increase in Amount of Adjustment Representing Prorated Sales Losses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,900,000 
 
 
Charge on future customers who install rooftop solar panels (in dollars per kWh)
 
 
0.70 
0.70 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated monthly collection due to charge on future customers who install rooftop solar panels
 
 
$ 4.90 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
$ 14,997 
$ (26,927)
$ 21,678 
Deferred fuel and purchased power amortization
1,617 
40,757 
31,190 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
14,997 
(26,927)
21,678 
Deferred fuel and purchased power amortization
1,617 
40,757 
31,190 
ACC |
ARIZONA PUBLIC SERVICE COMPANY |
Power Supply Adjustor (PSA) |
Cost Recovery Mechanisms
 
 
 
Change in regulatory asset
 
 
 
Beginning balance
6,926 
20,755 
 
Deferred fuel and purchased power
(14,997)
26,927 
 
Deferred fuel and purchased power amortization
(1,617)
(40,756)
 
Ending balance
$ (9,688)
$ 6,926 
 
Regulatory Matters - Four Corners and Cholla (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended 0 Months Ended 0 Months Ended 12 Months Ended
Jul. 31, 2012
Dec. 31, 2015
Retired power plant costs
APS
Dec. 30, 2013
SCE
Four Corners
APS
MW
Dec. 31, 2015
SCE
Four Corners
APS
Dec. 23, 2014
Four Corners Units 4 and 5
SCE
APS
Dec. 30, 2013
Four Corners Units 4 and 5
SCE
APS
Dec. 31, 2015
Four Corners Units 4 and 5
SCE
Four Corners cost deferral
APS
Acquisition
 
 
 
 
 
 
 
Ownership interest acquired
 
 
 
 
 
48.00% 
 
Settlement agreement, ACC approved rate adjustment, annualized customer impact
 
 
 
 
$ 57.1 
 
 
Regulatory assets
 
 
 
12 
 
 
70 
Regulatory asset amortization period
3 years 
 
 
 
 
 
10 years 
Net receipt due to negotiation of alternate arrangement
 
 
40 
 
 
 
 
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 asset, net book value
 
$ 122 
 
 
 
 
 
Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Detail of regulatory assets
 
 
Regulatory assets, current
$ 149,555 
$ 136,734 
Regulatory assets, non-current
1,214,146 
1,054,087 
Pension
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
619,223 
485,037 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
9,913 
9,913 
Regulatory assets, non-current
127,518 
136,182 
Income taxes - AFUDC equity
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
5,495 
4,813 
Regulatory assets, non-current
133,712 
118,396 
Deferred fuel and purchased power - mark-to-market
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
71,852 
51,209 
Regulatory assets, non-current
69,697 
46,233 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,689 
6,689 
Regulatory assets, non-current
63,582 
70,565 
Income taxes — investment tax credit basis adjustment
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,766 
1,716 
Regulatory assets, non-current
48,462 
46,200 
Lost fixed cost recovery
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
45,507 
37,612 
Regulatory assets, non-current
0 
0 
Palo Verde VIE
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
18,143 
34,440 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
34,751 
34,162 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
50,453 
30,283 
Loss on reacquired debt
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,515 
1,435 
Regulatory assets, non-current
16,375 
16,410 
Tax expense of Medicare subsidy
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,520 
1,528 
Regulatory assets, non-current
12,163 
13,756 
Transmission vegetation management
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
4,543 
9,086 
Regulatory assets, non-current
0 
4,543 
Mead-Phoenix transmission line CIAC
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
332 
332 
Regulatory assets, non-current
11,040 
11,372 
Deferred fuel and purchased power
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
6,926 
Regulatory assets, non-current
0 
0 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
418 
418 
Regulatory assets, non-current
6,085 
6,503 
Pension and other postretirement benefits deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
4,238 
Regulatory assets, non-current
0 
0 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
5 
819 
Regulatory assets, non-current
$ 2,942 
$ 5 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 145,766 
$ 130,549 
Regulatory liabilities, non-current
994,152 
1,051,196 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
277,554 
295,546 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
39,746 
31,033 
Regulatory liabilities, non-current
240,367 
272,825 
Other postretirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
34,100 
32,317 
Regulatory liabilities, non-current
179,521 
198,599 
Income taxes — deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
3,604 
3,505 
Regulatory liabilities, non-current
97,175 
92,727 
Income taxes - change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
1,113 
371 
Regulatory liabilities, non-current
72,454 
72,423 
Spent nuclear fuel
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
3,051 
4,396 
Regulatory liabilities, non-current
67,437 
65,594 
Renewable energy standard (b)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
43,773 
24,596 
Regulatory liabilities, non-current
4,365 
22,677 
Demand side management (b)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
6,079 
31,335 
Regulatory liabilities, non-current
19,115 
0 
Sundance maintenance
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
13,678 
12,069 
Deferred fuel and purchased power (b) (c)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
9,688 
0 
Regulatory liabilities, non-current
0 
0 
Deferred gains on utility property
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,000 
2,000 
Regulatory liabilities, non-current
6,000 
8,000 
Four Corners coal reclamation
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
8,920 
1,200 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,550 
934 
Regulatory liabilities, non-current
$ 7,565 
$ 9,535 
Income Taxes (Details) (USD $)
12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
Third quarter 2009
Dec. 31, 2013
Tax Years 2008 and 2009
Feb. 17, 2011
ARIZONA
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Apr. 4, 2013
NEW MEXICO
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
NEW MEXICO
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Palo Verde VIE
Income Taxes
 
 
 
 
 
 
 
 
 
 
 
 
 
Decrease in prior period uncertain tax positions
$ 10,244,000 
$ 2,282,000 
$ 108,099,000 
$ 10,244,000 
$ 2,282,000 
$ 107,918,000 
$ 67,000,000 
$ 41,000,000 
 
 
 
 
 
Income tax expense benefit attributable to non controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
0 
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 than)
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
 
 
 
 
 
 
 
 
 
75,000,000 
 
2,000,000 
 
General business tax credit carryforwards that will begin to expire in 2031
82,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of federal and state loss carryforwards which will begin to expire in 2019
3,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Decrease in long term deferred tax liability due to adoption of regulations
$ 26,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
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
$ 44,775 
$ 41,997 
$ 133,422 
Additions for tax positions of the current year
2,175 
4,309 
3,516 
Additions for tax positions of prior years
0 
751 
13,158 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(10,244)
(2,282)
(108,099)
Settlements with taxing authorities
0 
0 
0 
Lapses of applicable statute of limitations
(2,259)
0 
0 
Total unrecognized tax benefits, end of the year
34,447 
44,775 
41,997 
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
44,775 
41,997 
133,241 
Additions for tax positions of the current year
2,175 
4,309 
3,516 
Additions for tax positions of prior years
0 
751 
13,158 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(10,244)
(2,282)
(107,918)
Settlements with taxing authorities
0 
0 
0 
Lapses of applicable statute of limitations
(2,259)
0 
0 
Total unrecognized tax benefits, end of the year
$ 34,447 
$ 44,775 
$ 41,997 
Income Taxes - Summary of Unrecognized Tax Benefits (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Income Tax [Line Items]
 
 
 
Tax positions, that if recognized, would decrease our effective tax rate
$ 9,523 
$ 11,207 
$ 9,827 
Unrecognized tax benefit interest expense/(benefit) recognized
(161)
752 
(3,716)
Unrecognized tax benefit interest accrued
804 
965 
213 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Income Tax [Line Items]
 
 
 
Tax positions, that if recognized, would decrease our effective tax rate
9,523 
11,207 
9,827 
Unrecognized tax benefit interest expense/(benefit) recognized
(161)
752 
(3,716)
Unrecognized tax benefit interest accrued
$ 804 
$ 965 
$ 213 
Income Taxes - Components of Income Tax Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
$ (12,335)
$ 25,054 
$ (81,784)
State
 
 
 
 
 
 
 
 
4,763 
10,382 
10,537 
Total current
 
 
 
 
 
 
 
 
(7,572)
35,436 
(71,247)
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
221,505 
167,365 
279,973 
State
 
 
 
 
 
 
 
 
23,787 
17,904 
21,865 
Total deferred
 
 
 
 
 
 
 
 
245,292 
185,269 
301,838 
Income tax expense
22,847 
139,555 
67,371 
7,947 
5,007 
134,753 
74,540 
6,405 
237,720 
220,705 
230,591 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
6,485 
40,115 
(97,531)
State
 
 
 
 
 
 
 
 
7,813 
15,598 
11,983 
Total current
 
 
 
 
 
 
 
 
14,298 
55,713 
(85,548)
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
208,326 
165,027 
305,389 
State
 
 
 
 
 
 
 
 
23,217 
16,620 
25,254 
Total deferred
 
 
 
 
 
 
 
 
231,543 
181,647 
330,643 
Income tax expense
 
 
 
 
 
 
 
 
$ 245,841 
$ 237,360 
$ 245,095 
Income Taxes - Effective Tax Rate Reconciliation (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
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
 
 
 
 
 
 
 
 
$ 242,869 
$ 225,540 
$ 234,695 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
18,265 
18,149 
21,387 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
(2,169)
0 
(3,356)
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
837 
830 
823 
Allowance for equity funds used during construction (see Note 1)
 
 
 
 
 
 
 
 
(9,711)
(8,523)
(6,997)
Palo Verde VIE noncontrolling interest (see Note 18)
 
 
 
 
 
 
 
 
(6,626)
(9,135)
(11,862)
Investment tax credit amortization
 
 
 
 
 
 
 
 
(5,527)
(4,928)
(3,548)
Other
 
 
 
 
 
 
 
 
(218)
(1,228)
(551)
Income tax expense
22,847 
139,555 
67,371 
7,947 
5,007 
134,753 
74,540 
6,405 
237,720 
220,705 
230,591 
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% 
35.00% 
35.00% 
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Federal income tax expense at 35% statutory rate
 
 
 
 
 
