PINNACLE WEST CAPITAL CORP, 10-K filed on 2/24/2017
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2016
Feb. 17, 2017
Jun. 30, 2016
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, 2016 
 
 
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
 
 
$ 8,961,361,256 
Entity Common Stock, Shares Outstanding
 
111,340,169 
 
Document Fiscal Year Focus
2016 
 
 
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, 2016 
 
 
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
2016 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
OPERATING REVENUES
$ 3,498,682 
$ 3,495,443 
$ 3,491,632 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,075,510 
1,101,298 
1,179,829 
Operations and maintenance
911,319 
868,377 
908,025 
Depreciation and amortization
485,829 
494,422 
417,358 
Taxes other than income taxes
166,499 
171,812 
172,295 
Other expenses
3,541 
4,932 
2,883 
Total
2,642,698 
2,640,841 
2,680,390 
OPERATING INCOME
855,984 
854,602 
811,242 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
42,140 
35,215 
30,790 
Other income (Note 17)
901 
621 
9,608 
Other expense (Note 17)
(15,337)
(17,823)
(21,746)
Total
27,704 
18,013 
18,652 
INTEREST EXPENSE
 
 
 
Interest charges
205,720 
194,964 
200,950 
Allowance for borrowed funds used during construction (Note 1)
(19,970)
(16,259)
(15,457)
Total
185,750 
178,705 
185,493 
INCOME BEFORE INCOME TAXES
697,938 
693,910 
644,401 
INCOME TAXES (Note 4)
236,411 
237,720 
220,705 
NET INCOME
461,527 
456,190 
423,696 
Less: Net income attributable to noncontrolling interests (Note 18)
19,493 
18,933 
26,101 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
442,034 
437,257 
397,595 
Weighted Average common shares outstanding — basic (in shares)
111,409 
111,026 
110,626 
Weighted Average common shares outstanding — diluted (in shares)
112,046 
111,552 
111,178 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.97 
$ 3.94 
$ 3.59 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 3.95 
$ 3.92 
$ 3.58 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
ELECTRIC OPERATING REVENUES
3,489,754 
3,492,357 
3,488,946 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,082,625 
1,101,298 
1,179,829 
Operations and maintenance
879,108 
853,135 
882,442 
Depreciation and amortization
484,909 
494,298 
417,264 
Taxes other than income taxes
165,779 
171,499 
171,583 
Income taxes (Note 4)
259,353 
260,143 
245,036 
Total
2,871,774 
2,880,373 
2,896,154 
OPERATING INCOME
617,980 
611,984 
592,792 
OTHER INCOME (DEDUCTIONS)
 
 
 
Income taxes (Note 4)
13,511 
14,302 
7,676 
Allowance for equity funds used during construction (Note 1)
42,140 
35,215 
30,790 
Other income (Note 17)
8,607 
2,834 
11,295 
Other expense (Note 17)
(17,514)
(19,019)
(13,403)
Total
46,744 
33,332 
36,358 
INTEREST EXPENSE
 
 
 
Interest on long-term debt
189,828 
180,123 
186,323 
Interest on short-term borrowings
7,983 
7,376 
6,796 
Debt discount, premium and expense
4,760 
4,793 
4,168 
Allowance for borrowed funds used during construction (Note 1)
(19,481)
(16,183)
(15,457)
Total
183,090 
176,109 
181,830 
INCOME TAXES (Note 4)
245,842 
245,841 
237,360 
NET INCOME
481,634 
469,207 
447,320 
Less: Net income attributable to noncontrolling interests (Note 18)
19,493 
18,933 
26,101 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 462,141 
$ 450,274 
$ 421,219 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
NET INCOME
$ 461,527 
$ 456,190 
$ 423,696 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(538)
(957)
(810)
Reclassification of net realized loss, net of tax benefit
2,941 
4,187 
13,483 
Pension and other postretirement benefits activity, net of tax (expense) benefit
(1,477)
20,163 
(2,761)
Total other comprehensive income
926 
23,393 
9,912 
COMPREHENSIVE INCOME
462,453 
479,583 
433,608 
Less: Comprehensive income attributable to noncontrolling interests
19,493 
18,933 
26,101 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
442,960 
460,650 
407,507 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
NET INCOME
481,634 
469,207 
447,320 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(538)
(957)
(809)
Reclassification of net realized loss, net of tax benefit
2,941 
4,187 
13,483 
Pension and other postretirement benefits activity, net of tax (expense) benefit
(729)
18,006 
(7,635)
Total other comprehensive income
1,674 
21,236 
5,039 
COMPREHENSIVE INCOME
483,308 
490,443 
452,359 
Less: Comprehensive income attributable to noncontrolling interests
19,493 
18,933 
26,101 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 463,815 
$ 471,510 
$ 426,258 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Net unrealized loss, tax (expense)
$ (585)
$ (342)
$ (438)
Reclassification of net realized loss, tax benefit
985 
1,801 
7,932 
Pension and other postretirement benefits activity, tax benefit (expense)
633 
(13,302)
1,307 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net unrealized loss, tax (expense)
(585)
(342)
(438)
Reclassification of net realized loss, tax benefit
985 
1,801 
7,932 
Pension and other postretirement benefits activity, tax benefit (expense)
$ 293 
$ (11,776)
$ 4,655 
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 8,881 
$ 39,488 
Customer and other receivables
250,491 
274,691 
Accrued unbilled revenues
107,949 
96,240 
Allowance for doubtful accounts
(3,037)
(3,125)
Materials and supplies (at average cost)
253,979 
234,234 
Fossil fuel (at average cost)
28,608 
45,697 
Income tax receivable (Note 4)
3,751 
589 
Assets from risk management activities (Note 16)
19,694 
15,905 
Deferred fuel and purchased power regulatory asset (Note 3)
12,465 
0 
Other regulatory assets (Note 3)
94,410 
149,555 
Other current assets
45,028 
37,242 
Total current assets
822,219 
890,516 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
1 
12,106 
Nuclear decommissioning trust (Notes 13 and 19)
779,586 
735,196 
Other assets
69,063 
52,518 
Total investments and other assets
848,650 
799,820 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
17,341,888 
16,222,232 
Accumulated depreciation and amortization
(5,970,100)
(5,594,094)
Net
11,371,788 
10,628,138 
Construction work in progress
1,019,947 
816,307 
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)
113,515 
117,385 
Intangible assets, net of accumulated amortization of $603,637 and $546,038
90,022 
123,975 
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228
119,004 
123,139 
Total property, plant and equipment
12,714,276 
11,808,944 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,313,428 
1,214,146 
Assets for other postretirement benefits (Note 7)
166,206 
185,997 
Other
139,474 
128,835 
Total deferred debits
1,619,108 
1,528,978 
Total Assets
16,004,253 
15,028,258 
CURRENT LIABILITIES
 
 
Accounts payable
264,631 
297,480 
Accrued taxes (Note 4)
138,964 
138,600 
Accrued interest
52,835 
56,305 
Common dividends payable
72,926 
69,363 
Short-term borrowings (Note 5)
177,200 
0 
Current maturities of long-term debt (Note 6)
125,000 
357,580 
Customer deposits
82,520 
73,073 
Liabilities from risk management activities (Note 16)
25,836 
77,716 
Liabilities for asset retirements (Note 11)
9,135 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
0 
9,688 
Other regulatory liabilities (Note 3)
99,899 
136,078 
Other current liabilities
244,000 
197,861 
Total current liabilities
1,292,946 
1,442,317 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
4,021,785 
3,462,391 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,945,232 
2,723,425 
Regulatory liabilities (Notes 1, 3, 4 and 7)
948,916 
994,152 
Liabilities for asset retirements (Note 11)
615,340 
415,003 
Liabilities for pension benefits (Note 7)
509,310 
480,998 
Liabilities from risk management activities (Note 16)
47,238 
89,973 
Customer advances
88,672 
115,609 
Coal mine reclamation
221,910 
201,984 
Deferred investment tax credit
210,162 
187,080 
Unrecognized tax benefits (Note 4)
10,046 
9,524 
Other
156,784 
186,345 
Total deferred credits and other
5,753,610 
5,404,093 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,392,053 and 111,095,402 issued at respective dates
2,596,030 
2,541,668 
Treasury stock at cost; 55,317 shares at end of 2016 and 115,030 shares at end of 2015
(4,133)
(5,806)
Total common stock
2,591,897 
2,535,862 
Retained earnings
2,255,547 
2,092,803 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(39,070)
(37,593)
Derivative instruments (Note 16)
(4,752)
(7,155)
Total accumulated other comprehensive loss
(43,822)
(44,748)
Total shareholders’ equity
4,803,622 
4,583,917 
Noncontrolling interests (Note 18)
132,290 
135,540 
Total equity
4,935,912 
4,719,457 
Total Liabilities and Equity
16,004,253 
15,028,258 
ARIZONA PUBLIC SERVICE COMPANY
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
8,840 
22,056 
Customer and other receivables
262,611 
274,428 
Accrued unbilled revenues
107,949 
96,240 
Allowance for doubtful accounts
(3,037)
(3,125)
Materials and supplies (at average cost)
252,777 
234,234 
Fossil fuel (at average cost)
28,608 
45,697 
Income tax receivable (Note 4)
11,174 
0 
Assets from risk management activities (Note 16)
19,694 
15,905 
Deferred fuel and purchased power regulatory asset (Note 3)
12,465 
0 
Other regulatory assets (Note 3)
94,410 
149,555 
Other current assets
41,849 
35,765 
Total current assets
837,340 
870,755 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
1 
12,106 
Nuclear decommissioning trust (Notes 13 and 19)
779,586 
735,196 
Other assets
48,320 
34,455 
Total investments and other assets
827,907 
781,757 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
17,228,787 
16,218,724 
Accumulated depreciation and amortization
(5,881,941)
(5,590,937)
Net
11,346,846 
10,627,787 
Construction work in progress
989,497 
812,845 
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)
113,515 
117,385 
Intangible assets, net of accumulated amortization of $603,637 and $546,038
89,868 
123,820 
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228
119,004 
123,139 
Total property, plant and equipment
12,658,730 
11,804,976 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,313,428 
1,214,146 
Assets for other postretirement benefits (Note 7)
162,911 
182,625 
Other
130,859 
127,923 
Total deferred debits
1,607,198 
1,524,694 
Total Assets
15,931,175 
14,982,182 
CURRENT LIABILITIES
 
 
Accounts payable
259,161 
291,574 
Accrued taxes (Note 4)
130,576 
144,488 
Accrued interest
52,525 
56,003 
Common dividends payable
72,900 
69,400 
Short-term borrowings (Note 5)
135,500 
0 
Current maturities of long-term debt (Note 6)
0 
357,580 
Customer deposits
82,520 
73,073 
Liabilities from risk management activities (Note 16)
25,836 
77,716 
Liabilities for asset retirements (Note 11)
8,703 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
0 
9,688 
Other regulatory liabilities (Note 3)
99,899 
136,078 
Other current liabilities
226,417 
180,535 
Total current liabilities
1,094,037 
1,424,708 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,999,295 
2,764,489 
Regulatory liabilities (Notes 1, 3, 4 and 7)
948,916 
994,152 
Liabilities for asset retirements (Note 11)
607,234 
415,003 
Liabilities for pension benefits (Note 7)
488,253 
459,065 
Liabilities from risk management activities (Note 16)
47,238 
89,973 
Customer advances
88,672 
115,609 
Coal mine reclamation
206,645 
201,984 
Deferred investment tax credit
210,162 
187,080 
Unrecognized tax benefits (Note 4)
37,408 
35,251 
Other
143,560 
142,683 
Total deferred credits and other
5,777,383 
5,405,289 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,421,696 
2,379,696 
Retained earnings
2,331,245 
2,148,493 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(20,671)
(19,942)
Derivative instruments (Note 16)
(4,752)
(7,155)
Total accumulated other comprehensive loss
(25,423)
(27,097)
Total shareholders’ equity
4,905,680 
4,679,254 
Noncontrolling interests (Note 18)
132,290 
135,540 
Total equity
5,037,970 
4,814,794 
Long-term debt less current maturities (Note 6)
4,021,785 
3,337,391 
Total capitalization
9,059,755 
8,152,185 
Total Liabilities and Equity
$ 15,931,175 
$ 14,982,182 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 237,535 
$ 233,665 
Accumulated amortization on intangible assets
603,637 
546,038 
Accumulated amortization on nuclear fuel
147,202 
146,228 
EQUITY
 
 
Common stock, par value
$ 0 
$ 0 
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
111,392,053 
111,095,402 
Treasury stock at cost, shares
55,317 
115,030 
ARIZONA PUBLIC SERVICE COMPANY
 