 
 
 
250,267 
239,638 
246,384 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
20,433 
21,148 
23,970 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
(1,892)
0 
(3,231)
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
837 
830 
823 
Allowance for equity funds used during construction (see Note 1)
 
 
 
 
 
 
 
 
(9,711)
(8,523)
(6,997)
Palo Verde VIE noncontrolling interest (see Note 18)
 
 
 
 
 
 
 
 
(6,626)
(9,135)
(11,862)
Investment tax credit amortization
 
 
 
 
 
 
 
 
(5,527)
(4,928)
(3,548)
Other
 
 
 
 
 
 
 
 
(1,940)
(1,670)
(444)
Income tax expense
 
 
 
 
 
 
 
 
$ 245,841 
$ 237,360 
$ 245,095 
Income Taxes Income Taxes - Deferred Income Tax Liability Recognized on the Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Net deferred income tax liability recognized on the Consolidated Balance Sheets
 
 
Deferred tax asset, current
$ 0 
$ 122,232 
Long-term liability
(2,723,425)
(2,582,636)
Deferred income taxes — net
(2,723,425)
(2,460,404)
ARIZONA PUBLIC SERVICE COMPANY
 
 
Net deferred income tax liability recognized on the Consolidated Balance Sheets
 
 
Deferred tax asset, current
0 
55,253 
Long-term liability
(2,764,489)
(2,571,365)
Deferred income taxes — net
$ (2,764,489)
$ (2,516,112)
Income Taxes - Components of Deferred Income Tax Liability (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
DEFERRED TAX ASSETS
 
 
Risk management activities
$ 70,498 
$ 57,505 
Regulatory liabilities:
 
 
Asset retirement obligation and removal costs
216,765 
229,772 
Unamortized investment tax credits
100,779 
96,232 
Other postretirement liabilities
83,034 
90,496 
Other
60,707 
60,409 
Pension liabilities
191,028 
205,227 
Renewable energy incentives
60,956 
65,169 
Credit and loss carryforwards
59,557 
68,347 
Other
149,033 
138,729 
Total deferred tax assets
992,357 
1,011,886 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(3,116,752)
(2,958,369)
Risk management activities
(10,626)
(12,171)
Other postretirement assets
(71,737)
(59,170)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(54,110)
(48,286)
Deferred fuel and purchased power
0 
(2,498)
Deferred fuel and purchased power — mark-to-market
(55,020)
(38,187)
Pension benefits
(240,692)
(191,747)
Retired power plant costs (see Note 3)
(53,420)
(57,255)
Other
(108,441)
(99,123)
Other
(4,984)
(5,484)
Total deferred tax liabilities
3,715,782 
3,472,290 
Deferred income taxes — net
(2,723,425)
(2,460,404)
ARIZONA PUBLIC SERVICE COMPANY
 
 
DEFERRED TAX ASSETS
 
 
Risk management activities
70,498 
57,505 
Regulatory liabilities:
 
 
Asset retirement obligation and removal costs
216,765 
229,772 
Unamortized investment tax credits
100,779 
96,232 
Other postretirement liabilities
83,034 
90,496 
Other
60,707 
60,409 
Pension liabilities
181,787 
194,541 
Renewable energy incentives
60,956 
65,169 
Credit and loss carryforwards
0 
0 
Other
176,016 
161,379 
Total deferred tax assets
950,542 
955,503 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(3,116,752)
(2,958,369)
Risk management activities
(10,626)
(12,171)
Other postretirement assets
(70,986)
(58,495)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(54,110)
(48,286)
Deferred fuel and purchased power
0 
(2,498)
Deferred fuel and purchased power — mark-to-market
(55,020)
(38,187)
Pension benefits
(240,692)
(191,747)
Retired power plant costs (see Note 3)
(53,420)
(57,255)
Other
(108,441)
(99,123)
Other
(4,984)
(5,484)
Total deferred tax liabilities
3,715,031 
3,471,615 
Deferred income taxes — net
$ (2,764,489)
$ (2,516,112)
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Lines of Credit and Short-Term Borrowings
 
 
Commercial paper
$ 0 
$ (147,400,000)
Pinnacle West
 
 
Lines of Credit and Short-Term Borrowings
 
 
Commercial paper
0 
0 
Commitment fees (as a percent)
0.125% 
0.175% 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Lines of Credit and Short-Term Borrowings
 
 
Commercial paper
0 
(147,400,000)
Commitment fees (as a percent)
0.10% 
0.125% 
Revolving credit facility
 
 
Lines of Credit and Short-Term Borrowings
 
 
Amount committed
1,200,000,000 
1,200,000,000 
Unused amount
1,200,000,000 
1,052,600,000 
Revolving credit facility |
Pinnacle West
 
 
Lines of Credit and Short-Term Borrowings
 
 
Amount committed
200,000,000 
200,000,000 
Unused amount
200,000,000 
200,000,000 
Revolving credit facility |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Lines of Credit and Short-Term Borrowings
 
 
Amount committed
1,000,000,000 
1,000,000,000 
Unused amount
$ 1,000,000,000 
$ 852,600,000 
Lines of Credit and Short-Term Borrowings (Details) (USD $)
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2015
Pinnacle West
Dec. 31, 2014
Pinnacle West
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Feb. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 31, 2015
Revolving credit facility
Dec. 31, 2014
Revolving credit facility
Dec. 31, 2015
Revolving credit facility
Pinnacle West
Dec. 31, 2014
Revolving credit facility
Pinnacle West
Dec. 31, 2015
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in 2019
Dec. 31, 2015
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing in 2019 and 2020
Facility
Dec. 31, 2015
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing September 2020
Sep. 2, 2015
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing September 2020
Dec. 31, 2015
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing in May 2019
Sep. 2, 2015
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing April 2018
Dec. 31, 2015
Letter of credit
Pinnacle West
Revolving credit facility maturing in 2019
Dec. 31, 2015
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing in 2019 and 2020
Dec. 31, 2015
Commercial paper
Pinnacle West
Revolving credit facility maturing in 2019
Dec. 31, 2015
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
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 
$ 1,000,000,000 
$ 1,000,000,000 
$ 1,000,000,000 
 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
 
 
 
 
 
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders
 
 
 
 
 
 
 
 
 
 
 
300,000,000 
 
 
1,400,000,000 
700,000,000 
 
700,000,000 
 
 
 
 
 
 
Long-term line of credit
 
 
 
 
 
 
 
 
 
 
 
0 
 
 
0 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
79,000,000 
0 
 
 
Commercial paper
0 
147,400,000 
0 
0 
0 
147,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
 
Number of credit facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
Maximum commercial paper support available under credit facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 and Liquidity Matters (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
Maximum
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 5, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Minimum
ACC
Dec. 31, 2015
Pinnacle West
Dec. 31, 2014
Pinnacle West
Dec. 31, 2013
Pinnacle West
Jan. 12, 2015
Unsecured senior notes 2.20 percent matures on 15 January, 2020
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
May 19, 2015
Unsecured senior notes 3.15 percent matures on 15 May, 2025
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
May 19, 2015
Unsecured senior notes 4.65 percent matures on 15 May, 2015
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
May 19, 2015
Unsecured senior notes 4.65 percent matures on 15 May, 2015
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
May 28, 2015
Arizona pollution control revenue refunding bond, 2009 series B
ARIZONA PUBLIC SERVICE COMPANY
Nov. 17, 2015
Arizona pollution control revenue refunding bond, 2009 series B
ARIZONA PUBLIC SERVICE COMPANY
Current maturities of long-term debt
Jun. 26, 2015
Term loan facility maturing June 26, 2018
ARIZONA PUBLIC SERVICE COMPANY
Term loan
Nov. 17, 2015
Arizona pollution control corporation revenue refunding bonds, 2009 series A
ARIZONA PUBLIC SERVICE COMPANY
Current maturities of long-term debt
Nov. 6, 2015
Unsecured senior notes 4.35 percent mature on 15 November, 2020
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
Dec. 8, 2015
Arizona pollution control corporation revenue refunding bonds, 2009 series C
ARIZONA PUBLIC SERVICE COMPANY
Current maturities of long-term debt
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 250,000,000 
$ 300,000,000 
 
 
 
 
$ 50,000,000 
 
$ 250,000,000 
 
Interest rate (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.20% 
3.15% 
 
4.65% 
 
 
 
 
4.35% 
 
Repayments of long-term debt
415,570,000 
652,578,000 
122,828,000 
 
415,570,000 
527,578,000 
122,828,000 
 
 
 
 
0 
125,000,000 
0 
 
 
300,000,000 
 
 
 
 
 
 
 
Principal balance repaid
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
32,000,000 
32,000,000 
 
38,150,000 
 
32,000,000 
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)
 
 
 
 
46.00% 
 
 
 
 
 
 
47.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Required common equity ratio ordered by ACC (as a percent) (at least)
 
 
 
 
 
 
 
 
 
 
40.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total shareholder equity
4,583,917,000 
4,367,493,000 
 
 
4,679,254,000 
4,478,243,000 
 
4,700,000,000 
 
 
 
4,583,917,000 
4,367,493,000 
 
 
 
 
 
 
 
 
 
 
 
Total capitalization
 
 
 
 
 
 
 
8,600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
 
 
3,400,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long term debt authorization
 
 
 
 
 
 
 
 
$ 5,100,000,000.0 
$ 4,200,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Total long-term debt
$ 3,819,971 
$ 3,390,143 
Long-term debt less current maturities
3,462,391 
3,006,573 
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
3,728,555 
 
Unamortized discount
(10,374)
(9,206)
Unamortized premium
4,686 
4,866 
Unamortized debt issue costs
(27,896)
(24,642)
Total long-term debt
3,694,971 
3,265,143 
Less current maturities
(357,580)
(383,570)
Total long-term debt less current maturities
3,337,391 
2,881,573 
Pinnacle West
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
3,853,555 
 