 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
237,535 
233,665 
Accumulated amortization on intangible assets
603,637 
546,038 
Accumulated amortization on nuclear fuel
$ 147,202 
$ 146,228 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$ 461,527 
$ 456,190 
$ 423,696 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
565,011 
571,664 
496,487 
Deferred fuel and purchased power
(60,303)
14,997 
(26,927)
Deferred fuel and purchased power amortization
38,152 
1,617 
40,757 
Allowance for equity funds used during construction
(42,140)
(35,215)
(30,790)
Deferred income taxes
206,870 
236,819 
159,023 
Deferred investment tax credit
23,082 
8,473 
26,246 
Change in derivative instruments fair value
(403)
(381)
339 
Stock compensation
18,883 
18,756 
33,059 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(2,489)
(22,219)
(52,672)
Accrued unbilled revenues
(11,709)
4,293 
(3,737)
Materials, supplies and fossil fuel
(1,491)
(23,945)
3,724 
Income tax receivable
(3,162)
2,509 
132,419 
Other current assets
(23,324)
3,145 
4,384 
Accounts payable
(66,917)
(34,266)
(353)
Accrued taxes
447 
(2,013)
9,615 
Other current liabilities
29,594 
603 
17,892 
Change in margin and collateral accounts — assets
673 
(324)
(343)
Change in margin and collateral accounts — liabilities
17,735 
22,776 
(24,975)
Change in unrecognized tax benefits
1,628 
(10,328)
2,778 
Change in long-term regulatory liabilities
14,682 
(20,535)
59,618 
Change in other long-term assets
(60,163)
2,426 
(56,561)
Change in other long-term liabilities
(82,793)
(100,715)
(114,052)
Net cash flow provided by operating activities
1,023,390 
1,094,327 
1,099,627 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,275,472)
(1,076,087)
(910,634)
Contributions in aid of construction
64,296 
46,546 
20,325 
Allowance for borrowed funds used during construction
(19,970)
(16,259)
(15,457)
Proceeds from nuclear decommissioning trust sales
633,410 
478,813 
356,195 
Investment in nuclear decommissioning trust
(635,691)
(496,062)
(373,444)
Other
(18,651)
(3,184)
347 
Net cash flow used for investing activities
(1,252,078)
(1,066,233)
(922,668)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
693,151 
842,415 
731,126 
Repayment of long-term debt
(370,430)
(415,570)
(652,578)
Short-term borrowings and payments — net
137,200 
(147,400)
(5,725)
Short-term debt borrowings under revolving credit facility
40,000 
0 
0 
Dividends paid on common stock
(274,229)
(260,027)
(246,671)
Common stock equity issuance and purchases - net
(4,867)
19,373 
15,288 
Distributions to noncontrolling interests
(22,744)
(35,002)
(20,482)
Other
0 
1 
161 
Net cash flow provided by (used for) financing activities
198,081 
3,790 
(178,881)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(30,607)
31,884 
(1,922)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
39,488 
7,604 
9,526 
CASH AND CASH EQUIVALENTS AT END OF YEAR
8,881 
39,488 
7,604 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
9,956 
6,550 
(102,154)
Interest, net of amounts capitalized
184,462 
170,209 
177,074 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
114,855 
83,798 
44,712 
Dividends declared but not paid
72,926 
69,363 
65,790 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
481,634 
469,207 
447,320 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
564,091 
571,540 
496,393 
Deferred fuel and purchased power
(60,303)
14,997 
(26,927)
Deferred fuel and purchased power amortization
38,152 
1,617 
40,757 
Allowance for equity funds used during construction
(42,140)
(35,215)
(30,790)
Deferred income taxes
221,167 
223,069 
155,401 
Deferred investment tax credit
23,082 
8,473 
26,246 
Change in derivative instruments fair value
(403)
(381)
339 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(1,601)
(21,040)
(52,466)
Accrued unbilled revenues
(11,709)
4,293 
(3,737)
Materials, supplies and fossil fuel
(1,454)
(23,945)
3,724 
Income tax receivable
(14,567)
0 
135,179 
Other current assets
(21,640)
4,498 
3,766 
Accounts payable
(67,543)
(34,891)
(2,355)
Accrued taxes
(13,912)
13,378 
8,650 
Other current liabilities
5,097 
(3,718)
33,970 
Change in margin and collateral accounts — assets
673 
(324)
(343)
Change in margin and collateral accounts — liabilities
17,735 
22,776 
(24,975)
Change in unrecognized tax benefits
1,628 
(10,328)
2,778 
Change in long-term regulatory liabilities
14,682 
(20,535)
59,618 
Change in other long-term assets
(45,866)
(813)
(62,739)
Change in other long-term liabilities
(76,855)
(82,628)
(85,642)
Net cash flow provided by operating activities
1,009,948 
1,100,030 
1,124,167 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,248,010)
(1,072,053)
(910,084)
Contributions in aid of construction
64,296 
46,546 
20,325 
Allowance for borrowed funds used during construction
(19,481)
(16,183)
(15,457)
Proceeds from nuclear decommissioning trust sales
633,410 
478,813 
356,195 
Investment in nuclear decommissioning trust
(635,691)
(496,062)
(373,444)
Other
(13,865)
(1,093)
347 
Net cash flow used for investing activities
(1,219,341)
(1,060,032)
(922,118)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
693,151 
842,415 
606,126 
Repayment of long-term debt
(370,430)
(415,570)
(527,578)
Short-term borrowings and payments — net
135,500 
(147,400)
(5,725)
Dividends paid on common stock
(281,300)
(266,900)
(253,600)
Equity infusion from Pinnacle West
42,000 
0 
0 
Distributions to noncontrolling interests
(22,744)
(35,002)
(20,482)
Net cash flow provided by (used for) financing activities
196,177 
(22,457)
(201,259)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(13,216)
17,541 
790 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
22,056 
4,515 
3,725 
CASH AND CASH EQUIVALENTS AT END OF YEAR
8,840 
22,056 
4,515 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
26,864 
14,831 
(86,054)
Interest, net of amounts capitalized
181,809 
167,670 
173,436 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
114,874 
83,798 
44,712 
Dividends declared but not paid
$ 72,900 
$ 69,400 
$ 65,800 
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, 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 
Beginning 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 
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 
 
 
 
 
 
 
 
 
 
Stock compensation cumulative effect adjustments
45,855 
40,380 
 
5,475 
 
 
5,411 
 
 
5,411 
 
 
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 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
461,527 
 
 
442,034 
 
19,493 
481,634 
 
 
462,141 
 
19,493 
Other comprehensive income
926 
 
 
 
926 
 
1,674 
 
 
 
1,674 
 
Dividends on common stock
(284,765)
 
 
(284,765)
 
 
(284,800)
 
 
(284,800)
 
 
Issuance of common stock
13,982 
13,982 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
296,651 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(9,087)
 
(9,087)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(128,105)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
10,760 
 
10,760 
 
 
 
 
 
 
 
 
 
Equity infusion from Pinnacle West
 
 
 
 
 
 
42,000 
 
42,000 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
187,818 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(22,743)
 
 
 
 
(22,743)
(22,743)
 
 
 
 
(22,743)
Ending balance at Dec. 31, 2016
$ 4,935,912 
$ 2,596,030 
$ (4,133)
$ 2,255,547 
$ (43,822)
$ 132,290 
$ 5,037,970 
$ 178,162 
$ 2,421,696 
$ 2,331,245 
$ (25,423)
$ 132,290 
Ending Balance (in shares) at Dec. 31, 2016
111,392,053 
111,392,053 
55,317 
 
 
 
 
71,264,947 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.56 
$ 2.44 
$ 2.33 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies

Description of Business and Basis of Presentation
 
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. 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. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. 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.

Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on net cash flows provided by operating activities. The following tables show the impacts of the reclassifications of the prior years (previously reported) amounts (dollars in thousands):

Statement of Cash Flows for the
Year Ended December 31, 2015
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current
year presentation
Cash Flows from Operating Activities
 

 
 

 
 

Stock compensation
$
—

 
$
18,756

 
$
18,756

Change in other long term liabilities
(81,959
)
 
(18,756
)
 
(100,715
)

Statement of Cash Flows for the
Year Ended December 31, 2014
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current
year presentation
Cash Flows from Operating Activities
 

 
 

 
 

Stock compensation
$
—

 
$
33,059

 
$
33,059

Change in other long-term liabilities
(80,993
)
 
(33,059
)
 
(114,052
)


 
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, 2016 and 2015 consolidated balance sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2016
 
2015
Generation
$
7,874,898

 
$
7,336,902

Transmission
2,746,508

 
2,494,744

Distribution
5,738,801

 
5,543,561

General plant
981,681

 
847,025

Plant in service and held for future use
17,341,888

 
16,222,232

Accumulated depreciation and amortization
(5,970,100
)
 
(5,594,094
)
Net
11,371,788

 
10,628,138

Construction work in progress
1,019,947

 
816,307

Palo Verde sale leaseback, net of accumulated depreciation
113,515

 
117,385

Intangible assets, net of accumulated amortization
90,022

 
123,975

Nuclear fuel, net of accumulated amortization
119,004

 
123,139

Total property, plant and equipment
$
12,714,276

 
$
11,808,944



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, 2016 were as follows:
 
•Fossil plant — 19 years;
•Nuclear plant — 27 years;
•Other generation — 26 years;
•Transmission — 39 years;
•Distribution — 33 years; and
•General plant — 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 $422 million in 2016, $430 million in 2015, and $396 million in 2014. For the years 2014 through 2016, the depreciation rates ranged from a low of 0.30% to a high of 14.12%.  The weighted-average depreciation rate was 2.66% in 2016, 2.74% in 2015, and 2.77% in 2014.
 
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 7.17% for 2016, 8.02% for 2015, and 8.47% for 2014.  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,
 
2016
 
2015
 
2014
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
9,956

 
$
6,550

 
$
(102,154
)
Interest, net of amounts capitalized
184,462

 
170,209

 
177,074

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
114,855

 
$
83,798

 
$
44,712

Dividends declared but not paid
72,926

 
69,363

 
65,790


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 2016, $58 million in 2015, and $53 million in 2014.  Estimated amortization expense on existing intangible assets over the next five years is $41 million in 2017, $23 million in 2018, $12 million in 2019, $4 million in 2020, and $1 million in 2021.  At December 31, 2016, the weighted-average remaining amortization period for intangible assets was 6 years.
 
Investments
 
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments.
 
Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.

Preferred Stock

At December 31, 2016, 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
 
ASU 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting

In March 2016, new stock compensation accounting guidance was issued intended to simplify the accounting for employee share-based payments. The new guidance impacts several aspects of the accounting for share-based payments including: modifies the tax withholding threshold that triggers liability classification of an award, requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, simplifies the accounting for forfeitures, and clarifies certain cash flow presentation matters. Certain aspects of the standard must be adopted using a prospective approach and other aspects must be adopted using a modified retrospective approach.

During the fourth quarter of 2016, we elected to early adopt this standard, and accordingly have applied the guidance effective as of January 1, 2016. Prior to adoption of the new standard, our stock compensation awards were generally classified as liability awards and accounted for at fair value until settled because employees could withhold at more than the minimum statutory tax withholding rate. In accordance with the new guidance, certain of these stock compensation awards are now classified as equity awards and accounted for at grant date fair value. As a result of adopting the new standard, Pinnacle West recorded a cumulative effect adjustment to retained earnings of $6 million. The other provisions of the standard did not have a material impact on our consolidated financial statements. See Note 15 for additional details of the adoption impacts.

ASU 2015-07, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)

In May 2015, new accounting guidance was issued that removes the requirement to categorize certain investments valued using net asset value, as a practical expedient, within the fair value hierarchy. We retrospectively adopted this guidance during the first quarter of 2016. The adoption of this guidance modifies our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.  See Note 7 and Note 13.  

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard 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. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard 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 plan on adopting this standard on January 1, 2018, and are currently evaluating the transition method and the effect on our financial statements. As part of our evaluation we continue to actively monitor certain industry issues being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups may impact our application of the standard, specifically in regards to the treatment of contributions in aid of construction.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new 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 standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements.

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.


ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

                In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business.  The definition of a business  affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are evaluating the impacts of adopting this new standard, and the impacts it may have on our financial statements.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%).