Total 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
92,405 
156,405 
Less current maturities
(108,000)
 
Pollution Control Bonds - Variable |
APS |
Minimum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
0.01% 
0.03% 
Pollution Control Bonds - Variable |
APS |
Maximum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
0.24% 
0.27% 
Pollution Control Bonds - Fixed |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
211,150 
249,300 
Interest Rates, low end of range (as a percent)
1.75% 
1.75% 
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
303,555 
405,705 
Senior unsecured notes |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
3,375,000 
2,875,000 
Interest Rates, low end of range (as a percent)
2.20% 
2.20% 
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
0 
13,420 
Interest rate (as a percent)
8.00% 
8.00% 
Term loan facility |
Pinnacle West
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Total long-term debt
125,000 
125,000 
Weighted-average interest rate (as a percent)
1.174% 
1.019% 
Senior unsecured notes maturing through 2015 |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Less current maturities
(250,000)
 
Term loan |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
1.024% 
 
Term loan |
Term loan facility maturing June 26, 2018 |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Term loan
$ 50,000 
$ 0 
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Pinnacle West
 
Principal payments due on long-term debt
 
2016
$ 357,580 
2017
125,000 
2018
82,000 
2019
500,000 
2020
250,000 
Thereafter
2,538,975 
Total
3,853,555 
ARIZONA PUBLIC SERVICE COMPANY
 
Principal payments due on long-term debt
 
2016
357,580 
2017
0 
2018
82,000 
2019
500,000 
2020
250,000 
Thereafter
2,538,975 
Total
$ 3,728,555 
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
$ 3,819,971 
$ 3,390,143 
Fair Value
4,106,367 
3,839,108 
Pinnacle West
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
125,000 
125,000 
Fair Value
125,000 
125,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
3,694,971 
3,265,143 
Fair Value
$ 3,981,367 
$ 3,714,108 
Retirement Plans and Other Benefits Retirement Plans and Other Benefits (Details) (USD $)
1 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Jul. 31, 2012
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2015
Pension Benefits
Dec. 31, 2014
Pension Benefits
Dec. 31, 2013
Pension Benefits
Dec. 31, 2015
Pension Benefits
Fixed income securities
Dec. 31, 2015
Pension Benefits
Return-generating assets
Dec. 31, 2015
Pension Benefits
Developed equities
Dec. 31, 2015
Pension Benefits
Emerging equities
Dec. 31, 2015
Pension Benefits
Alternative investments
Dec. 31, 2015
Other postretirement benefits
Dec. 31, 2014
Other postretirement benefits
Dec. 31, 2013
Other postretirement benefits
Jan. 1, 2015
Other postretirement benefits
Age
Dec. 31, 2015
Other postretirement benefits
Fixed income
Dec. 31, 2015
Other postretirement benefits
Non-fixed income
Dec. 31, 2015
Pinnacle West
Dec. 31, 2014
Pinnacle West
Dec. 31, 2013
Pinnacle West
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Other postretirement benefits
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Other postretirement benefits
Dec. 31, 2013
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
 
185,997,000 
152,290,000 
 
 
 
0 
0 
 
 
 
 
 
 
185,997,000 
152,290,000 
 
 
 
 
 
 
 
182,625,000 
149,260,000 
 
 
 
 
 
 
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
 
5,000,000 
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, contribution amount (up to)
 
75,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partnership funding commitments, funded amount
 
40,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
 
 
 
 
 
60.00% 
40.00% 
 
 
 
 
 
 
 
40.00% 
60.00% 
 
 
 
 
 
 
 
 
 
 
 
Contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Employer's contributions under the plan
 
 
 
 
 
 
100,000,000 
175,000,000 
141,000,000 
 
 
 
 
 
791,000 
770,000 
14,000,000 
 
 
 
 
 
 
 
 
100,000,000 
175,000,000 
140,000,000 
1,000,000 
1,000,000 
14,000,000 
Minimum contributions under MAP-21
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum contributions under MAP-21
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Voluntary employer contributions over next three years (up to)
 
 
 
 
 
 
300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected employer contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 
$ 9,000,000 
 
 
 
 
 
 
 
 
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, 2015
Dec. 31, 2014
Dec. 31, 2013
Pension Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost - benefits earned during the period
$ 59,627 
$ 53,080 
$ 64,195 
Interest cost on benefit obligation
123,983 
129,194 
112,392 
Expected return on plan assets
(179,231)
(158,998)
(146,333)
Amortization of prior service cost (credit)
594 
869 
1,097 
Amortization of net actuarial loss
31,056 
10,963 
39,852 
Net periodic benefit cost
36,029 
35,108 
71,203 
Portion of cost charged to expense
20,036 
21,985 
38,968 
Other Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost - benefits earned during the period
16,827 
18,139 
23,597 
Interest cost on benefit obligation
28,102 
41,243 
41,536 
Expected return on plan assets
(36,855)
(46,400)
(45,717)
Amortization of prior service cost (credit)
(37,968)
(9,626)
(179)
Amortization of net actuarial loss
4,881 
1,175 
11,310 
Net periodic benefit cost
(25,013)
4,531 
30,547 
Portion of cost charged to expense
$ (10,391)
$ 6,000 
$ 18,469 
Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Pension Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
$ 3,078,648 
$ 2,646,530 
 
Service cost
59,627 
53,080 
64,195 
Interest cost
123,983 
129,194 
112,392 
Benefit payments
(137,115)
(128,550)
 
Actuarial (gain) loss
(91,340)
378,394 
 
Plan amendments
0 
0 
 
Benefit obligation at the end of the period
3,033,803 
3,078,648 
2,646,530 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
2,615,404 
2,264,121 
 
Actual return on plan assets
(44,690)
292,992 
 
Employer's contributions under the plan
100,000 
175,000 
141,000 
Benefit payments
(127,940)
(116,709)
 
Balance at the end of the period
2,542,774 
2,615,404 
2,264,121 
Funded Status at the end of the period
(491,029)
(463,244)
 
Other Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
682,335 
890,418 
 
Service cost
16,827 
18,139 
23,597 
Interest cost
28,102 
41,243 
41,536 
Benefit payments
(24,988)
(29,054)
 
Actuarial (gain) loss
(55,256)
150,188 
 
Plan amendments
0 
(388,599)
 
Benefit obligation at the end of the period
647,020 
682,335 
890,418 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
834,625 
748,339 
 
Actual return on plan assets
(2,399)
105,223 
 
Employer's contributions under the plan
791 
770 
14,000 
Benefit payments
0 
(19,707)
 
Balance at the end of the period
833,017 
834,625 
748,339 
Funded Status at the end of the period
$ 185,997 
$ 152,290 
 
Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) (Pension Benefits, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
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
$ 3,033,803 
$ 3,078,648 
Accumulated benefit obligation
2,873,467 
2,873,741 
Fair value of plan assets
$ 2,542,774 
$ 2,615,404 
Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Amounts recognized on the Consolidated Balance Sheets
 
 
Assets for other postretirement benefits
$ 185,997 
$ 152,290 
Pension Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Assets for other postretirement benefits
0 
0 
Current liability
(10,031)
(9,508)
Noncurrent liability
(480,998)
(453,736)
Net amount recognized
(491,029)
(463,244)
Other Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Assets for other postretirement benefits
185,997 
152,290 
Current liability
0 
0 
Noncurrent liability
0 
0 
Net amount recognized
$ 185,997 
$ 152,290 
Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Details related to accumulated other comprehensive loss
 
 
Accumulated other comprehensive loss
$ 37,593 
$ 57,756 
Other Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
127,124 
148,006 
Prior service cost (credit)
(341,301)
(379,269)
APS's portion recorded as a regulatory asset
213,621 
230,916 
Income tax benefit
925 
851 
Accumulated other comprehensive loss
369 
504 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
3,784 
 
Prior service cost (credit)
(37,884)
 
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014
(34,100)
 
Pension Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
679,501 
577,976 
Prior service cost (credit)
609 
1,203 
APS's portion recorded as a regulatory asset
(619,223)
(485,037)
Income tax benefit
(23,663)
(36,890)
Accumulated other comprehensive loss
37,224 
57,252 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
38,923 
 
Prior service cost (credit)
527 
 
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014
$ 39,450 
 
Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
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% 
7.00% 
 
Initial post-65 healthcare cost trend rate (as a percent)
 
 
5.00% 
5.00% 
 
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 
0 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% 
7.00% 
 
7.50% 
Initial post-65 health care cost trend rate (as a percent)
5.00% 
7.50% 
5.00% 
 
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 
0 years 
 
4 years 
Pension Benefits
 
 
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
 
Discount rate (as a percent)
4.02% 
 
4.37% 
4.02% 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
 
 
Discount rate (as a percent)
4.88% 
4.88% 
4.02% 
 
4.01% 
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% 
6.90% 
 
7.00% 
Other Benefits
 
 
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
 
Discount rate (as a percent)
4.14% 
 
4.52% 
4.14% 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
 
 
Discount rate (as a percent)
4.41% 
5.10% 
4.14% 
 
4.20% 
Expected long-term return on plan assets (as a percent)
4.25% 
6.80% 
4.45% 
 
7.00% 
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
 
 
 8,834 
 
 
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
 
 
(5,890)
 
 
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs
 
 
9,069 
 
 
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs
 
 
(6,949)
 
 
Effect of 1% increase on the accumulated other postretirement benefit obligation
 
 
100,322 
 
 
Effect of 1% decrease on the accumulated other postretirement benefit obligation
 
 
 (80,332)
 
 
Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Pension Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
$ 2,542,774 
$ 2,615,404 
$ 2,264,121 
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Net receivables (payables)
14,467 
16,883 
 
Fair value of plan assets
2,542,774 
2,615,404 
 
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
640,679 
556,660 
 
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
1,845,531 
2,013,932 
 
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
42,097 
27,929 
 
Other Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
833,017 
834,625 
748,339 
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Net receivables (payables)
3,096 
4,100 
 