The principal provisions of the application are:

•
a test year ended December 31, 2015, adjusted as described below;
         
•
an original cost rate base of $6.8 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2015;

•
the following proposed capital structure and costs of capital:
 
 
 
Capital Structure
 
Cost of Capital
 
Long-term debt
 
44.20
%
5.13
%
Common stock equity
 
55.80
%
10.50
%
Weighted-average cost of capital
 
 
 
8.13
%
 
•
a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•
a base rate for fuel and purchased power costs of $0.029882 per kWh based on estimated 2017 prices (a decrease from the current base fuel rate of $0.03207 per kWh);

•
authorization to defer for potential future recovery its share of the construction costs associated with installing selective catalytic reduction equipment at Four Corners (estimated at approximately $400 million in direct costs). APS proposes that the rates established in this rate case be increased through a step mechanism beginning in 2019 to reflect these deferred costs;

•
authorization to defer for potential future recovery in the Company’s next general rate case the construction costs APS incurs for its Ocotillo power plant modernization project, once the project reaches commercial operation. APS estimates the direct construction costs at approximately $500 million and that the new facility will be fully in service by early 2019;

•
authorization to defer until the Company’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

•
updates and modifications to four of APS’s adjustor mechanisms - the PSA, the LFCR, the TCA and the Environmental Improvement Surcharge (“EIS”);

•
a number of proposed rate design changes for residential customers, including:
◦
change the on-peak time of use period from 12 p.m. - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;
◦
reduce the difference in the on- and off-peak energy price and lower all energy charges;
◦
offer four rate plan options, three of which have demand charges and a fourth that is available to non-partial requirements customers using less than 600 kWh on average per month; and
◦
modify the current net metering tariff to provide for a credit at the retail rate for the portion of generation by rooftop solar customers that offsets their own load, and for a credit for excess energy delivered to the grid at an export rate.

•
proposed rate design changes for commercial customers, including an aggregation rider that allows certain large customers to qualify for a reduced rate, an extra-high load factor rate schedule for certain customers, and an economic development rate offering for new loads meeting certain criteria.

The Company requested that the increase become effective July 1, 2017.  On July 22, 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months.

The ACC staff and intervenors began filing their direct testimony in late December 2016 and additional filings of testimony are ongoing. On January 12, 2017, APS began settlement discussions with all parties.  On January 13, 2017, the ALJ hearing the case before the ACC issued a procedural order delaying hearings on the case from the originally scheduled March 22, 2017 to April 24, 2017, to allow parties to participate in settlement discussions and prepare testimony on the distributed generation rate design issues addressed in the value and cost of DG decision.  According to the procedural order, settlement discussions are to be completed and, if applicable, any related settlement must be filed by March 17, 2017.  The procedural order also extended the rate case completion date as calculated by Commission rule for an additional 33 days. APS cannot predict the outcome of this case.

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 settlement agreement for the 2009 retail rate case (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 December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC.

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.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. The ACC has not yet ruled on the Company’s 2017 RES Implementation Plan.

In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the EPA.  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  APS cannot predict the outcome of this proceeding.
 
Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC 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. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program.

On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on the Company’s 2017 DSM Plan.    
 
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. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.
 
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 2016 and 2015 (dollars in thousands):
 
 
Year Ended December 31,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,926

Deferred fuel and purchased power costs - current period
60,303

 
(14,997
)
Amounts charged to customers
(38,150
)
 
(1,617
)
Ending balance
$
12,465

 
$
(9,688
)

 
The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. 
 
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, 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.

Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 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, 2016.

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 to make changes to their protocols in the future. As a result, APS is evaluating how its formula rate protocols compare with more recently approved formula rate protocols and anticipates that it will make a filing to update its formula rate protocols in the first quarter of 2017.
 
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 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. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two month delay in implementation did not have an adverse effect on APS. APS filed its 2017 LFCR adjustment on January 13, 2017. APS requested an adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective the first billing cycle of March 2017.

Net Metering

In 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 was held in April 2016. On October 7, 2016, the ALJ issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed.  The price established by this resource comparison proxy method will be updated annually (between rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by that utility for exported distributed energy.

In addition, the ACC made the following determinations:

•
Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS' pending rate case will be grandfathered for a period of 20 years from the date of interconnection;

•
Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

•
Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case, which is scheduled for hearing by the ACC in April 2017.  APS cannot predict the outcome of this determination.

The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC's request for rehearing is required for TASC to challenge this decision in court. To date, the ACC has taken no action on the rehearing request. The ACC's decision is expected to remain in effect during any legal challenge.

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 on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.

System Benefits Charge

The 2012 Settlement Agreement  provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016.  Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge.  The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas.  Commissioner Burns has also scheduled a workshop in this matter for March 17, 2017.  APS and Pinnacle West 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 $64 million as of December 31, 2016 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 suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. 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.   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 established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

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. On January 13, 2017, EPA approved a final rule incorporating APS's compromise proposal. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review.

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 is seeking recovery of the unit’s decommissioning and other retirement-related costs over the previously estimated remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($116 million as of December 31, 2016), 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.

Navajo Plant

On February 13, 2017, the co-owners of the Navajo Plant voted not to pursue continued operation of the plant beyond December 2019, the expiration of the current lease term, and to pursue a new lease or lease extension with the Navajo Nation that would allow decommissioning activities to begin after December 2019 instead of later this year. Various stakeholders including regulators, tribal representatives and others interested in the continued operation of the plant intend to meet to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. We cannot predict whether any alternate solutions will be found that would be acceptable to all of the stakeholders and feasible to implement. APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($108 million as of December 31, 2016, see Note 9 for additional details) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. We cannot predict whether APS would obtain such recovery.
    
On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.


Regulatory Assets and Liabilities
 
The detail of regulatory assets is as follows (dollars in thousands):
S
Amortization Through
 
December 31, 2016
 
December 31, 2015
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
711,059

 
$
—

 
$
619,223

Retired power plant costs
2033
 
9,913

 
117,591

 
9,913

 
127,518

Income taxes - AFUDC equity
2046
 
6,305

 
152,118

 
5,495

 
133,712

Deferred fuel and purchased power — mark-to-market (Note 16)
2020
 
—

 
42,963

 
71,852

 
69,697

Four Corners cost deferral
2024
 
6,689

 
56,894

 
6,689

 
63,582

Income taxes — investment tax credit basis adjustment
2046
 
2,120

 
54,356

 
1,766

 
48,462

Lost fixed cost recovery
2017
 
61,307

 
—

 
45,507

 
—

Palo Verde VIEs (Note 18)
2046
 
—

 
18,775

 
—

 
18,143

Deferred compensation
2036
 
—

 
35,595

 
—

 
34,751

Deferred property taxes
(d)
 
—

 
73,200

 
—

 
50,453

Loss on reacquired debt
2038
 
1,637

 
16,942

 
1,515

 
16,375

AG-1 deferral
2018
 
—

 
5,868

 
—

 
—

Demand side management (b)
2017
 
3,744

 
—

 
—

 
—

Tax expense of Medicare subsidy
2024
 
1,513

 
10,589

 
1,520

 
12,163

Transmission vegetation management
2016
 
—

 
—

 
4,543

 
—

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,708

 
332

 
11,040

Deferred fuel and purchased power (b) (c)
2017
 
12,465

 
—

 
—

 
—

Coal reclamation
2026
 
418

 
5,182

 
418

 
6,085

Other
Various
 
432

 
1,588

 
5

 
2,942

Total regulatory assets (e)
 
 
$
106,875

 
$
1,313,428

 
$
149,555

 
$
1,214,146


(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, 2016
 
December 31, 2015
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
279,976

 
$
—

 
$
277,554

Removal costs
(a)
 
29,899

 
223,145

 
39,746

 
240,367

Other postretirement benefits
(d)
 
32,662

 
123,913

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2046
 
4,368

 
108,827

 
3,604

 
97,175

Income taxes - change in rates
2045
 
1,771

 
70,898

 
1,113

 
72,454

Spent nuclear fuel
2047
 
—

 
71,726

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
26,809

 
—

 
43,773

 
4,365

Demand side management (b)
2019
 
—

 
20,472

 
6,079

 
19,115

Sundance maintenance
2030
 
—

 
15,287

 
—

 
13,678

Deferred fuel and purchased power (b) (c)
2016
 
—

 
—

 
9,688

 
—

Deferred gains on utility property
2018
 
2,063

 
8,895

 
2,062

 
6,001

Four Corners coal reclamation
2031
 
—

 
18,248

 
—

 
8,920

Other
Various
 
2,327

 
7,529

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
99,899

 
$
948,916

 
$
145,766

 
$
994,152


(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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Total unrecognized tax benefits, January 1
$
34,447

 
$
44,775

 
$
41,997

 
$
34,447

 
$
44,775

 
$
41,997

Additions for tax positions of the current year
2,695

 
2,175

 
4,309

 
2,695

 
2,175

 
4,309

Additions for tax positions of prior years
886

 
—

 
751

 
886

 
—

 
751

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(1,953
)
 
(10,244
)
 
(2,282
)
 
(1,953
)
 
(10,244
)
 
(2,282
)
Settlements with taxing authorities
—

 
—

 
—

 
—

 
—

 
—

Lapses of applicable statute of limitations
—

 
(2,259
)
 
—

 
—

 
(2,259
)
 
—

Total unrecognized tax benefits, December 31
$
36,075

 
$
34,447

 
$
44,775

 
$
36,075

 
$
34,447

 
$
44,775



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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Tax positions, that if recognized, would decrease our effective tax rate
$
11,313

 
$
9,523

 
$
11,207

 
$
11,313

 
$
9,523

 
$
11,207


 
As of the balance sheet date, the tax year ended December 31, 2013 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 2012.
 
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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Unrecognized tax benefit interest expense/(benefit) recognized
$
529

 
$
(161
)
 
$
752

 
$
529

 
$
(161
)
 
$
752


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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Unrecognized tax benefit interest accrued
$
1,333

 
$
804

 
$
965

 
$
1,333

 
$
804

 
$
965



Additionally, as of December 31, 2016, 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,
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Current:
 

 
 

 
 

 
 
 
 
 
 
Federal
$
8,630

 
$
(12,335
)
 
$
25,054

 
$
711

 
$
6,485

 
$
40,115

State
1,259

 
4,763

 
10,382

 
4,276

 
7,813

 
15,598

Total current
9,889

 
(7,572
)
 
35,436

 
4,987

 
14,298

 
55,713

Deferred:
 

 
 

 
 

 
 

 
 

 
 

Federal
201,743

 
221,505

 
167,365

 
215,178

 
208,326

 
165,027

State
24,779

 
23,787

 
17,904

 
25,677

 
23,217

 
16,620

Total deferred
226,522

 
245,292

 
185,269

 
240,855

 
231,543

 
181,647

Income tax expense
$
236,411

 
$
237,720

 
$
220,705

 
$
245,842

 
$
245,841

 
$
237,360



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,
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Federal income tax expense at 35% statutory rate
$
244,278

 
$
242,869

 
$
225,540

 
$
254,617

 
$
250,267

 
$
239,638

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

 
 

 
 

 
 

State income tax net of federal income tax benefit
16,311

 
18,265

 
18,149

 
18,750

 
20,433

 
21,148

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

 
(2,169
)
 
—

 
—

 
(1,892
)
 
—

Medicare Subsidy Part-D
844

 
837

 
830

 
844

 
837

 
830

Allowance for equity funds used during construction (see Note 1)
(11,724
)
 
(9,711
)
 
(8,523
)
 
(11,724
)
 
(9,711
)
 
(8,523
)
Palo Verde VIE noncontrolling interest (see Note 18)
(6,823
)
 
(6,626
)
 
(9,135
)
 
(6,823
)
 
(6,626
)
 
(9,135
)
Investment tax credit amortization
(5,887
)
 
(5,527
)
 
(4,928
)
 
(5,887
)
 
(5,527
)
 
(4,928
)
Other
(588
)
 
(218
)
 
(1,228
)
 
(3,935
)
 
(1,940
)
 
(1,670
)
Income tax expense
$
236,411

 
$
237,720

 
$
220,705

 
$
245,842

 
$
245,841

 
$
237,360


 
    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, 2016, APS has recorded a regulatory liability of $74 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
 
On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2016, 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,
 
2016
 
2015
 
2016
 
2015
DEFERRED TAX ASSETS
 

 
 

 
 
 
 
Risk management activities
$
26,614

 
$
70,498

 
$
26,614

 
$
70,498

Regulatory liabilities:
 

 
 

 
 

 
 
Asset retirement obligation and removal costs
200,140

 
216,765

 
200,140

 
216,765

Unamortized investment tax credits
113,195

 
100,779

 
113,195

 
100,779

Other postretirement benefits
60,375

 
83,034

 
60,375

 
83,034

Other
63,311

 
60,707

 
63,311

 
60,707

Pension liabilities
204,436

 
191,028

 
194,981

 
181,787

Renewable energy incentives
56,379

 
60,956

 
56,379

 
60,956

Credit and loss carryforwards
75,944

 
59,557

 
1,645

 
—

Other
158,421

 
149,033

 
187,453

 
176,016

Total deferred tax assets
958,815

 
992,357

 
904,093

 
950,542

DEFERRED TAX LIABILITIES
 

 
 

 
 

 
 
Plant-related
(3,297,989
)
 
(3,116,752
)
 
(3,297,989
)
 
(3,116,752
)
Risk management activities
(7,594
)
 
(10,626
)
 
(7,594
)
 
(10,626
)
Other postretirement assets
(63,477
)
 
(71,737
)
 
(62,819
)
 
(70,986
)
Regulatory assets:
 

 
 

 
 
 
 

Allowance for equity funds used during construction
(61,088
)
 
(54,110
)
 
(61,088
)
 
(54,110
)
Deferred fuel and purchased power — mark-to-market
(21,396
)
 
(55,020
)
 
(21,396
)
 
(55,020
)
Pension benefits
(274,184
)
 
(240,692
)
 
(274,184
)
 
(240,692
)
Retired power plant costs (see Note 3)
(49,166
)
 
(53,420
)
 
(49,166
)
 
(53,420
)
Other
(123,987
)
 
(108,441
)
 
(123,987
)
 
(108,441
)
Other
(5,166
)
 
(4,984
)
 
(5,165
)
 
(4,984
)
Total deferred tax liabilities
(3,904,047
)
 
(3,715,782
)
 
(3,903,388
)
 
(3,715,031
)
Deferred income taxes — net
$
(2,945,232
)
 
$
(2,723,425
)
 
$
(2,999,295
)
 
$
(2,764,489
)

 
As of December 31, 2016, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $98 million, which first begin to expire in 2031, and other federal and state loss carryforwards of $5 million, which first begin to expire in 2019. The credit and loss carryforwards amount above has been reduced by $27 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, 2016 and 2015 (dollars in thousands):
 
 
December 31, 2016
 
December 31, 2015
 
Pinnacle West
APS
Total
 
Pinnacle West
APS
Total
Commitments under Credit Facilities
$
275,000

$
1,000,000

$
1,275,000

 
$
200,000

$
1,000,000

$
1,200,000

Outstanding Commercial Paper and Revolving Credit Facility Borrowings
(41,700
)
(135,500
)
(177,200
)
 
—

—

—

Amount of Credit Facilities Available
$
233,300

$
864,500

$
1,097,800

 
$
200,000

$
1,000,000

$
1,200,000

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

Pinnacle West
 
On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $200 million facility that matures in May 2021. 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, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $1.7 million commercial paper borrowings.

On August 31, 2016, PNW entered into a $75 million 364-day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At December 31, 2016, Pinnacle West had $40 million outstanding under the facility.
 
APS
 
During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021.

At December 31, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021. APS may increase the amount of each facility up to a maximum of $700 million, 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 $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2016, APS had $135.5 million of commercial paper outstanding and 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, 2016 and 2015 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2016
 
2015
APS
 
 
 
 
 

 
 

Pollution control bonds:
 
 
 
 
 

 
 

Variable
2029
 
(b)
 
$
35,975

 
$
92,405

Fixed
2024-2029
 
1.75%-4.70%
 
147,150

 
211,150

Total pollution control bonds
 
 
 
 
183,125

 
303,555

Senior unsecured notes
2019-2046
 
2.20%-8.75%
 
3,725,000

 
3,375,000

Term loans
2018-2019
 
(c)
 
150,000

 
50,000

Unamortized discount
 
 
 
 
(11,816
)
 
(10,374
)
Unamortized premium
 
 
 
 
4,506

 
4,686

Unamortized debt issuance cost
 
 
 
 
(29,030
)
 
(27,896
)
Total APS long-term debt
 
 
 
 
4,021,785

 
3,694,971

Less current maturities

 
 
 
—

 
357,580

Total APS long-term debt less current maturities
 
 
 
 
4,021,785

 
3,337,391

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(d)
 
125,000

 
125,000

Less current maturities
 
 
 
 
125,000

 
—

Total PNW long-term debt less current maturities
 
 
 
 
—

 
125,000

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
4,021,785

 
$
3,462,391


(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 0.81% at December 31, 2016 and 0.01%-0.24% at December 31, 2015.
(c)
The weighted-average interest rate was 1.427% at December 31, 2016, and 1.024% at December 31, 2015.
(d)                                 The interest rate was 1.520% at December 31, 2016 and 1.174% at December 31, 2015.


 
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
2017
 
$
125,000

 
$
—

2018
 
82,000

 
82,000

2019
 
600,000

 
600,000

2020
 
250,000

 
250,000

2021
 
—

 
—

Thereafter
 
3,126,125

 
3,126,125

Total
 
$
4,183,125

 
$
4,058,125


 
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, 2016
 
As of
December 31, 2015
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,021,785

 
4,300,789

 
3,694,971

 
3,981,367

Total
$
4,146,785

 
$
4,425,789

 
$
3,819,971

 
$
4,106,367


 
Credit Facilities and Debt Issuances
 
APS
 
On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. 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 May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E.

On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A.

On August 1, 2016, APS repaid at maturity APS's $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016.

On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016.

On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B.

On December 6, 2016, APS redeemed at par and canceled all $17 million of the Coconino County Arizona Pollution Control Corporation Revenue Bonds (Arizona Public Service Company Project), Series 1998.

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, 2016, the ratio was approximately 48% for Pinnacle West and 47% 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, 2016, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.1 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.6 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2016.

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 other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries.  These plans provide 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 is providing 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 approval to move up to $140 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to move into a new account to pay for active union employee medical costs. As of December 31, 2016, such methodology would result in an amount of approximately $140 million being transferred to the new account.

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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Service cost-benefits earned during the period
$
53,792

 
$
59,627

 
$
53,080

 
$
14,993

 
$
16,827

 
$
18,139

Interest cost on benefit obligation
131,647

 
123,983

 
129,194

 
29,721

 
28,102

 
41,243

Expected return on plan assets
(173,906
)
 
(179,231
)
 
(158,998
)
 
(36,495
)
 
(36,855
)
 
(46,400
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
527

 
594

 
869

 
(37,883
)
 
(37,968
)
 
(9,626
)
Net actuarial loss
40,717

 
31,056

 
10,963

 
4,589

 
4,881

 
1,175

Net periodic benefit cost
$
52,777

 
$
36,029

 
$
35,108

 
$
(25,075
)
 
$
(25,013
)
 
$
4,531

Portion of cost charged to expense
$
26,172

 
$
20,036

 
$
21,985

 
$
(12,435
)
 
$
(10,391
)
 
$
6,000


 
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2016 and 2015 (dollars in thousands):
 
Pension
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
3,033,803

 
$
3,078,648

 
$
647,020

 
$
682,335

Service cost
53,792

 
59,627

 
14,993

 
16,827

Interest cost
131,647

 
123,983

 
29,721

 
28,102

Benefit payments
(142,247
)
 
(137,115
)
 
(26,231
)
 
(24,988
)
Actuarial (gain) loss
127,467

 
(91,340
)
 
50,942

 
(55,256
)
Benefit obligation at December 31
3,204,462

 
3,033,803

 
716,445

 
647,020

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,542,774

 
2,615,404

 
833,017

 
834,625

Actual return on plan assets
166,408

 
(44,690
)
 
63,463

 
(2,399
)
Employer contributions
100,000

 
100,000

 
819

 
791

Benefit payments
(133,825
)
 
(127,940
)
 
(14,648
)
 
—

Fair value of plan assets at December 31
2,675,357

 
2,542,774

 
882,651

 
833,017

Funded Status at December 31
$
(529,105
)
 
$
(491,029
)
 
$
166,206

 
$
185,997



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, 2016 and 2015 (dollars in thousands):
 
2016
 
2015
Projected benefit obligation
$
3,204,462

 
$
3,033,803

Accumulated benefit obligation
3,049,406

 
2,873,467

Fair value of plan assets
2,675,357

 
2,542,774


 
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2016 and 2015 (dollars in thousands):
 
Pension
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
Noncurrent asset
$
—

 
$
—

 
$
166,206

 
$
185,997

Current liability
(19,795
)
 
(10,031
)
 
—

 
—

Noncurrent liability
(509,310
)
 
(480,998
)
 
—

 
—

Net amount recognized
$
(529,105
)
 
$
(491,029
)
 
$
166,206

 
$
185,997


 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2016 and 2015 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
Net actuarial loss
$
773,750

 
$
679,501

 
$
146,509

 
$
127,124

Prior service cost (credit)
81

 
609

 
(303,417
)
 
(341,301
)
APS’s portion recorded as a regulatory (asset) liability
(711,059
)
 
(619,223
)
 
156,575

 
213,621

Income tax expense (benefit)
(24,202
)
 
(23,663
)
 
833

 
925

Accumulated other comprehensive loss
$
38,570

 
$
37,224

 
$
500

 
$
369


 
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 2017 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
46,971

 
$
5,181

Prior service cost (credit)
81

 
(37,842
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017
$
47,052

 
$
(32,661
)


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,
 
2016
 
2015
 
2016
 
2015
2014
 
 
 
 
 
 
 
 
 
January - September
October - December
 
Discount rate – pension
4.08
%
 
4.37
%
 
4.37
%
 
4.02
%
4.88
%
4.88
%
 
Discount rate – other benefits
4.17
%
 
4.52
%
 
4.52
%
 
4.14
%
5.10
%
4.41
%
 
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
%
6.90
%
 
Expected long-term return on plan assets - other benefits
N/A

 
N/A

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

 
0

4

0

 

 
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 2017, we are assuming a 6.55% long-term rate of return for pension assets and 6.37% (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
$
8,430

 
$
(5,455
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
8,440

 
(6,527
)
Effect on the accumulated other postretirement benefit obligation
108,046

 
(86,651
)

 
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.
 
Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended 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 and other government agencies, U.S Treasury Futures Contracts, and fixed income debt securities issued by corporations.  Long-term fixed income assets may also include interest rate swaps, 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 also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds.
 
Based on the IPS, and given the pension plan’s funded status at year-end 2016, 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, 2016, long-term fixed income assets represented 57% of total pension plan assets, and return-generating assets represented 43% of total pension plan assets.
 
As of December 31, 2016, 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, 2016, investment in fixed income assets represented 51% of the other postretirement benefit plan total assets, and non-fixed income assets represented 49% of the other postretirement benefit plan’s assets. 
 
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, U.S Treasury Futures Contracts, 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.  U.S Treasury Future Contracts are valued using the quoted active market prices from the exchange on which they trade, 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. Mutual funds, classified as Level 1, are valued using a NAV that is observable and 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. Investments in common and collective trusts are valued using NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. 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, 2016, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. The NAV for these investments 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, 2016, approximately $54 million of these commitments have been funded.
 
The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value.  We have internal control procedures to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016, 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)
 
Other (a)
 
Balance at December 31, 2016
Pension Plan:
 

 
 

 
 
 
 

Cash and cash equivalents
$
13,995

 
$
—

 
$
—

 
$
13,995

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
1,210,453

 
—

 
1,210,453

U.S. Treasury
112,583

 
—

 
—

 
112,583

Other (b)
—

 
102,170

 
—

 
102,170

Common stock equities (c)
235,109

 
—

 
—

 
235,109

Mutual funds (d)
251,506

 
—

 
—

 
251,506

Common and collective trusts:
 
 
 
 
 
 
 
   Equities
—

 
—

 
266,840

 
266,840

   Real estate
—

 
—

 
161,449

 
161,449

Partnerships
—

 
—

 
208,915

 
208,915

Short-term investments and other (e)
—

 
—

 
112,337

 
112,337

Total
$
613,193

 
$
1,312,623

 
$
749,541

 
$
2,675,357

Other Benefits:
 

 
 

 
 
 
 

Cash and cash equivalents
$
304

 
$
—

 
$
—

 
$
304

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
268,193

 
—

 
268,193

U.S. Treasury
145,255

 
—

 
—

 
145,255

Other (b)
—

 
34,506

 
—

 
34,506

Common stock equities (c)
243,741

 
—

 
—

 
243,741

Mutual funds (d)
67,418

 
—

 
—

 
67,418

Common and collective trusts:
 

 
 

 
 
 
 

   Equities
—

 
—

 
95,814

 
95,814

   Real estate
—

 
—

 
14,509

 
14,509

Partnerships
—

 
—

 
3,060

 
3,060

Short-term investments and other (e)
—

 
—

 
9,851

 
9,851

Total
$
456,718

 
$
302,699

 
$
123,234

 
$
882,651


(a)
These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.
(b)
This category consists primarily of debt securities issued by municipalities.
(c)
This category primarily consists of US common stock equities.
(d)
These funds invest in US and international common stock equities.
(e)
This category includes 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)
 
Other (a)
 
Balance at December 31, 2015
Pension Plan:
 

 
 

 
 
 
 

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 (b)
—

 
113,008

 
—

 
113,008

Common stock equities (c)
247,701

 
—

 
—

 
247,701

Mutual funds - International equities
116,307

 
—

 
—

 
116,307

Common and collective trusts:
 
 
 
 
 
 
 
Equities
—

 
—

 
315,989

 
315,989

Real Estate
—

 
—

 
150,359

 
150,359

Partnerships
—

 
—

 
169,937

 
169,937

Short-term investments and other (d)
—

 
—

 
44,066

 
44,066

Total
$
640,679

 
$
1,221,744

 
$
680,351

 
$
2,542,774

Other Benefits:
 

 
 

 
 
 
 

Cash and cash equivalents
$
240

 
$
—

 
$
—

 
$
240

Fixed Income Securities:
 

 
 

 
 
 
 

Corporate
—

 
217,026

 
—

 
217,026

U.S. Treasury
131,435

 
—

 
—

 
131,435

Other (b)
—

 
31,106

 
—

 
31,106

Common stock equities (c)
265,583

 
—

 
—

 
265,583

Mutual funds - International equities
52,568

 
—

 
—

 
52,568

Common and collective trusts:
 
 
 
 
 
 
 
Equities
—

 
—

 
110,055

 
110,055

Real Estate
—

 
—

 
13,512

 
13,512

Short-term investments and other (d)
—

 
—

 
11,492

 
11,492

Total
$
449,826

 
$
248,132

 
$
135,059

 
$
833,017


(a)
These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.
(b)
This category consists primarily of debt securities issued by municipalities.
(c)
This category primarily consists of US common stock equities.
(d)
This category includes plan receivables and payables.