Fair value of plan assets
833,017 
834,625 
 
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
454,891 
414,204 
 
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
375,030 
416,321 
 
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
0 
0 
 
Cash and cash equivalents |
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
1,893 
387 
 
Cash and cash equivalents |
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
1,893 
387 
 
Cash and cash equivalents |
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
240 
318 
 
Cash and cash equivalents |
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
240 
318 
 
Corporate |
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
1,108,736 
1,162,096 
 
Corporate |
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
1,108,736 
1,162,096 
 
Corporate |
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
217,026 
187,961 
 
Corporate |
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
217,026 
187,961 
 
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
274,778 
291,817 
 
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
274,778 
291,817 
 
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
131,435 
130,967 
 
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
131,435 
130,967 
 
Other (a) |
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
113,008 
113,265 
 
Other (a) |
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
113,008 
113,265 
 
Other (a) |
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
31,106 
35,291 
 
Other (a) |
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
31,106 
35,291 
 
U.S. companies |
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
233,021 
246,387 
 
U.S. companies |
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
233,021 
246,387 
 
U.S. companies |
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
253,193 
265,106 
 
U.S. companies |
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
253,193 
265,106 
 
International companies |
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
14,680 
18,069 
 
International companies |
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
14,680 
18,069 
 
International companies |
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
12,390 
17,813 
 
International companies |
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
12,390 
17,813 
 
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
130,097 
127,336 
 
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
130,097 
127,336 
 
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
81,516 
88,258 
 
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
81,516 
88,258 
 
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
185,892 
317,167 
 
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
185,892 
317,167 
 
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
28,539 
85,746 
 
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
28,539 
85,746 
 
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
150,359 
129,715 
 
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
150,359 
129,715 
 
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
13,512 
11,657 
 
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
13,512 
11,657 
 
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
169,937 
166,266 
 
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
127,840 
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
42,097 
27,929 
 
Mutual funds - 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
116,307 
 
 
Mutual funds - International 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
116,307 
 
 
Mutual funds - 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
52,568 
 
 
Mutual funds - International 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
52,568 
 
 
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)
14,467 
16,883 
 
Fair value of plan assets
44,066 
42,899 
 
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
29,599 
26,016 
 
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
42,097 
27,929 
8,660 
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)
3,096 
4,100 
 
Fair value of plan assets
11,492 
11,508 
 
Short-term investments and other |
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
5,065 
 
 
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
$ 3,331 
$ 7,408 
 
Retirement Plans and Other Benefits - Changes in Fair Value (Details) (Pension Benefits, USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
Short-term investments and other
Significant Unobservable Inputs (Level 3)
Dec. 31, 2014
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
$ 2,542,774 
$ 2,615,404 
$ 2,264,121 
$ 27,929 
$ 8,660 
Actual return on assets still held
 
 
 
2,789 
927 
Purchases
 
 
 
13,187 
19,984 
Sales
 
 
 
(1,808)
(1,642)
Transfers in and/or out of Level 3
 
 
 
0 
0 
Balance at the end of the period
$ 2,542,774 
$ 2,615,404 
$ 2,264,121 
$ 42,097 
$ 27,929 
Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Pension Benefits
 
Estimated Future Benefit Payments
 
2016
$ 152,146 
2017
171,005 
2018
170,534 
2019
180,700 
2020
188,988 
Years 2021-2025
1,023,451 
Other Benefits
 
Estimated Future Benefit Payments
 
2016
26,468 
2017
28,444 
2018
30,490 
2019
32,438 
2020
33,982 
Years 2021-2025
$ 184,335 
Leases (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Trust
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 1986
Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
Lease expense
$ 17,000,000 
$ 18,000,000 
$ 18,000,000 
 
Pinnacle West
 
 
 
 
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
2016
9,182,000 
 
 
 
2017
8,557,000 
 
 
 
2018
7,045,000 
 
 
 
2019
6,121,000 
 
 
 
2020
4,835,000 
 
 
 
Thereafter
61,251,000 
 
 
 
Total future lease commitments
96,991,000 
 
 
 
Palo Verde Lessor Trusts
 
 
 
 
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
Number of VIE lessor trusts
 
 
 
3 
APS
 
 
 
 
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
2016
8,797,000 
 
 
 
2017
8,317,000 
 
 
 
2018
6,880,000 
 
 
 
2019
5,961,000 
 
 
 
2020
4,680,000 
 
 
 
Thereafter
61,101,000 
 
 
 
Total future lease commitments
95,736,000 
 
 
 
Lease expense
$ 14,000,000 
$ 15,000,000 
$ 15,000,000 
 
Number of VIE lessor trusts
3 
 
 
3 
Jointly-Owned Facilities (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Palo Verde Units 1 and 3
 
Interests in jointly-owned facilities
 
Percent Owned
29.10% 
Plant in Service
$ 1,744,137 
Accumulated Depreciation
1,067,376 
Construction Work in Progress
22,228 
Palo Verde Unit 2
 
Interests in jointly-owned facilities
 
Percent Owned
16.80% 
Plant in Service
583,633 
Accumulated Depreciation
356,767 
Construction Work in Progress
4,142 
Palo Verde Common
 
Interests in jointly-owned facilities
 
Percent Owned
28.00% 
Plant in Service
643,201 
Accumulated Depreciation
231,609 
Construction Work in Progress
64,069 
Palo Verde Sale Leaseback
 
Interests in jointly-owned facilities
 
Plant in Service
351,050 
Accumulated Depreciation
233,665 
Construction Work in Progress
0 
Four Corners Units 4, 5 and Common
 
Interests in jointly-owned facilities
 
Percent Owned
63.00% 
Plant in Service
857,555 
Accumulated Depreciation
577,321 
Construction Work in Progress
77,317 
Navajo Generating Station Units 1, 2 and 3
 
Interests in jointly-owned facilities
 
Percent Owned
14.00% 
Plant in Service
274,640 
Accumulated Depreciation
168,132 
Construction Work in Progress
4,460 
Cholla common facilities
 
Interests in jointly-owned facilities
 
Percent Owned
63.30% 
Plant in Service
158,623 
Accumulated Depreciation
53,777 
Construction Work in Progress
1,390 
ANPP 500kV System
 
Interests in jointly-owned facilities
 
Percent Owned
33.40% 
Plant in Service
109,348 
Accumulated Depreciation
36,576 
Construction Work in Progress
1,594 
Navajo Southern System
 
Interests in jointly-owned facilities
 
Percent Owned
22.70% 
Plant in Service
62,139 
Accumulated Depreciation
19,361 
Construction Work in Progress
397 
Palo Verde - Yuma 500kV System
 
Interests in jointly-owned facilities
 
Percent Owned
19.30% 
Plant in Service
14,043 
Accumulated Depreciation
5,226 
Construction Work in Progress
133 
Four Corners Switchyards
 
Interests in jointly-owned facilities
 
Percent Owned
49.80% 
Plant in Service
38,420 
Accumulated Depreciation
9,833 
Construction Work in Progress
1,687 
Phoenix - Mead System
 
Interests in jointly-owned facilities
 
Percent Owned
17.10% 
Plant in Service
39,089 
Accumulated Depreciation
13,173 
Construction Work in Progress
151 
Palo Verde - Estrella 500kV System
 
Interests in jointly-owned facilities
 
Percent Owned
50.00% 
Plant in Service
89,832 
Accumulated Depreciation
18,359 
Construction Work in Progress
1,008 
Morgan-Pinnacle Peak System
 
Interests in jointly-owned facilities
 
Percent Owned
64.60% 
Plant in Service
129,855 
Accumulated Depreciation
11,087 
Construction Work in Progress
2,592 
Round Valley System
 
Interests in jointly-owned facilities
 
Percent Owned
50.00% 
Plant in Service
703 
Accumulated Depreciation
286 
Construction Work in Progress
0 
Palo Verde - Morgan System
 
Interests in jointly-owned facilities
 
Percent Owned
87.70% 
Plant in Service
12 
Accumulated Depreciation
0 
Construction Work in Progress
133,813 
Hassayampa - North Gila System
 
Interests in jointly-owned facilities
 
Percent Owned
80.00% 
Plant in Service
164,854 
Accumulated Depreciation
1,159 
Construction Work in Progress
0 
Cholla 500 Switchyard
 
Interests in jointly-owned facilities
 
Percent Owned
85.70% 
Plant in Service
547 
Accumulated Depreciation
15 
Construction Work in Progress
0 
Saquaro 500 Switchyard
 
Interests in jointly-owned facilities
 
Percent Owned
75.00% 
Plant in Service
773 
Accumulated Depreciation
26 
Construction Work in Progress
$ 0 
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)
12 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Coal take-or-pay commitments
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, 2015
ARIZONA PUBLIC SERVICE COMPANY
Renewable energy credits
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Obligations
Dec. 31, 2014
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
Jun. 1, 2015
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal [Member]
Dec. 31, 2015
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal [Member]
Jun. 1, 2015
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal [Member]
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal [Member]
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Litigation settlement, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 57,400,000 
$ 16,700,000 
 
 
 
 
Proceeds from legal settlements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
42,000,000 
12,000,000 
12,200,000 
3,600,000 
Change in long-term regulatory liabilities
20,535,000 
(59,618,000)
(64,473,000)
20,535,000 
(59,618,000)
(64,473,000)
 
 
 
 
 
 
 
 
 
 
 
12,200,000 
 
Maximum insurance against public liability per occurrence for a nuclear incident
 
 
 
13,500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum available nuclear liability insurance
 
 
 
375,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program
 
 
 
13,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
3 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum potential retrospective assessment per incident of APS
 
 
 
111,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual payment limitation with respect to maximum potential retrospective assessment
 
 
 
16,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde
 
 
 
2,800,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment
 
 
 
23,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Collateral assurance provided based on rating triggers
 
 
 
61,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Period to provide collateral assurance based on rating triggers
 
 
 
20 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016
 
 
 
876,000,000 
 
 
 