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 2016, $100 million in 2015, and $175 million in 2014.  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 2017-2019 period.  With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2016, 2015 and 2014.  We expect to make contributions of less than $1 million in total for 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 approximately $100 million in 2016, $100 million in 2015 and $175 million in 2014.  APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2016, 2015 and 2014.
 
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
2017
 
$
172,859

 
$
31,126

2018
 
173,232

 
33,795

2019
 
182,944

 
36,195

2020
 
191,037

 
37,998

2021
 
196,292

 
39,368

Years 2022-2026
 
1,049,149

 
201,944


 
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 2016, 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 $10 million for 2016, $9 million for 2015, and $9 million for 2014.
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. See Note 2 for a discussion of the new lease accounting standard.
 
Total lease expense recognized in the Consolidated Statements of Income was $16 million in 2016, $17 million in 2015, and $18 million in 2014.  APS’s lease expense was $15 million in 2016, $14 million in 2015, and $15 million in 2014.
 
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
2017
 
$
12,330

 
$
11,919

2018
 
10,987

 
10,690

2019
 
9,019

 
8,767

2020
 
7,688

 
7,439

2021
 
5,266

 
5,020

Thereafter
 
59,647

 
57,207

Total future lease commitments
 
$
104,937

 
$
101,042


 
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 Statements 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, 2016 (dollars in thousands):

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

 
 
 
 

 
 

 
 

 
Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,770,324

 
$
1,080,072

 
$
17,615

 
Palo Verde Unit 2 (a)
 
16.8
%
 

 
581,572

 
360,757

 
9,717

 
Palo Verde Common
 
28.0
%
 
(b)
 
672,799

 
242,649

 
62,479

 
Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
237,535

 
—

 
Four Corners Generating Station
 
63.0
%
 

 
934,837

 
578,924

 
248,072

 
Navajo Generating Station Units 1, 2 and 3
 
14.0
%
 

 
279,629

 
176,931

 
5,761

 
Cholla common facilities (c)
 
63.3
%
 
(b)
 
159,707

 
58,276

 
806

(d)
Transmission facilities:
 
 

 
 
 
 

 
 

 
 

 
ANPP 500kV System
 
33.6
%
 
 (b)
 
127,970

 
38,610

 
2,291

 
Navajo Southern System
 
22.5
%
 
(b)
 
62,135

 
20,491

 
334

 
Palo Verde — Yuma 500kV System
 
19.0
%
 
(b)
 
13,699

 
5,368

 
408

 
Four Corners Switchyards
 
51.3
%
 
 (b)
 
39,850

 
10,474

 
1,044

 
Phoenix — Mead System
 
17.1
%
 
(b)
 
39,330

 
13,725

 
85

 
Palo Verde — Rudd 500kV System
 
50.0
%
 
(b)
 
91,904

 
19,818

 
227

 
Morgan — Pinnacle Peak System
 
65.2
%
 
 (b)
 
140,374

 
13,557

 
—

 
Round Valley System
 
50.0
%
 
(b)
 
515

 
127

 
—

 
Palo Verde — Morgan System
 
85.8
%
 
(b)
 
125,908

 
1,326

 
28,949

 
Hassayampa — North Gila System
 
80.0
%
 
(b)
 
142,541

 
3,231

 
—

 
Cholla 500kV Switchyard
 
85.7
%
 
(b)
 
5,078

 
1,201

 
—

 
Saguaro 500kV Switchyard
 
75.0
%
 
(b)
 
20,456

 
12,426

 
2

 

(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.
(d)
Due to the closure of Cholla Unit 2 in 2015, all new Cholla common facilities construction is owned by APS at 50.5%

4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. At December 31, 2016, 4CA had plant in service of $110 million, accumulated depreciation of $79 million and construction work in progress of $30 million.
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 the DOE in the Court of Federal Claims.  The lawsuit sought to recover damages incurred due to DOE’s breach of the 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 reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019.

APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2016, and approved on February 1, 2017, in the amount of $11.3 million (APS’s share is $3.3 million). Payment for the claim is expected in the second quarter of 2017.
  
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-wide 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 approximately $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million (on January 1, 2017 this coverage was increased to $450 million), which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.1 billion (on January 1, 2017 this balance was decreased to $13.0 billion) of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $18.9 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments 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 $23.8 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 $64 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 2017 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $977 million in 2017; $737 million in 2018; $598 million in 2019; $525 million in 2020; $524 million in 2021; and $7.3 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,
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
Coal take-or-pay commitments (a)
$
195,428

 
$
189,588

 
$
193,818

 
$
198,160

 
$
202,619

 
$
2,068,355

 
(a)
Total take-or-pay commitments are approximately $3.0 billion.  The total net present value of these commitments is approximately $2.1 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 amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):
 
 
Year Ended December 31,
 
2016
 
2015
 
2014
Total purchases
$
160,066

 
$
211,327

 
$
236,773


 
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 $40 million in 2017; $40 million in 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; and $420 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.
 
Coal Mine Reclamation Obligations
 
APS and 4CA 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 $207 million at December 31, 2016 and $202 million at December 31, 2015. 4CA recorded an obligation for the coal mine final reclamation of approximately $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows:  $17 million in 2017; $18 million in 2018; $19 million in 2019; $21 million in 2020; $22 million in 2021; and $241 million thereafter.  4CA expects to make payments for the final mine reclamation as follows: $1 million in 2017; $1 million in 2018; $1 million in 2019; $1 million in 2020; $2 million in 2021; and $17 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 RI/FS work plan.  The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by June 2017. 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.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. 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.  On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016.
 
Environmental Matters
 
APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, 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 and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. EPA recently approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the recent Cholla rule approval.

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required 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. 4CA purchased the El Paso interest on July 6, 2016. NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. 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. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million 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. 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 a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program.  EPA signed the final rule approving the Agency's proposal on January 13, 2017. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review.
 
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. 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 majority of which has already been incurred. Litigation concerning the rules, including supplemental analyses EPA has prepared in support of the MATS regulation, is ongoing. These proceedings do not materially impact APS.  Regardless of the results from further judicial or administrative proceedings concerning 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. 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.

On December 16, 2016, President Obama signed the WIIN Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds. Because EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act, and Arizona has yet to determine whether it will develop a state-specific permitting program, it is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR.

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. APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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, the majority of which has already been incurred. Additionally, the CCR rule requires ongoing groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next 3 years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

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, this timing will be impacted by the court-imposed stay described below.

Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ is continuing to assess alternatives while completing outreach and soliciting feedback from stakeholders. In addition to these ongoing 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 a 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 or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains ongoing, 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 and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, 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.
 
Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners.

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 in the amount of $0.8 million 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.

On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above, is approximately $0.8 million.
 
Peabody Bankruptcy

On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri.  Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona.  APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement.  

On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleged that the Buyers breached the Agreement. On January 27, 2017, the bankruptcy court approved a settlement between the parties, and on February 6, 2017 the parties executed an amendment to the Coal Supply Agreement that allows for continuation of the agreement with modified terms and conditions acceptable to the parties.

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 commodity contract collateral obligations and other transactions. As of December 31, 2016, standby letters of credit totaled $35 million and will expire in 2017. As of December 31, 2016, surety bonds expiring through 2019 totaled $53 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, 2016. Effective July 6, 2016, Pinnacle West has issued two parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.
Asset Retirement Obligations
Asset Retirement Obligations
Asset Retirement Obligations
 
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation 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 2016, APS recognized an ARO for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million. In addition, 4CA acquired El Paso's share of Four Corners Units 4 & 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million. In addition, Four Corners spent $16 million in actual decommissioning costs. Finally, in 2016, APS received a new decommissioning study for the Palo Verde Nuclear Generating Station. This resulted in an increase to the ARO in the amount of $151 million, an increase in plant in service of $131 million, and a reduction of the regulatory liability of $20 million.

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.
 
The following table shows the change in our asset retirement obligations for 2016 and 2015 (dollars in thousands):

 
2016
 
2015
Asset retirement obligations at the beginning of year
$
443,576

 
$
390,750

Changes attributable to:
 

 
 

Accretion expense
26,656

 
25,163

Settlements
(15,732
)
 
(32,048
)
Estimated cash flow revisions
151,046

 
17,556

Newly incurred or acquired obligations
18,929

 
42,155

Asset retirement obligations at the end of year
$
624,475

 
$
443,576


 
Decommissioning activities for Four Corners Units 1-3 began in January 2014. Thus, $9 million of the total ARO of $624 million at December 31, 2016, is classified as a current liability on the balance sheet. At December 31, 2015, $29 million of the total ARO of $444 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 2016 and 2015 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.

 
2016 Quarter Ended
 
2016
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
677,167

 
$
915,394

 
$
1,166,922

 
$
739,199

 
$
3,498,682

Operations and maintenance
243,195

 
242,279

 
217,568

 
208,277

 
911,319

Operating income
50,162

 
231,748

 
451,258

 
122,816

 
855,984

Income taxes
1,914

 
65,742

 
141,446

 
27,309

 
236,411

Net income
9,326

 
126,182

 
267,900

 
58,119

 
461,527

Net income attributable to common shareholders
4,453

 
121,308

 
263,027

 
53,246

 
442,034

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.04

 
$
1.09

 
$
2.36

 
$
0.48

 
$
3.97

Net income attributable to common shareholders — Diluted
0.04

 
1.08

 
2.35

 
0.47

 
3.95

 
 
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

Selected Quarterly Financial Data (Unaudited) 
Selected Quarterly Financial Data (Unaudited) - APS
 
APS's quarterly financial information for 2016 and 2015 is as follows (dollars in thousands):
 
 
2016 Quarter Ended,
 
2016
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
676,632

 
$
909,757

 
$
1,166,359

 
$
737,006

 
$
3,489,754

Operations and maintenance
238,711

 
233,712

 
209,366

 
197,319

 
879,108

Operating income
48,930

 
165,684

 
307,601

 
95,765

 
617,980

Net income attributable to common shareholder
7,253

 
127,188

 
269,220

 
58,480

 
462,141

 
 
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

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.
 
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.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires certain instruments valued using NAV to no longer be classified within the fair value hierarchy. As such, certain instruments valued using NAV are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments.  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.

Coal Reclamation Trust Investments

The coal reclamation trust holds cash equivalent investments in money market funds that are valued using quoted prices in active markets, and are reported within Level 1.

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 using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV.  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 funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.
 
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, 2016 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, 2016
Assets
 

 
 

 
 

 
 

 
 
 
 

Coal reclamation trust - cash equivalents (b)
$
14,521

 
$
—

 
$
—

 
$
—

 
 
 
$
14,521

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
43,722

 
11,076

 
(35,103
)
 
(c)
 
19,695

Nuclear decommissioning trust:
 

 
 

 
 

 
 
 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
353,261

 
(d)
 
353,261

Fixed income securities:
 

 
 

 
 

 
 
 
 
 
 

     Cash and cash equivalent funds
—

 
—

 
—

 
795

 
(e)
 
795

U.S. Treasury
95,441

 
—

 
—

 
—

 
 
 
95,441

Corporate debt
—

 
111,623

 
—

 
—

 
 
 
111,623

Mortgage-backed securities
—

 
115,337

 
—

 
—

 
 
 
115,337

Municipal bonds
—

 
80,997

 
—

 
—

 
 
 
80,997

Other
—

 
22,132

 
—

 
—

 
 
 
22,132

Subtotal nuclear decommissioning trust
95,441

 
330,089

 
—

 
354,056

 

 
779,586

Total
$
109,962

 
$
373,811

 
$
11,076

 
$
318,953

 

 
$
813,802

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(45,641
)
 
$
(58,482
)
 
$
31,049

 
(c)
 
$
(73,074
)

(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets.
(c)
Represents counterparty netting, margin and collateral.  See Note 16.
(d)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(e)
Represents nuclear decommissioning trust net pending securities sales and purchases.