170,714,000 
 
 
42,000,000 
15,000,000 
 
 
 
 
 
 
 
2017
 
 
 
949,000,000 
 
 
 
195,428,000 
 
 
40,000,000 
16,000,000 
 
 
 
 
 
 
 
2018
 
 
 
737,000,000 
 
 
 
189,588,000 
 
 
40,000,000 
18,000,000 
 
 
 
 
 
 
 
2019
 
 
 
603,000,000 
 
 
 
193,818,000 
 
 
40,000,000 
19,000,000 
 
 
 
 
 
 
 
2020
 
 
 
498,000,000 
 
 
 
198,160,000 
 
 
40,000,000 
20,000,000 
 
 
 
 
 
 
 
Thereafter
 
 
 
7,800,000,000 
 
 
 
2,270,974,000 
 
 
432,000,000 
262,000,000 
 
 
 
 
 
 
 
Total obligation
 
 
 
 
 
 
 
3,200,000,000 
 
 
 
202,000,000 
198,000,000 
 
 
 
 
 
 
Present value of commitments
 
 
 
 
 
 
 
2,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
Total purchases
 
 
 
 
 
 
 
$ 211,327,000 
$ 236,773,000 
$ 188,496,000 
 
 
 
 
 
 
 
 
 
Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) (USD $)
0 Months Ended 12 Months Ended 0 Months Ended
Sep. 8, 2011
ARIZONA PUBLIC SERVICE COMPANY
kV
Customer
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Natural Gas Tolling Letter of Credit
Aug. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
Contaminated groundwater wells
Defendant
Aug. 17, 2015
ARIZONA PUBLIC SERVICE COMPANY
Clean Air Act Citizen Lawsuit
power_plant
Aug. 17, 2015
Four Corners
Clean Air Act Citizen Lawsuit
Feb. 9, 2016
Subsequent Event
Minimum
Loss of perishable inventory and sales
Feb. 9, 2016
Subsequent Event
Maximum
Loss of perishable inventory and sales
Superfund
 
 
 
 
 
 
 
 
Costs related to investigation and study under Superfund site
 
$ 2,000,000 
 
 
 
 
 
 
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit
 
 
 
24 
 
 
 
 
Southwest Power Outage
 
 
 
 
 
 
 
 
Power outage capacity of transmission line that tripped out of service
500 
 
 
 
 
 
 
 
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost
10 minutes 
 
 
 
 
 
 
 
Number of customers losing service in Yuma area
69,700 
 
 
 
 
 
 
 
Time period a decision is reached after oral argument
 
 
 
 
 
 
30 days 
60 days 
Clean Air Act Citizen Lawsuit
 
 
 
 
 
 
 
 
Loss contingency, number of units
 
 
 
 
2 
 
 
 
Loss contingency, civil penalty amount
 
 
 
 
 
1,500,000 
 
 
Outstanding letters of credit
 
 
$ 6,700,000 
 
 
 
 
 
Litigation settlement, percent of settlement
 
 
 
 
15.00% 
 
 
 
Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)
12 Months Ended 0 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2015
Dec. 31, 2015
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Cholla
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Cholla Units 1-3
ARIZONA PUBLIC SERVICE COMPANY
Aug. 17, 2015
Clean Air Act Citizen Lawsuit
ARIZONA PUBLIC SERVICE COMPANY
power_plant
Aug. 17, 2015
Clean Air Act Citizen Lawsuit
Four Corners
May 23, 2013
New Mexico Tax Matter
Four Corners
May 23, 2013
New Mexico Tax Matter
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Equity Lessors Sale Leaseback Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Natural Gas Tolling Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Four Corners Units 4 and 5
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Four Corners Units 4 and 5
Navajo Plant
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Four Corners Units 4 and 5
Natural Gas Tolling Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Minimum
Four Corners Units 4 and 5
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Sep. 30, 2015
Regional Haze Rules
Cholla
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Mercury and Air Toxic Standards
Navajo Generating Station
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Coal Combustion Waste
Navajo Generating Station
ARIZONA PUBLIC SERVICE COMPANY
Commitments and Contingencies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss contingency, number of units
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss contingency, civil penalty amount
 
 
 
 
 
$ 1,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
Environmental Matters [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of share of cost of control
 
 
 
 
 
 
 
 
 
 
 
 
 
63.00% 
 
 
 
 
Expected environmental cost
 
 
 
8,000,000 
 
 
 
 
 
 
 
 
200,000,000 
 
400,000,000 
100,000,000 
1,000,000 
 
Additional percentage share of cost of control
 
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
 
 
 
 
Additional expected environment cost
 
15,000,000 
85,000,000 
 
 
 
 
 
 
 
 
45,000,000 
 
 
 
 
 
1,000,000 
Clean power plan, optional extension period
2 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal severance surtax, penalty, and interest
 
 
 
 
 
 
30,000,000 
 
 
 
 
 
 
 
 
 
 
 
Share of the assessment
 
 
 
 
 
 
 
12,000,000 
 
 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
 
 
 
$ 79,000,000 
$ 158,000,000 
$ 6,700,000 
 
 
 
 
 
 
 
Asset Retirement Obligations (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Changes attributable to:
 
 
Asset retirement obligations, current
$ 28,573,000 
$ 32,462,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Change in asset retirement obligations
 
 
Beginning balance
390,750,000 
346,729,000 
Changes attributable to:
 
 
Accretion expense
25,163,000 
23,567,000 
Settlements
(32,048,000)
(29,497,000)
Estimated cash flow revisions
17,556,000 
43,899,000 
Newly incurred obligation
42,155,000 
6,052,000 
Ending balance
443,576,000 
390,750,000 
Asset retirement obligations, current
28,573,000 
32,000,000 
Four Corners |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Settlements
(32,000,000)
(30,000,000)
Estimated cash flow revisions
24,000,000 
 
Cholla |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Asset Retirement Obligations
 
 
Increase in plant services
23,000,000 
 
Decrease in regulatory liability
16,000,000 
 
Changes attributable to:
 
 
Estimated cash flow revisions
(3,000,000)
 
Newly incurred obligation
39,000,000 
 
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 
Four Corners Units 1 Through 3 |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Estimated cash flow revisions
 
24,000,000 
Solar Facility |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Newly incurred obligation
 
$ 6,000,000 
Selected Quarterly Financial Data (Unaudited) (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
OPERATING REVENUES
$ 734,430 
$ 1,199,146 
$ 890,648 
$ 671,219 
$ 726,450 
$ 1,172,667 
$ 906,264 
$ 686,251 
$ 3,495,443 
$ 3,491,632 
$ 3,454,628 
Operations and maintenance
222,019 
220,449 
210,965 
214,944 
260,503 
223,418 
211,222 
212,882 
868,377 
908,025 
924,727 
Operating income
109,834 
445,111 
231,973 
67,684 
60,184 
421,775 
254,113 
75,170 
854,602 
811,242 
846,323 
INCOME TAXES (Note 4)
22,847 
139,555 
67,371 
7,947 
5,007 
134,753 
74,540 
6,405 
237,720 
220,705 
230,591 
Net income
45,978 
261,978 
127,507 
20,727 
9,535 
248,086 
141,384 
24,691 
456,190 
423,696 
439,966 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
41,117 
257,116 
122,902 
16,122 
5,410 
243,961 
132,458 
15,766 
437,257 
397,595 
406,074 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.37 
$ 2.32 
$ 1.11 
$ 0.15 
$ 0.05 
$ 2.20 
$ 1.20 
$ 0.14 
$ 3.94 
$ 3.59 
$ 3.69 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 0.37 
$ 2.30 
$ 1.10 
$ 0.14 
$ 0.05 
$ 2.20 
$ 1.19 
$ 0.14 
$ 3.92 
$ 3.58 
$ 3.66 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
733,586 
1,198,380 
889,723 
670,668 
725,633 
1,172,190 
905,578 
685,545 
3,492,357 
3,488,946 
3,451,251 
Operations and maintenance
219,146 
216,011 
208,031 
209,947 
253,668 
212,430 
208,059 
208,285 
853,135 
882,442 
897,824 
Operating income
86,709 
301,238 
162,704 
61,333 
54,835 
287,928 
180,394 
69,635 
611,984 
592,792 
621,865 
INCOME TAXES (Note 4)
 
 
 
 
 
 
 
 
245,841 
237,360 
245,095 
Net income
 
 
 
 
 
 
 
 
469,207 
447,320 
458,861 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 43,857 
$ 261,187 
$ 125,362 
$ 19,868 
$ 15,738 
$ 251,047 
$ 134,916 
$ 19,518 
$ 450,274 
$ 421,219 
$ 424,969 
Fair Value Measurements - Fair Value of Assets and Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Assets
 
 
Nuclear decommissioning trust
$ 735,196 
$ 713,866 
Total assets
30,364 
32,598 
Fair value measurement on a recurring basis
 
 
Assets
 
 
Other
(25,345)
(21,962)
Derivative assets
28,011 
31,405 
Other
(335)
(7,245)
Nuclear decommissioning trust
735,196 
713,866 
Other
(25,680)
(29,207)
Total assets
763,207 
745,271 
Liabilities
 
 
Other
39,698 
58,767 
Derivative Liability
(167,689)
(110,278)
Fair value measurement on a recurring basis |
US commingled equity funds
 
 
Assets
 
 
Other
0 
0 
Nuclear decommissioning trust
314,957 
309,620 
Fair value measurement on a recurring basis |
Cash and cash equivalents
 
 
Assets
 
 
Other
(335)
(7,245)
Nuclear decommissioning trust
11,925 
4,208 
Fair value measurement on a recurring basis |
U.S. Treasury
 
 
Assets
 
 
Nuclear decommissioning trust
117,245 
118,843 
Fair value measurement on a recurring basis |
Corporate
 
 
Assets
 
 
Nuclear decommissioning trust
96,243 
109,379 
Fair value measurement on a recurring basis |
Mortgage-backed securities
 
 
Assets
 
 
Nuclear decommissioning trust
99,065 
88,465 
Fair value measurement on a recurring basis |
Municipality bonds
 
 
Assets
 
 
Nuclear decommissioning trust
72,206 
69,139 
Fair value measurement on a recurring basis |
Other (a)
 
 
Assets
 
 
Nuclear decommissioning trust
23,555 
14,212 
Fair value measurement on a recurring basis |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
129,505 
118,843 
Gross assets, fair value disclosure
129,505 
118,843 
Fair value measurement on a recurring basis |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Cash and cash equivalents
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
12,260 
 
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
117,245 
118,843 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Gross derivative assets
22,992 
20,769 
Decommissioning fund investments, gross fair value
606,026 
602,268 
Gross assets, fair value disclosure
629,018 
623,037 
Liabilities
 
 
Gross derivative liability
(144,044)
(95,061)
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
US commingled equity funds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
314,957 
309,620 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Cash and cash equivalents
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
 
11,453 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
U.S. Treasury
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
0 
 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Corporate
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
96,243 
109,379 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
99,065 
88,465 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Municipality bonds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
72,206 
69,139 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Other (a)
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
23,555 
14,212 
Fair value measurement on a recurring basis |
Significant Unobservable Inputs (Level 3)
 
 
Assets
 
 
Gross derivative assets
30,364 
32,598 
Gross assets, fair value disclosure
30,364 
32,598 
Liabilities
 
 
Gross derivative liability
$ (63,343)
$ (73,984)
Fair Value Measurements - Level 3 Quantative Information (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
 
 
 
 
 
 
 
 
 
Assets
$ 30,364 
 
 
 
$ 32,598 
 
 
 
$ 30,364 
$ 32,598 
 
Liabilities
63,343 
 
 
 
73,984 
 
 
 
63,343 
73,984 
 
Operating revenues
734,430 
1,199,146 
890,648 
671,219 
726,450 
1,172,667 
906,264 
686,251 
3,495,443 
3,491,632 
3,454,628 
Electricity forward contracts
 
 
 
 
 
 
 
 
 
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
 
 
 
 
 
 
 
 
 
Assets
24,543 
 
 
 
29,471 
 
 
 
24,543 
29,471 
 
Liabilities
54,679 
 
 
 
55,894 
 
 
 
54,679 
55,894 
 
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)
 
 
 
 
 
 
 
 
15.92 
19.51 
 
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)
 
 
 
 
 
 
 
 
40.73 
56.72 
 
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)
 
 
 
 
 
 
 
 
26.86 
35.27 
 
Option Contracts
 
 
 
 
 
 
 
 
 
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
 
 
 
 
 
 
 
 
 
Liabilities
5,628 
 
 
 
15,035 
 
 
 
5,628 
15,035 
 
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)
 
 
 
 
 
 
 
 
23.87 
32.14 
 
Implied electricity price volatilities (as a percent)
 
 
 
 
 
 
 
 
40.00% 
23.00% 
 
Implied natural gas price volatilities (as a percent)
 
 
 
 
 
 
 
 
32.00% 
23.00% 
 
Natural gas forward price (per MMbtu)
 
 
 
 
 
 
 
 
 
3.18 
 
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)
 
 
 
 
 
 
 
 
44.13 
66.09 
 
Implied electricity price volatilities (as a percent)
 
 
 
 
 
 
 
 
59.00% 
63.00% 
 
Implied natural gas price volatilities (as a percent)
 
 
 
 
 
 
 
 
40.00% 
41.00% 
 
Natural gas forward price (per MMbtu)
 
 
 
 
 
 
 
 
 
3.29 
 
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)
 
 
 
 
 
 
 
 
33.91 
45.83 
 
Implied electricity price volatilities (as a percent)
 
 
 
 
 
 
 
 
52.00% 
41.00% 
 
Implied natural gas price volatilities (as a percent)
 
 
 
 
 
 
 
 
35.00% 
31.00% 
 
Natural gas forward price (per MMbtu)
 
 
 
 
 
 
 
 
 
3.25 
 
Natural gas forward contracts
 
 
 
 
 
 
 
 
 
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
 
 
 
 
 
 
 
 
 
Assets
5,821 
 
 
 
3,127 
 
 
 
5,821 
3,127 
 
Liabilities
$ 3,036 
 
 
 
$ 3,055 
 
 
 
$ 3,036 
$ 3,055 
 
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)
 
 
 
 
 
 
 
 
2.18 
2.98 
 
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)
 
 
 
 
 
 
 
 
3.14 
4.13 
 
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 
 
Natural gas forward 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)
 
 
 
 
 
 
 
 
2.61 
 
 
Fair Value Measurements Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Total net gains (losses) realized/unrealized:
 
 
Net derivative beginning balance
$ (41,386,000)
$ (49,165,000)
Included in earnings
0 
102,000 
Included in OCI
(452,000)
(239,000)
Deferred as a regulatory asset or liability
(4,009,000)
(482,000)
Settlements
14,809,000 
12,080,000 
Transfers into Level 3 from Level 2
(6,256,000)
(2,090,000)
Transfers from Level 3 into Level 2
4,315,000 
(1,592,000)
Net derivative ending balance
(32,979,000)
(41,386,000)
Net unrealized gains included in earnings related to instruments still held at end of period
0 
0 
Significant level 1 transfers
$ 0 
 
Earnings Per Share (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Earnings Per Share [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common shareholders
$ 41,117 
$ 257,116 
$ 122,902 
$ 16,122 
$ 5,410 
$ 243,961 
$ 132,458 
$ 15,766 
$ 437,257 
$ 397,595 
$ 406,074 
Weighted Average common shares outstanding — basic (in shares)
 
 
 
 
 
 
 
 
111,026 
110,626 
109,984 
Net effect of dilutive securities:
 
 
 
 
 
 
 
 
 
 
 
Contingently issuable performance shares and restricted stock units
 
 
 
 
 
 
 
 
526 
552 
822 
Weighted average common shares outstanding — diluted (in shares)
 
 
 
 
 
 
 
 
111,552 
111,178 
110,806 
Earnings per average common share attributable to common shareholders — basic (in dollars per share)
$ 0.37 
$ 2.32 
$ 1.11 
$ 0.15 
$ 0.05 
$ 2.20 
$ 1.20 
$ 0.14 
$ 3.94 
$ 3.59 
$ 3.69 
Earnings per average common share attributable to common shareholders — diluted (in dollars per share)
$ 0.37 
$ 2.30 
$ 1.10 
$ 0.14 
$ 0.05 
$ 2.20 
$ 1.19 
$ 0.14 
$ 3.92 
$ 3.58 
$ 3.66 
Stock-Based Compensation (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
Restricted stock unit awards
Dec. 31, 2014
Restricted stock unit awards
Dec. 31, 2013
Restricted stock unit awards
Dec. 31, 2015
Restricted Stock Units, Stock Grants, and Stock Units
Dec. 31, 2015
Performance Shares
element
metric
Dec. 31, 2014
Performance Shares
Dec. 31, 2013
Performance Shares
Dec. 31, 2015
Performance Shares
Maximum
Dec. 31, 2015
Performance Shares
Minimum
Dec. 31, 2015
Officers and Key Employees
Restricted stock unit awards
Dec. 31, 2012
Chief Executive Officer
Retention units
Dec. 31, 2015
Non-Officer Board of Director Member
Restricted stock unit awards
Dec. 31, 2015
2012 Plan
Stock-Based Compensation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares available for grant (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,600,000 
Common shares available for issuance (in shares)
2,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Compensation cost that has been charged against income
$ 19 
$ 33 
$ 25 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total income tax benefit recognized
7 
13 
10 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted
14 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected weighted-average period of recognition of unrecognized compensation cost
2 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total fair value of shares vested
21 
20 
20 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-based liabilities paid
 
 
 
10 
9 
10 
 
16 
12 
15 
 
 
 
 
 
 
Cash flow effect, cash used to settle awards
 
 
 
$ 3 
$ 3 
$ 4 
 
 
 
 
 
 
 
 
 
 
Restricted Stock Units, Stock Grants and Stock Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vesting period
 
 
 
4 years 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of cash that the participant may elect as a dividend for the first option available under the plan
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
Percentage of Fully Transferable Shares of Stock in which Election to Receive Payment May be Made by Participants for Deferrals Option Two
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
100.00% 
 
Granted (in shares)
 
 
 
 
 
 
152,651 
151,430 
 
 
 
 
 
50,617 
 
 
Additional shares to be granted as retention award if performance requirements are met
 
 
 
 
 
 
 
 
 
 
 
 
 
33,745 
 
 
Percentage of cash that the participant may elect as a dividend equivalent deferral for 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% 
 
Performance Shares
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of performance element criteria
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
Performance period
 
 
 
 
 
 
 
3 years 
 
 
 
 
 
 
 
 
Percentage of the awards that vest based on a percentile ranking of total shareholder return
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
Percentage of the awards that vest based on non-financial separate performance metrics
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
Number of non-financial separate performance metrics based on which awards vest
 
 
 
 
 
 
 
6 
 
 
 
 
 
 
 
 
Exact number of shares issued as a percentage of the target award
 
 
 
 
 
 
 
 
 
 
200.00% 
0.00% 
 
 
 
 
Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Restricted Stock Units, Stock Grants, and Stock Units
 
 
 
Stocks granted and the weighted average fair value
 
 
 
Units granted (in shares)
152,651 
179,291 
182,240 
Grant date fair value (in dollars per share)
$ 64.12 
$ 54.89 
$ 55.14 
Number of granted awards to be settled in cash (in shares)
45,104 
49,018 
52,620 
Performance Shares
 
 
 
Stocks granted and the weighted average fair value
 
 
 
Units granted (in shares)
151,430 
166,244 
176,332 
Grant date fair value (in dollars per share)
$ 64.97 
$ 54.86 
$ 55.45 
Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Restricted Stock Units, Stock Grants, and Stock Units
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
480,933 
 