 
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

 
(c)
 
314,957

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
12,260

 
—

 
—

 
(335
)
 
(d)
 
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

 
291,069

 
—

 
314,622

 

 
735,196

Total
$
129,505

 
$
314,061

 
$
30,364

 
$
289,277

 

 
$
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)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(d)
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 remaining option contract expired on October 1, 2016. The significant unobservable inputs at December 31, 2015 for these instruments include electricity 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, 2016 and December 31, 2015:
 
 
December 31, 2016
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
10,648

 
$
32,042

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$16.43 - $41.07
 
$
29.86

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
428

 
26,440

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.32 - $3.60
 
$
2.81

Total
$
11,076

 
$
58,482

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.

 
 
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.
 
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, 2016 and 2015 (dollars in thousands):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2016
 
2015
Net derivative balance at beginning of period
 
$
(32,979
)
 
$
(41,386
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 
—

 
—

Included in OCI
 
88

 
(452
)
Deferred as a regulatory asset or liability
 
(37,543
)
 
(4,009
)
Settlements
 
15,146

 
14,809

Transfers into Level 3 from Level 2
 
1,900

 
(6,256
)
Transfers from Level 3 into Level 2
 
5,982

 
4,315

Net derivative balance at end of period
 
$
(47,406
)
 
$
(32,979
)
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, 2016, 2015 and 2014 (in thousands, except per share amounts):
 
2016
 
2015
 
2014
Net income attributable to common shareholders
$
442,034

 
$
437,257

 
$
397,595

Weighted average common shares outstanding — basic
111,409

 
111,026

 
110,626

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
637

 
526

 
552

Weighted average common shares outstanding — diluted
112,046

 
111,552

 
111,178

Earnings per weighted-average common share outstanding
 
 
 
 
 
Net income attributable to common shareholders - basic
$
3.97

 
$
3.94

 
$
3.59

Net Income attributable to common shareholders - diluted
$
3.95

 
$
3.92

 
$
3.58

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, 2016, 2.5 million common shares were available for issuance under the 2012 Plan. During 2016, 2015, and 2014, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. 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
 
During the fourth quarter of 2016, we adopted new stock-based compensation accounting guidance prescribed by ASU 2016-09, see Note 2. Prior to the adoption of this guidance we had certain awards that were accounted for as liability awards due to the ability of the employee to withhold taxes beyond the minimum statutory tax withholding rate. Under the new standard, the tax withholding terms of our awards no longer trigger liability treatment. Accordingly, effective, January 1, 2016 certain awards that were previously classified as liability awards are now accounted for as equity awards. The impacts of this accounting change relating to prior years have been applied using a modified retrospective approach, resulting in a $6 million cumulative-effect adjustment, net of income tax expense of $3 million, to increase Retained Earnings as of January 1, 2016. The impacts of this accounting change relating to the current year, resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. Due to this transition approach, the following discussion reflects this change in the 2016 expense and activity; however, expense and activities relating to 2015 and 2014 reflect the historical treatment. The new standard also requires excess income tax benefits and deficiencies arising from stock based compensation to now be recognized in the period incurred, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. These other provisions of the standard did not have a material impact on our consolidated financial statements.

Compensation cost included in net income for stock-based compensation plans was $19 million in 2016, $19 million in 2015, and $33 million in 2014.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $10 million in 2016, $7 million in 2015, and $13 million in 2014.

As of December 31, 2016, there were approximately $13 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years. 
    
The total fair value of shares vested was $22 million in 2016, $21 million in 2015 and $22 million in 2014.
 
The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2016, 2015 and 2014.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Units granted
141,811

 
152,651

 
179,291

 
166,666

 
151,430

 
166,244

Weighted-average grant date fair value
$
67.34

 
$
64.12

 
$
54.89

 
$
66.60

 
$
64.97

 
$
54.86

(a)
Units granted includes awards that will be cash settled of 43,952 in 2016, 45,104 in 2015, and 49,018 in 2014.
(b)
Reflects the target payout level.
 
The following table is a summary of the status of non-vested awards as of December 31, 2016 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, 2016
428,287

 
$
56.69

 
305,832

 
$
58.86

Granted
141,811

 
67.34

 
166,666

 
66.60

Change in performance factor
—

 
—

 
15,573

 
54.09

Vested
(230,881
)
 
55.07

 
(171,303
)
 
54.09

Forfeited (c)
(3,958
)
 
62.86

 
(4,044
)
 
62.34

Nonvested at December 31, 2016
335,259

(a)
62.04

 
312,724

 
65.32

Vested Awards Outstanding at December 31, 2016
174,201

 


 
171,303

 



 
(a)
Includes 112,554 of awards that will be cash settled.
(b)
The nonvested performance shares are reflected at target payout level.  The performance metric component 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.
(c)
We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $3 million, $10 million and $9 million in 2016, 2015 and 2014, respectively. This includes cash used to settle restricted stock units of $3 million for each of the years 2016, 2015 and 2014. Restricted stock units that are cash settled are classified as liability awards. Share-based liabilities paid relating to performance shares were $16 million in 2015 and $12 million in 2014. In 2016, performance shares were classified as equity awards.
 
Restricted Stock Units, Stock Grants, and Stock Units
 
Restricted stock units are 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 dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.
 
In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West.  This award vested on December 31, 2016, because he remained employed with the Company through that date.  The Board can increase the number of awards that vest, up to an additional 33,745 restricted stock units, payable in stock, if certain performance requirements are met.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash 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. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company's closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.
 
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.  Each stock unit is convertible to one share of 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 are granted to officers and key employees.  The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based upon six non-financial separate performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West's total shareholder return (TSR) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). 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 equity awards, with compensation cost based on the fair value of the award on grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.
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.
  
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, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
Commodity
 
Quantity
Power
 
1,314

 
GWh
Gas
 
194

 
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, 2016, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2016
 
2015
 
2014
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
47

 
$
(615
)
 
$
(372
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(3,926
)
 
(5,988
)
 
(21,415
)

(a)
During the years ended December 31, 2016, 2015, and 2014, 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 $3 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, 2016, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2016
 
2015
 
2014
Net Gain Recognized in Income
 
Operating revenues
 
$
771

 
$
574

 
$
324

Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
25,711

 
(108,973
)
 
(66,367
)
Total
 
 
 
$
26,482

 
$
(108,399
)
 
$
(66,043
)

(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, 2016 and December 31, 2015, include gross liabilities of $2 million and $3 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, 2016 and 2015.  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, 2016:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$
—

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
1

 
—

 
1

Total assets
 
54,798

 
(35,103
)
 
19,695

 
—

 
19,695

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(50,182
)
 
28,400

 
(21,782
)
 
(4,054
)
 
(25,836
)
Deferred credits and other
 
(53,941
)
 
6,703

 
(47,238
)
 
—

 
(47,238
)
Total liabilities
 
(104,123
)
 
35,103

 
(69,020
)
 
(4,054
)
 
(73,074
)
Total
 
$
(49,325
)
 
$
—

 
$
(49,325
)
 
$
(4,054
)
 
$
(53,379
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(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 $4,054.
 
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. 

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2016, we have no counterparties with positive exposures of greater than 10% of risk management assets. 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, 2016 (dollars in thousands):
 
 
December 31, 2016
Aggregate fair value of derivative instruments in a net liability position
$
104,123

Cash collateral posted
—

Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)
23,914


(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 $144 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 2016, 2015 and 2014 (dollars in thousands):
 
 
2016
 
2015
 
2014
Other income:
 

 
 

 
 

Interest income
$
884

 
$
493

 
$
1,010

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

 
—

 
8,386

Miscellaneous
17

 
128

 
212

Total other income
$
901

 
$
621

 
$
9,608

Other expense:
 

 
 

 
 

Non-operating costs
$
(9,235
)
 
$
(11,292
)
 
$
(9,657
)
Investment losses — net
(1,747
)
 
(2,080
)
 
(9,426
)
Miscellaneous
(4,355
)
 
(4,451
)
 
(2,663
)
Total other expense
$
(15,337
)
 
$
(17,823
)
 
$
(21,746
)
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 2016, 2015 and 2014 (dollars in thousands):
 
 
2016
 
2015
 
2014
Other income:
 

 
 

 
 

Interest income
$
261

 
$
163

 
$
689

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

 
—

 
8,386

Gain on disposition of property
5,745

 
716

 
1,197

Miscellaneous
2,601

 
1,955

 
1,023

Total other income
$
8,607

 
$
2,834

 
$
11,295

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(11,034
)
 
$
(11,648
)
 
$
(10,397
)
Loss on disposition of property
(1,246
)
 
(2,219
)
 
(615
)
Miscellaneous
(5,234
)
 
(5,152
)
 
(2,391
)
Total other expense
$
(17,514
)
 
$
(19,019
)
 
$
(13,403
)

(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.  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 2017 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, 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 leases' terms 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. Predominantly due to the lease terms, 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 expense, resulting in an increase in net income for 2016, 2015 and 2014 of $19 million, $19 million and $26 million, respectively, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders is not impacted by the consolidation.
    
Our Consolidated Balance Sheets at December 31, 2016 and December 31, 2015 include the following amounts relating to the VIEs (dollars in thousands):
 
 
December 31, 2016
 
December 31, 2015
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation
$
113,515

 
$
117,385

Equity-Noncontrolling interests
132,290

 
135,540


 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur.  Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants 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 periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 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, 2016 and December 31, 2015 (dollars in thousands):
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2016
 

 
 

 
 

Equity securities
$
353,261

 
$
188,091

 
$
—

Fixed income securities
425,530

 
9,820

 
(4,962
)
Net receivables (a)
795

 
—

 
—

Total
$
779,586

 
$
197,911

 
$
(4,962
)
 
 
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
)

(a)
Net receivables/(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,
 
2016
 
2015
 
2014
Realized gains
$
11,213

 
$
5,189

 
$
4,725

Realized losses
(10,106
)
 
(6,225
)
 
(4,525
)
Proceeds from the sale of securities (a)
633,410

 
478,813

 
356,195


(a)
Proceeds are reinvested in the trust.
 
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2016 is as follows (dollars in thousands):
 
 
Fair Value
Less than one year
$
13,063

1 year – 5 years
119,292

5 years – 10 years
105,612

Greater than 10 years
187,563

Total
$
425,530

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, 2016 and 2015 (dollars in thousands): 
 
Year Ended December 31,
 
2016
 
2015
Balance at beginning of period
$
(44,748
)
 
$
(68,141
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(538
)
 
(957
)
Amounts reclassified from accumulated other comprehensive loss (a)
2,941

 
4,187

Net current period OCI (loss)
2,403

 
3,230

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
(4,509
)
 
16,980

Amounts reclassified from accumulated other comprehensive loss (b)
3,032

 
3,183

Net current period OCI (loss)
(1,477
)
 
20,163

Balance at end of period
$
(43,822
)
 
$
(44,748
)

(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, 2016 and 2015 (dollars in thousands): 
 
Year Ended December 31,
 
2016
 
2015
Balance at beginning of period
$
(27,097
)
 
$
(48,333
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(538
)
 
(957
)
Amounts reclassified from accumulated other comprehensive loss (a)
2,941

 
4,187

Net current period OCI (loss)
2,403

 
3,230

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
(3,821
)
 
14,726

Amounts reclassified from accumulated other comprehensive loss (b)
3,092

 
3,280

Net current period OCI (loss)
(729
)
 
18,006

Balance at end of period
$
(25,423
)
 
$
(27,097
)

(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,
 
2016
 
2015
 
2014
Operating revenues
$
370

 
$
550

 
$
642

Operating expenses
26,424

 
12,733

 
23,507

Operating loss
(26,054
)
 
(12,183
)
 
(22,865
)
Other
 

 
 

 
 

Equity in earnings of subsidiaries
462,027

 
446,508

 
411,528

Other expense
(1,771
)
 
(3,302
)
 
(3,276
)
Total
460,256

 
443,206

 
408,252

Interest expense
3,151

 
2,672

 
3,663

Income before income taxes
431,051

 
428,351

 
381,724

Income tax benefit
(10,983
)
 
(8,906
)
 
(15,871
)
Net income attributable to common shareholders
442,034

 
437,257

 
397,595

Other comprehensive income — attributable to common shareholders
926

 
23,393

 
9,912

Total comprehensive income — attributable to common shareholders
$
442,960

 
$
460,650

 
$
407,507


 
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,
 
2016
 
2015
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
41

 
$
17,432

Accounts receivable
81,751

 
93,093

Income tax receivable
—

 
14,895

Other current assets
340

 
197

Total current assets
82,132

 
125,617

Investments and other assets
 

 
 

Investments in subsidiaries
5,084,035

 
4,815,236

Deferred income taxes
53,805

 
41,065

Other assets
38,500

 
43,422

Total investments and other assets
5,176,340

 
4,899,723

Total Assets
$
5,258,472

 
$
5,025,340

LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
$
5,421

 
$
5,901

Accrued taxes
12,050

 
6,904

Common dividends payable
72,926

 
69,363

Short-term borrowings
41,700

 
—

Current maturities of long-term debt
125,000

 
—

Other current liabilities
31,182

 
33,120

Total current liabilities
288,279

 
115,288

 
 
 
 
Long-term debt less current maturities
—

 
125,000

 
 
 
 
Pension liabilities
21,057

 
21,933

Other
13,224

 
43,662

Total deferred credits and other
34,281

 
65,595

Common stock equity
 
 
 
Common stock
2,591,897

 
2,535,862

Accumulated other comprehensive loss
(43,822
)
 
(44,748
)
Retained earnings
2,255,547

 
2,092,803

Total Pinnacle West Shareholders’ equity
4,803,622

 
4,583,917

Noncontrolling interests
132,290

 
135,540

Total Equity
4,935,912

 
4,719,457

Total Liabilities and Equity
$
5,258,472

 
$
5,025,340


 
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,
 
2016
 
2015
 
2014
Cash flows from operating activities
 

 
 

 
 

Net income
$
442,034

 
$
437,257

 
$
397,595

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

Equity in earnings of subsidiaries — net
(462,027
)
 
(446,508
)
 
(411,528
)
Depreciation and amortization
85

 
92

 
94

Deferred income taxes
(12,402
)
 
12,967

 
4,406

Accounts receivable
15,823

 
11,336

 
(22,945
)
Accounts payable
10,402

 
637

 
2,017

Accrued taxes and income tax receivables — net
20,041

 
(12,882
)
 
(1,795
)
Dividends received from subsidiaries
239,300

 
266,900

 
253,600

Other
5,514

 
(6,995
)
 
18,432

Net cash flow provided by operating activities
258,770

 
262,804

 
239,876

Cash flows from investing activities
 

 
 

 
 

Construction work in progress
(18,457
)
 
(3,462
)
 
—

Investments in subsidiaries
(19,242
)
 
(3,491
)
 
(10,236
)
Repayments of loans from subsidiaries
1,026

 
157

 
322

Advances of loans to subsidiaries
(2,092
)
 
(1,010
)
 
(1,450
)
Net cash flow used for investing activities
(38,765
)
 
(7,806
)
 
(11,364
)
Cash flows from financing activities
 

 
 

 
 

Issuance of long-term debt
—

 
—

 
125,000

Short-term debt borrowings under revolving credit facility
40,000

 
—

 
—

Commercial Paper - net
1,700

 
—

 
—

Dividends paid on common stock
(274,229
)
 
(260,027
)
 
(246,671
)
Repayment of long-term debt
—

 
—

 
(125,000
)
Common stock equity issuance - net of purchases
(4,867
)
 
19,373

 
15,288

Other
—

 
—

 
161

Net cash flow used for financing activities
(237,396
)
 
(240,654
)
 
(231,222
)
Net increase (decrease) in cash and cash equivalents
(17,391
)
 
14,344

 
(2,710
)
Cash and cash equivalents at beginning of year
17,432

 
3,088

 
5,798

Cash and cash equivalents at end of year
$
41

 
$
17,432

 
$
3,088


     See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of the Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.
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:
 
 

 
 

 
 

 
 

 
 

2016
 
$
3,125

 
$
4,025

 
$
—

 
$
4,113

 
$
3,037

2015
 
3,094

 
4,073

 
—

 
4,042

 
3,125

2014
 
3,203

 
3,942

 
—

 
4,051

 
3,094

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:
 
 

 
 

 
 

 
 

 
 

2016
 
$
3,125

 
$
4,025

 
$
—

 
$
4,113

 
$
3,037

2015
 
3,094

 
4,073

 
—

 
4,042

 
3,125

2014
 
3,203

 
3,942

 
—

 
4,051

 
3,094

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, BCE and 4CA. 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. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. 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.

Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on net cash flows provided by operating activities. The following tables show the impacts of the reclassifications of the prior years (previously reported) amounts (dollars in thousands):

Statement of Cash Flows for the
Year Ended December 31, 2015
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current
year presentation
Cash Flows from Operating Activities
 

 
 

 
 

Stock compensation
$
—

 
$
18,756

 
$
18,756

Change in other long term liabilities
(81,959
)
 
(18,756
)
 
(100,715
)

Statement of Cash Flows for the
Year Ended December 31, 2014
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current
year presentation
Cash Flows from Operating Activities
 

 
 

 
 

Stock compensation
$
—

 
$
33,059

 
$
33,059

Change in other long-term liabilities
(80,993
)
 
(33,059
)
 
(114,052
)


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 7.17% for 2016, 8.02% for 2015, and 8.47% for 2014.  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
 
ASU 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting

In March 2016, new stock compensation accounting guidance was issued intended to simplify the accounting for employee share-based payments. The new guidance impacts several aspects of the accounting for share-based payments including: modifies the tax withholding threshold that triggers liability classification of an award, requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, simplifies the accounting for forfeitures, and clarifies certain cash flow presentation matters. Certain aspects of the standard must be adopted using a prospective approach and other aspects must be adopted using a modified retrospective approach.

During the fourth quarter of 2016, we elected to early adopt this standard, and accordingly have applied the guidance effective as of January 1, 2016. Prior to adoption of the new standard, our stock compensation awards were generally classified as liability awards and accounted for at fair value until settled because employees could withhold at more than the minimum statutory tax withholding rate. In accordance with the new guidance, certain of these stock compensation awards are now classified as equity awards and accounted for at grant date fair value. As a result of adopting the new standard, Pinnacle West recorded a cumulative effect adjustment to retained earnings of $6 million. The other provisions of the standard did not have a material impact on our consolidated financial statements. See Note 15 for additional details of the adoption impacts.

ASU 2015-07, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)

In May 2015, new accounting guidance was issued that removes the requirement to categorize certain investments valued using net asset value, as a practical expedient, within the fair value hierarchy. We retrospectively adopted this guidance during the first quarter of 2016. The adoption of this guidance modifies our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.  See Note 7 and Note 13.  

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard 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. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard 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 plan on adopting this standard on January 1, 2018, and are currently evaluating the transition method and the effect on our financial statements. As part of our evaluation we continue to actively monitor certain industry issues being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups may impact our application of the standard, specifically in regards to the treatment of contributions in aid of construction.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new 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 standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements.

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.


ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

                In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business.  The definition of a business  affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are evaluating the impacts of adopting this new standard, and the impacts it may have on our financial statements.  

Summary of Significant Accounting Policies (Tables)
Schedule of reclassifications of the prior year 
The following tables show the impacts of the reclassifications of the prior years (previously reported) amounts (dollars in thousands):

Statement of Cash Flows for the
Year Ended December 31, 2015
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current
year presentation
Cash Flows from Operating Activities
 

 
 

 
 

Stock compensation
$
—

 
$
18,756

 
$
18,756

Change in other long term liabilities
(81,959
)
 
(18,756
)
 
(100,715
)

Statement of Cash Flows for the
Year Ended December 31, 2014
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current
year presentation
Cash Flows from Operating Activities
 

 
 

 
 

Stock compensation
$
—

 
$
33,059

 
$
33,059

Change in other long-term liabilities
(80,993
)
 
(33,059
)
 
(114,052
)
Schedule of property, plant and equipment 
Pinnacle West’s property, plant and equipment included in the December 31, 2016 and 2015 consolidated balance sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2016
 
2015
Generation
$
7,874,898

 
$
7,336,902

Transmission
2,746,508

 
2,494,744

Distribution
5,738,801

 
5,543,561

General plant
981,681

 
847,025

Plant in service and held for future use
17,341,888

 
16,222,232

Accumulated depreciation and amortization
(5,970,100
)
 
(5,594,094
)
Net
11,371,788

 
10,628,138

Construction work in progress
1,019,947

 
816,307

Palo Verde sale leaseback, net of accumulated depreciation
113,515

 
117,385

Intangible assets, net of accumulated amortization
90,022

 
123,975

Nuclear fuel, net of accumulated amortization
119,004

 
123,139

Total property, plant and equipment
$
12,714,276

 
$
11,808,944

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,
 
2016
 
2015
 
2014
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
9,956

 
$
6,550

 
$
(102,154
)
Interest, net of amounts capitalized
184,462

 
170,209

 
177,074

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
114,855

 
$
83,798

 
$
44,712

Dividends declared but not paid
72,926

 
69,363

 
65,790


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 2016 and 2015 (dollars in thousands):
 
 
Year Ended December 31,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,926

Deferred fuel and purchased power costs - current period
60,303

 
(14,997
)
Amounts charged to customers
(38,150
)
 
(1,617
)
Ending balance
$
12,465

 
$
(9,688
)
Schedule of regulatory assets 
The detail of regulatory assets is as follows (dollars in thousands):
S
Amortization Through
 
December 31, 2016
 
December 31, 2015
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
711,059

 
$
—

 
$
619,223

Retired power plant costs
2033
 
9,913

 
117,591

 
9,913

 
127,518

Income taxes - AFUDC equity
2046
 
6,305

 
152,118

 
5,495

 
133,712

Deferred fuel and purchased power — mark-to-market (Note 16)
2020
 
—

 
42,963

 
71,852

 
69,697

Four Corners cost deferral
2024
 
6,689

 
56,894

 
6,689

 
63,582

Income taxes — investment tax credit basis adjustment
2046
 
2,120

 
54,356

 
1,766

 
48,462

Lost fixed cost recovery
2017
 
61,307

 
—

 
45,507

 
—

Palo Verde VIEs (Note 18)
2046
 
—

 
18,775

 
—

 
18,143

Deferred compensation
2036
 
—

 
35,595

 
—

 
34,751

Deferred property taxes
(d)
 
—

 
73,200

 
—

 
50,453

Loss on reacquired debt
2038
 
1,637

 
16,942

 
1,515

 
16,375

AG-1 deferral
2018
 
—

 
5,868

 
—

 
—

Demand side management (b)
2017
 
3,744

 
—

 
—

 
—

Tax expense of Medicare subsidy
2024
 
1,513

 
10,589

 
1,520

 
12,163

Transmission vegetation management
2016
 
—

 
—

 
4,543

 
—

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,708

 
332

 
11,040

Deferred fuel and purchased power (b) (c)
2017
 
12,465

 
—

 
—

 
—

Coal reclamation
2026
 
418

 
5,182

 
418

 
6,085

Other
Various
 
432

 
1,588

 
5

 
2,942

Total regulatory assets (e)
 
 
$
106,875

 
$
1,313,428

 
$
149,555

 
$
1,214,146


(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, 2016
 
December 31, 2015
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
279,976

 
$
—

 
$
277,554

Removal costs
(a)
 
29,899

 
223,145

 
39,746

 
240,367

Other postretirement benefits
(d)
 
32,662

 
123,913

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2046
 
4,368

 
108,827

 
3,604

 
97,175

Income taxes - change in rates
2045
 
1,771

 
70,898

 
1,113

 
72,454

Spent nuclear fuel
2047
 
—

 
71,726

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
26,809

 
—

 
43,773

 
4,365

Demand side management (b)
2019
 
—

 
20,472

 
6,079

 
19,115

Sundance maintenance
2030
 
—

 
15,287

 
—

 
13,678

Deferred fuel and purchased power (b) (c)
2016
 
—

 
—

 
9,688

 
—

Deferred gains on utility property
2018
 
2,063

 
8,895

 
2,062

 
6,001

Four Corners coal reclamation
2031
 
—

 
18,248

 
—

 
8,920

Other
Various
 
2,327

 
7,529

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
99,899

 
$
948,916

 
$
145,766

 
$
994,152


(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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Total unrecognized tax benefits, January 1
$
34,447

 
$
44,775

 
$
41,997

 
$
34,447

 
$
44,775

 
$
41,997

Additions for tax positions of the current year
2,695

 
2,175

 
4,309

 
2,695

 
2,175

 
4,309

Additions for tax positions of prior years
886

 
—

 
751

 
886

 
—

 
751

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(1,953
)
 
(10,244
)
 
(2,282
)
 
(1,953
)
 
(10,244
)
 
(2,282
)
Settlements with taxing authorities
—

 
—

 
—

 
—

 
—

 
—

Lapses of applicable statute of limitations
—

 
(2,259
)
 
—

 
—

 
(2,259
)
 
—

Total unrecognized tax benefits, December 31
$
36,075

 
$
34,447

 
$
44,775

 
$
36,075

 
$
34,447

 
$
44,775

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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Tax positions, that if recognized, would decrease our effective tax rate
$
11,313

 
$
9,523

 
$
11,207

 
$
11,313

 
$
9,523

 
$
11,207

The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 
 
Pinnacle West Consolidated
 
APS Consolidated
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Unrecognized tax benefit interest expense/(benefit) recognized
$
529