 
Granted (in shares)
152,651 
 
 
Change in performance factor (in shares)
0 
 
 
Vested (in shares)
(198,424)
 
 
Forfeited (in shares)
(6,873)
 
 
Balance at the end of the period (in shares)
428,287 
480,933 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 51.27 
 
 
Granted (in dollars per share)
$ 64.12 
$ 54.89 
$ 55.14 
Change in performance factor (in dollars per share)
0.00 
 
 
Vested (in dollars per share)
$ 49.20 
 
 
Forfeited (in dollars per share)
$ 56.78 
 
 
Balance at the end of the period (in dollars per share)
$ 56.69 
$ 51.27 
 
Vested Awards Outstanding at December 31, 2015
106,712 
 
 
Vested Awards Outstanding at December 31, 2015 (in shares)
   
 
 
Number of nonvested awards to be settled in cash (in shares)
 
127,634 
 
Number of nonvested awards to be settled in shares (in shares)
 
353,299 
 
Performance Shares
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
324,230 
 
 
Granted (in shares)
151,430 
 
 
Change in performance factor (in shares)
40,496 
 
 
Vested (in shares)
(202,480)
 
 
Forfeited (in shares)
(7,844)
 
 
Balance at the end of the period (in shares)
305,832 
324,230 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 54.92 
 
 
Granted (in dollars per share)
$ 64.97 
$ 54.86 
$ 55.45 
Change in performance factor (in dollars per share)
54.98 
 
 
Vested (in dollars per share)
$ 54.98 
 
 
Forfeited (in dollars per share)
$ 57.89 
 
 
Balance at the end of the period (in dollars per share)
$ 59.78 
$ 54.92 
 
Vested Awards Outstanding at December 31, 2015
202,480 
 
 
Vested Awards Outstanding at December 31, 2015 (in shares)
   
 
 
Derivative Accounting (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Counterparty
Dec. 31, 2014
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
$ 3,000,000 
$ 4,000,000 
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
167,689,000 
110,271,000 
Concentration of credit risk, number of counterparties
1 
 
Concentration risk
87.00% 
 
Derivative assets
28,000,000 
31,405,000 
Additional collateral to counterparties for energy related non-derivative instrument contracts
161,000,000 
 
Commodity Contracts |
Designated as Hedging Instruments
 
 
Derivative Accounting
 
 
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income
$ (4,000,000)
 
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) (Commodity Contracts)
12 Months Ended
Dec. 31, 2015
MMcf
GWh
Commodity Contracts
 
Outstanding gross notional amount of derivatives
 
Power
2,487 
Gas
182,000 
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Designated as Hedging Instruments
 
 
 
Derivative Instruments in Designated Cash Flows Hedges
 
 
 
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
$ (615,000)
$ (372,000)
$ (353,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)
(5,988,000)
(21,415,000)
(44,219,000)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
0 
0 
0 
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges
0 
0 
0 
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
(108,399,000)
(66,043,000)
(10,160,000)
Revenue |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
574,000 
324,000 
289,000 
Fuel and purchased power |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
$ (108,973,000)
$ (66,367,000)
$ (10,449,000)
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Commodity Contracts
 
 
Assets
 
 
Gross Recognized Derivatives
$ 53,356 
$ 53,367 
Amounts Offset
(26,017)
(22,317)
Net Recognized Derivatives
27,339 
31,050 
Other
672 
355 
Amount Reported on Balance Sheet
28,000 
31,405 
Liabilities
 
 
Gross Recognized Derivatives
(207,387)
(169,045)
Amounts Offset
44,077 
66,217 
Net Recognized Derivatives
(163,310)
(102,828)
Other
(4,379)
(7,443)
Amount Reported on Balance Sheet
(167,689)
(110,271)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(154,031)
(115,678)
Amounts Offset
18,060 
43,900 
Net Recognized Derivatives
(135,971)
(71,778)
Other
(3,707)
(7,088)
Amount Reported on Balance Sheet
(139,678)
(78,866)
Commodity Contracts |
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
37,396 
28,557 
Amounts Offset
(22,163)
(15,127)
Net Recognized Derivatives
15,233 
13,430 
Other
672 
355 
Amount Reported on Balance Sheet
15,905 
13,785 
Commodity Contracts |
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
15,960 
24,810 
Amounts Offset
(3,854)
(7,190)
Net Recognized Derivatives
12,106 
17,620 
Other
0 
0 
Amount Reported on Balance Sheet
12,106 
17,620 
Commodity Contracts |
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(113,560)
(86,055)
Amounts Offset
40,223 
33,829 
Net Recognized Derivatives
(73,337)
(52,226)
Other
(4,379)
(7,443)
Amount Reported on Balance Sheet
(77,716)
(59,669)
Commodity Contracts |
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(93,827)
(82,990)
Amounts Offset
3,854 
32,388 
Net Recognized Derivatives
(89,973)
(50,602)
Other
0 
0 
Amount Reported on Balance Sheet
(89,973)
(50,602)
Designated as Hedging Instruments
 
 
Liabilities
 
 
Amount Reported on Balance Sheet
$ (3,000)
$ (4,000)
Derivative Accounting - Credit Risk and Related Contingent Features (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Commodity Contracts
 
Credit Risk and Credit-Related Contingent Features
 
Aggregate Fair Value of Derivative Instruments in a Net Liability Position
$ 207,387 
Cash Collateral Posted
18,060 
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered
$ 112,301 
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Other income:
 
 
 
Interest income
$ 493 
$ 1,010 
$ 1,629 
Debt return on the purchase of Four Corners units 4 & 5
 
8,386 
0 
Miscellaneous
128 
212 
75 
Total other income
621 
9,608 
1,704 
Other expense:
 
 
 
Non-operating costs
(11,292)
(9,657)
(8,207)
Investment loss - net
(2,080)
(9,426)
(3,711)
Miscellaneous
(4,451)
(2,663)
(4,106)
Total other expense
(17,823)
(21,746)
(16,024)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Other income:
 
 
 
Interest income
163 
689 
1,234 
Debt return on the purchase of Four Corners units 4 & 5
0 
8,386 
0 
Investment gains - net
716 
1,197 
1,024 
Miscellaneous
1,955 
1,023 
1,638 
Total other income
2,834 
11,295 
3,896 
Other expense:
 
 
 
Non-operating costs
(11,648)
(10,397)
(9,626)
Asset dispositions
(2,219)
(615)
(4,992)
Miscellaneous
(5,152)
(2,391)
(5,831)
Total other expense
$ (19,019)
$ (13,403)
$ (20,449)
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, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2013
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, 2015
Period 2016 through 2023
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2015
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
Jan. 1, 2016
Scenario, Forecast
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of VIE lessor trusts
 
 
 
3 
 
 
3 
 
 
 
 
 
 
 
 
 
Number of leases under which assets are retained
 
 
 
 
 
 
 
 
 
 
1 
2 
 
 
 
 
Annual lease payments
 
 
 
 
 
 
 
 
 
 
 
 
$ 23,000,000 
$ 16,000,000 
 
 
Lease period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 years 
 
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts
18,933,000 
26,101,000 
33,892,000 
18,933,000 
26,101,000 
33,892,000 
 
19,000,000 
26,000,000 
34,000,000 
 
 
 
 
 
 
VIE entity initial loss exposure to noncontrolling interests during lease extension period, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
288,000,000 
VIE entity maximum loss exposure to noncontrolling interests during lease extension period, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 465,000,000 
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, 2015
Dec. 31, 2014
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback, net of accumulated depreciation
$ 117,385 
$ 121,255 
Current maturities of long-term debt (Note 6)
357,580 
383,570 
Equity - noncontrolling interests
135,540 
151,609 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback, net of accumulated depreciation
117,385 
121,255 
Current maturities of long-term debt (Note 6)
357,580 
383,570 
Equity - noncontrolling interests
135,540 
151,609 
ARIZONA PUBLIC SERVICE COMPANY |
Consolidation of VIEs
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback, net of accumulated depreciation
117,385 
121,255 
Current maturities of long-term debt (Note 6)
0 
13,420 
Equity - noncontrolling interests
$ 135,540 
$ 151,609 
Nuclear Decommissioning Trusts (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
$ 735,196 
$ 713,866 
 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
Proceeds from the sale of securities
478,813 
356,195 
446,025 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
735,196 
713,866 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
735,196 
713,866 
 
Unrealized Gains
169,053 
176,534 
 
Unrealized Losses
(2,760)
(1,088)
 
Net payables for securities purchases
(335)
(7,245)
 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
Realized gains
5,189 
4,725 
5,459 
Realized losses
(6,225)
(4,525)
(6,706)
Proceeds from the sale of securities
478,813 
356,195 
446,025 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
735,196 
713,866 
 
ARIZONA PUBLIC SERVICE COMPANY |
Equity Securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
314,957 
309,620 
 
Unrealized Gains
157,098 
159,274 
 
Unrealized Losses
(115)
(15)
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
314,957 
309,620 
 
ARIZONA PUBLIC SERVICE COMPANY |
Fixed income securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
420,574 
411,491 
 
Unrealized Gains
11,955 
17,260 
 
Unrealized Losses
(2,645)
(1,073)
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Less than one year
14,001 
 
 
1 year - 5 years
117,356 
 
 
5 years - 10 years
114,769 
 
 
Greater than 10 years
174,448 
 
 
Total
$ 420,574 
$ 411,491 
 
Changes in Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
$ (68,141)
$ (78,053)
 
Total other comprehensive income
23,393 
9,912 
35,955 
Ending balance
(44,748)
(68,141)
(78,053)
Derivative Instruments
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
(957)
(810)
 
Amounts reclassified from accumulated other comprehensive loss
4,187 
13,483 
 
Total other comprehensive income
3,230 
12,673 
 
Pension and Other Postretirement Benefits
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
16,980 
(5,419)
 
Amounts reclassified from accumulated other comprehensive loss
3,183 
2,658 
 
Total other comprehensive income
20,163 
(2,761)
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
(48,333)
(53,372)
 
Total other comprehensive income
21,236 
5,039 
35,723 
Ending balance
(27,097)
(48,333)
(53,372)
ARIZONA PUBLIC SERVICE COMPANY |
Derivative Instruments
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
(957)
(809)
 
Amounts reclassified from accumulated other comprehensive loss
4,187 
13,483 
 
Total other comprehensive income
3,230 
12,674 
 
ARIZONA PUBLIC SERVICE COMPANY |
Pension and Other Postretirement Benefits
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
14,726 
(10,415)
 
Amounts reclassified from accumulated other comprehensive loss
3,280 
2,780 
 
Total other comprehensive income
$ 18,006 
$ (7,635)
 
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, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 734,430 
$ 1,199,146 
$ 890,648 
$ 671,219 
$ 726,450 
$ 1,172,667 
$ 906,264 
$ 686,251 
$ 3,495,443 
$ 3,491,632 
$ 3,454,628 
Operating expenses
 
 
 
 
 
 
 
 
2,640,841 
2,680,390 
2,608,305 
OPERATING INCOME
109,834 
445,111 
231,973 
67,684 
60,184 
421,775 
254,113 
75,170 
854,602 
811,242 
846,323 
Other
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
18,013 
18,652 
11,261 
Interest expense
 
 
 
 
 
 
 
 
194,964 
200,950 
201,888 
Income tax benefit
22,847 
139,555 
67,371 
7,947 
5,007 
134,753 
74,540 
6,405 
237,720 
220,705 
230,591 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
41,117 
257,116 
122,902 
16,122 
5,410 
243,961 
132,458 
15,766 
437,257 
397,595 
406,074 
Other comprehensive income
 
 
 
 
 
 
 
 
23,393 
9,912 
35,955 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
460,650 
407,507 
442,029 
Pinnacle West
 
 
 
 
 
 
 
 
 
 
 
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
550 
642 
799 
Operating expenses
 
 
 
 
 
 
 
 
12,733 
23,507 
24,930 
OPERATING INCOME
 
 
 
 
 
 
 
 
(12,183)
(22,865)
(24,131)
Other
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
 
 
 
 
 
 
 
 
446,508 
411,528 
420,926 
Other expense
 
 
 
 
 
 
 
 
(3,302)
(3,276)
(1,999)
Total
 
 
 
 
 
 
 
 
443,206 
408,252 
418,927 
Interest expense
 
 
 
 
 
 
 
 
2,672 
3,663 
3,226 
INCOME BEFORE INCOME TAXES
 
 
 
 
 
 
 
 
428,351 
381,724 
391,570 
Income tax benefit
 
 
 
 
 
 
 
 
(8,906)
(15,871)
(14,504)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
437,257 
397,595 
406,074 
Other comprehensive income
 
 
 
 
 
 
 
 
23,393 
9,912 
35,955 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
$ 460,650 
$ 407,507 
$ 442,029 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Current assets
 
 
 
 
Cash and cash equivalents
$ 39,488 
$ 7,604 
$ 9,526 
$ 26,202 
Accounts receivable
274,691 
297,740 
 
 
Income tax receivable
589 
3,098 
 
 
Other current assets
37,242 
38,817 
 
 
Total current assets
890,516 
973,435 
 
 
Investments and other assets
 
 
 
 
Other assets
52,518 
54,047 
 
 
Total investments and other assets
799,820 
785,533 
 
 
Total Assets
15,028,258 
14,288,890 
 
 
Current liabilities
 
 
 
 
Accounts payable
297,480 
295,211 
 
 
Accrued taxes (Note 4)
138,600 
140,613 
 
 
Common dividends payable
69,363 
65,790 
 
 
Other current liabilities
197,861 
178,962 
 
 
Total current liabilities
1,442,317 
1,559,143 
 
 
Long-term debt less current maturities
3,462,391 
3,006,573 
 
 
Deferred credits and other
 
 
 
 
Deferred income taxes
2,723,425 
2,582,636 
 
 
Other
186,345 
188,286 
 
 
Total deferred credits and other
5,404,093 
5,204,072 
 
 
Common stock equity
 
 
 
 
Common stock
2,541,668 
2,512,970 
 
 
Accumulated other comprehensive loss
(44,748)
(68,141)
(78,053)
 
Retained earnings
2,092,803 
1,926,065 
 
 
Total shareholders’ equity
4,583,917 
4,367,493 
 
 
Noncontrolling interests
135,540 
151,609 
 
 
Total equity
4,719,457 
4,519,102 
4,340,460 
4,102,289 
Total Liabilities and Equity
15,028,258 
14,288,890 
 
 
Pinnacle West
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
17,432 
3,088 
5,798 
22,679 
Accounts receivable
93,093 
99,958 
 
 
Current deferred income taxes
0 
66,979 
 
 
Income tax receivable
14,895 
7,329 
 
 
Other current assets
197 
124 
 
 
Total current assets
125,617 
177,478 
 
 
Investments and other assets
 
 
 
 
Investments in subsidiaries
4,815,236 
4,630,570 
 
 
Deferred income taxes
41,065 
0 
 
 
Other assets
43,422 
43,051 
 
 
Total investments and other assets
4,899,723 
4,673,621 
 
 
Total Assets
5,025,340 
4,851,099 
 
 
Current liabilities
 
 
 
 
Accounts payable
5,901 
5,250 
 
 
Accrued taxes (Note 4)
6,904 
12,220 
 
 
Common dividends payable
69,363 
65,790 
 
 
Other current liabilities
33,120 
38,992 
 
 
Total current liabilities
115,288 
122,252 
 
 
Long-term debt less current maturities
125,000 
125,000 
 
 
Deferred credits and other
 
 
 
 
Deferred income taxes
0 
12,055 
 
 
Pension liabilities
21,933 
29,228 
 
 
Other
43,662 
43,462 
 
 
Total deferred credits and other
65,595 
84,745 
 
 
Common stock equity
 
 
 
 
Common stock
2,535,862 
2,509,569 
 
 
Accumulated other comprehensive loss
(44,748)
(68,141)
 
 
Retained earnings
2,092,803 
1,926,065 
 
 
Total shareholders’ equity
4,583,917 
4,367,493 
 
 
Noncontrolling interests
135,540 
151,609 
 
 
Total equity
4,719,457 
4,519,102 
 
 
Total Liabilities and Equity
$ 5,025,340 
$ 4,851,099 
 
 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Statements of Cash Flows (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Cash Flows from Operating Activities
 
 
 
Net income
$ 456,190 
$ 423,696 
$ 439,966 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
571,664 
496,487 
492,322 
Deferred income taxes
236,819 
159,023 
249,296 
Accounts receivable
(22,219)
(52,672)
(44,991)
Accounts payable
(34,266)
(353)
45,414 
Net cash flow provided by operating activities
1,094,327 
1,099,627 
1,153,307 
Cash flows from investing activities
 
 
 
Net cash flow used for investing activities
(1,066,233)
(922,668)
(1,009,401)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
842,415 
731,126 
136,307 
Dividends paid on common stock
(260,027)
(246,671)
(235,244)
Repayment of long-term debt
(415,570)
(652,578)
(122,828)
Common stock equity issuance - net of purchases
19,373 
15,288 
17,319 
Other
1 
161 
299 
Net cash flow provided by (used for) financing activities
3,790 
(178,881)
(160,582)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
31,884 
(1,922)
(16,676)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
7,604 
9,526 
26,202 
CASH AND CASH EQUIVALENTS AT END OF YEAR
39,488 
7,604 
9,526 
Pinnacle West
 
 
 
Cash Flows from Operating Activities
 
 
 
Net income
437,257 
397,595 
406,074 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Equity in earnings of subsidiaries - net
(446,508)
(411,528)
(420,926)
Depreciation and amortization
92 
94 
95 
Deferred income taxes
12,967 
4,406 
(28,806)
Accounts receivable
11,336 
(22,945)
21,671 
Accounts payable
637 
2,017 
(2,449)
Accrued taxes and income tax receivable - net
(12,882)
(1,795)
1,402 
Dividends received from subsidiaries
266,900 
253,600 
242,100 
Other
(6,995)
18,432 
(15,065)
Net cash flow provided by operating activities
262,804 
239,876 
204,096 
Cash flows from investing activities
 
 
 
Construction work in progress
(3,462)
0 
0 
Investments in subsidiaries
(3,491)
(10,236)
(3,400)
Repayments of loans from subsidiaries
157 
322 
2,149 
Advances of loans to subsidiaries
(1,010)
(1,450)
(2,099)
Net cash flow used for investing activities
(7,806)
(11,364)
(3,350)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
0 
125,000 
0 
Dividends paid on common stock
(260,027)
(246,671)
(235,244)
Repayment of long-term debt
0 
(125,000)
0 
Common stock equity issuance - net of purchases
19,373 
15,288 
17,319 
Other
0 
161 
298 
Net cash flow provided by (used for) financing activities
(240,654)
(231,222)
(217,627)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
14,344 
(2,710)
(16,881)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
3,088 
5,798 
22,679 
CASH AND CASH EQUIVALENTS AT END OF YEAR
$ 17,432 
$ 3,088 
$ 5,798 
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) (Reserve for uncollectibles., USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
$ 3,094 
$ 3,203 
$ 3,340 
Additions, Charged to cost and expenses
4,073 
3,942 
4,923 
Additions, Charged to other accounts
0 
0 
0 
Deductions
4,042 
4,051 
5,060 
Balance at end of period
3,125 
3,094 
3,203 
Pinnacle West
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
3,094 
3,203 
3,340 
Additions, Charged to cost and expenses
4,073 
3,942 
4,923 
Additions, Charged to other accounts
0 
0 
0 
Deductions
4,042 
4,051 
5,060 
Balance at end of period
$ 3,125 
$ 3,094 
$ 3,203