 
$
(161
)
 
$
752

 
$
529

 
$
(161
)
 
$
752


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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Unrecognized tax benefit interest accrued
$
1,333

 
$
804

 
$
965

 
$
1,333

 
$
804

 
$
965

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,
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Current:
 

 
 

 
 

 
 
 
 
 
 
Federal
$
8,630

 
$
(12,335
)
 
$
25,054

 
$
711

 
$
6,485

 
$
40,115

State
1,259

 
4,763

 
10,382

 
4,276

 
7,813

 
15,598

Total current
9,889

 
(7,572
)
 
35,436

 
4,987

 
14,298

 
55,713

Deferred:
 

 
 

 
 

 
 

 
 

 
 

Federal
201,743

 
221,505

 
167,365

 
215,178

 
208,326

 
165,027

State
24,779

 
23,787

 
17,904

 
25,677

 
23,217

 
16,620

Total deferred
226,522

 
245,292

 
185,269

 
240,855

 
231,543

 
181,647

Income tax expense
$
236,411

 
$
237,720

 
$
220,705

 
$
245,842

 
$
245,841

 
$
237,360

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,
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Federal income tax expense at 35% statutory rate
$
244,278

 
$
242,869

 
$
225,540

 
$
254,617

 
$
250,267

 
$
239,638

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

 
 

 
 

 
 

State income tax net of federal income tax benefit
16,311

 
18,265

 
18,149

 
18,750

 
20,433

 
21,148

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

 
(2,169
)
 
—

 
—

 
(1,892
)
 
—

Medicare Subsidy Part-D
844

 
837

 
830

 
844

 
837

 
830

Allowance for equity funds used during construction (see Note 1)
(11,724
)
 
(9,711
)
 
(8,523
)
 
(11,724
)
 
(9,711
)
 
(8,523
)
Palo Verde VIE noncontrolling interest (see Note 18)
(6,823
)
 
(6,626
)
 
(9,135
)
 
(6,823
)
 
(6,626
)
 
(9,135
)
Investment tax credit amortization
(5,887
)
 
(5,527
)
 
(4,928
)
 
(5,887
)
 
(5,527
)
 
(4,928
)
Other
(588
)
 
(218
)
 
(1,228
)
 
(3,935
)
 
(1,940
)
 
(1,670
)
Income tax expense
$
236,411

 
$
237,720

 
$
220,705

 
$
245,842

 
$
245,841

 
$
237,360

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,
 
2016
 
2015
 
2016
 
2015
DEFERRED TAX ASSETS
 

 
 

 
 
 
 
Risk management activities
$
26,614

 
$
70,498

 
$
26,614

 
$
70,498

Regulatory liabilities:
 

 
 

 
 

 
 
Asset retirement obligation and removal costs
200,140

 
216,765

 
200,140

 
216,765

Unamortized investment tax credits
113,195

 
100,779

 
113,195

 
100,779

Other postretirement benefits
60,375

 
83,034

 
60,375

 
83,034

Other
63,311

 
60,707

 
63,311

 
60,707

Pension liabilities
204,436

 
191,028

 
194,981

 
181,787

Renewable energy incentives
56,379

 
60,956

 
56,379

 
60,956

Credit and loss carryforwards
75,944

 
59,557

 
1,645

 
—

Other
158,421

 
149,033

 
187,453

 
176,016

Total deferred tax assets
958,815

 
992,357

 
904,093

 
950,542

DEFERRED TAX LIABILITIES
 

 
 

 
 

 
 
Plant-related
(3,297,989
)
 
(3,116,752
)
 
(3,297,989
)
 
(3,116,752
)
Risk management activities
(7,594
)
 
(10,626
)
 
(7,594
)
 
(10,626
)
Other postretirement assets
(63,477
)
 
(71,737
)
 
(62,819
)
 
(70,986
)
Regulatory assets:
 

 
 

 
 
 
 

Allowance for equity funds used during construction
(61,088
)
 
(54,110
)
 
(61,088
)
 
(54,110
)
Deferred fuel and purchased power — mark-to-market
(21,396
)
 
(55,020
)
 
(21,396
)
 
(55,020
)
Pension benefits
(274,184
)
 
(240,692
)
 
(274,184
)
 
(240,692
)
Retired power plant costs (see Note 3)
(49,166
)
 
(53,420
)
 
(49,166
)
 
(53,420
)
Other
(123,987
)
 
(108,441
)
 
(123,987
)
 
(108,441
)
Other
(5,166
)
 
(4,984
)
 
(5,165
)
 
(4,984
)
Total deferred tax liabilities
(3,904,047
)
 
(3,715,782
)
 
(3,903,388
)
 
(3,715,031
)
Deferred income taxes — net
$
(2,945,232
)
 
$
(2,723,425
)
 
$
(2,999,295
)
 
$
(2,764,489
)
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, 2016 and 2015 (dollars in thousands):
 
 
December 31, 2016
 
December 31, 2015
 
Pinnacle West
APS
Total
 
Pinnacle West
APS
Total
Commitments under Credit Facilities
$
275,000

$
1,000,000

$
1,275,000

 
$
200,000

$
1,000,000

$
1,200,000

Outstanding Commercial Paper and Revolving Credit Facility Borrowings
(41,700
)
(135,500
)
(177,200
)
 
—

—

—

Amount of Credit Facilities Available
$
233,300

$
864,500

$
1,097,800

 
$
200,000

$
1,000,000

$
1,200,000

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

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, 2016 and 2015 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2016
 
2015
APS
 
 
 
 
 

 
 

Pollution control bonds:
 
 
 
 
 

 
 

Variable
2029
 
(b)
 
$
35,975

 
$
92,405

Fixed
2024-2029
 
1.75%-4.70%
 
147,150

 
211,150

Total pollution control bonds
 
 
 
 
183,125

 
303,555

Senior unsecured notes
2019-2046
 
2.20%-8.75%
 
3,725,000

 
3,375,000

Term loans
2018-2019
 
(c)
 
150,000

 
50,000

Unamortized discount
 
 
 
 
(11,816
)
 
(10,374
)
Unamortized premium
 
 
 
 
4,506

 
4,686

Unamortized debt issuance cost
 
 
 
 
(29,030
)
 
(27,896
)
Total APS long-term debt
 
 
 
 
4,021,785

 
3,694,971

Less current maturities

 
 
 
—

 
357,580

Total APS long-term debt less current maturities
 
 
 
 
4,021,785

 
3,337,391

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(d)
 
125,000

 
125,000

Less current maturities
 
 
 
 
125,000

 
—

Total PNW long-term debt less current maturities
 
 
 
 
—

 
125,000

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
4,021,785

 
$
3,462,391


(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 0.81% at December 31, 2016 and 0.01%-0.24% at December 31, 2015.
(c)
The weighted-average interest rate was 1.427% at December 31, 2016, and 1.024% at December 31, 2015.
(d)                                 The interest rate was 1.520% at December 31, 2016 and 1.174% at December 31, 2015.


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
2017
 
$
125,000

 
$
—

2018
 
82,000

 
82,000

2019
 
600,000

 
600,000

2020
 
250,000

 
250,000

2021
 
—

 
—

Thereafter
 
3,126,125

 
3,126,125

Total
 
$
4,183,125

 
$
4,058,125

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, 2016
 
As of
December 31, 2015
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,021,785

 
4,300,789

 
3,694,971

 
3,981,367

Total
$
4,146,785

 
$
4,425,789

 
$
3,819,971

 
$
4,106,367

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
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Service cost-benefits earned during the period
$
53,792

 
$
59,627

 
$
53,080

 
$
14,993

 
$
16,827

 
$
18,139

Interest cost on benefit obligation
131,647

 
123,983

 
129,194

 
29,721

 
28,102

 
41,243

Expected return on plan assets
(173,906
)
 
(179,231
)
 
(158,998
)
 
(36,495
)
 
(36,855
)
 
(46,400
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
527

 
594

 
869

 
(37,883
)
 
(37,968
)
 
(9,626
)
Net actuarial loss
40,717

 
31,056

 
10,963

 
4,589

 
4,881

 
1,175

Net periodic benefit cost
$
52,777

 
$
36,029

 
$
35,108

 
$
(25,075
)
 
$
(25,013
)
 
$
4,531

Portion of cost charged to expense
$
26,172

 
$
20,036

 
$
21,985

 
$
(12,435
)
 
$
(10,391
)
 
$
6,000

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 2016 and 2015 (dollars in thousands):
 
Pension
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
3,033,803

 
$
3,078,648

 
$
647,020

 
$
682,335

Service cost
53,792

 
59,627

 
14,993

 
16,827

Interest cost
131,647

 
123,983

 
29,721

 
28,102

Benefit payments
(142,247
)
 
(137,115
)
 
(26,231
)
 
(24,988
)
Actuarial (gain) loss
127,467

 
(91,340
)
 
50,942

 
(55,256
)
Benefit obligation at December 31
3,204,462

 
3,033,803

 
716,445

 
647,020

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,542,774

 
2,615,404

 
833,017

 
834,625

Actual return on plan assets
166,408

 
(44,690
)
 
63,463

 
(2,399
)
Employer contributions
100,000

 
100,000

 
819

 
791

Benefit payments
(133,825
)
 
(127,940
)
 
(14,648
)
 
—

Fair value of plan assets at December 31
2,675,357

 
2,542,774

 
882,651

 
833,017

Funded Status at December 31
$
(529,105
)
 
$
(491,029
)
 
$
166,206

 
$
185,997

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, 2016 and 2015 (dollars in thousands):
 
2016
 
2015
Projected benefit obligation
$
3,204,462

 
$
3,033,803

Accumulated benefit obligation
3,049,406

 
2,873,467

Fair value of plan assets
2,675,357

 
2,542,774

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, 2016 and 2015 (dollars in thousands):
 
Pension
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
Noncurrent asset
$
—

 
$
—

 
$
166,206

 
$
185,997

Current liability
(19,795
)
 
(10,031
)
 
—

 
—

Noncurrent liability
(509,310
)
 
(480,998
)
 
—

 
—

Net amount recognized
$
(529,105
)
 
$
(491,029
)
 
$
166,206

 
$
185,997

Schedule of accumulated other comprehensive loss 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2016 and 2015 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
Net actuarial loss
$
773,750

 
$
679,501

 
$
146,509

 
$
127,124

Prior service cost (credit)
81

 
609

 
(303,417
)
 
(341,301
)
APS’s portion recorded as a regulatory (asset) liability
(711,059
)
 
(619,223
)
 
156,575

 
213,621

Income tax expense (benefit)
(24,202
)
 
(23,663
)
 
833

 
925

Accumulated other comprehensive loss
$
38,570

 
$
37,224

 
$
500

 
$
369

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 2017 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
46,971

 
$
5,181

Prior service cost (credit)
81

 
(37,842
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017
$
47,052

 
$
(32,661
)
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,
 
2016
 
2015
 
2016
 
2015
2014
 
 
 
 
 
 
 
 
 
January - September
October - December
 
Discount rate – pension
4.08
%
 
4.37
%
 
4.37
%
 
4.02
%
4.88
%
4.88
%
 
Discount rate – other benefits
4.17
%
 
4.52
%
 
4.52
%
 
4.14
%
5.10
%
4.41
%
 
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
%
6.90
%
 
Expected long-term return on plan assets - other benefits
N/A

 
N/A

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

 
0

4

0

 
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
$
8,430

 
$
(5,455
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
8,440

 
(6,527
)
Effect on the accumulated other postretirement benefit obligation
108,046

 
(86,651
)
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, 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)
 
Other (a)
 
Balance at December 31, 2015
Pension Plan:
 

 
 

 
 
 
 

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 (b)
—

 
113,008

 
—

 
113,008

Common stock equities (c)
247,701

 
—

 
—

 
247,701

Mutual funds - International equities
116,307

 
—

 
—

 
116,307

Common and collective trusts:
 
 
 
 
 
 
 
Equities
—

 
—

 
315,989

 
315,989

Real Estate
—

 
—

 
150,359

 
150,359

Partnerships
—

 
—

 
169,937

 
169,937

Short-term investments and other (d)
—

 
—

 
44,066

 
44,066

Total
$
640,679

 
$
1,221,744

 
$
680,351

 
$
2,542,774

Other Benefits:
 

 
 

 
 
 
 

Cash and cash equivalents
$
240

 
$
—

 
$
—

 
$
240

Fixed Income Securities:
 

 
 

 
 
 
 

Corporate
—

 
217,026

 
—

 
217,026

U.S. Treasury
131,435

 
—

 
—

 
131,435

Other (b)
—

 
31,106

 
—

 
31,106

Common stock equities (c)
265,583

 
—

 
—

 
265,583

Mutual funds - International equities
52,568

 
—

 
—

 
52,568

Common and collective trusts:
 
 
 
 
 
 
 
Equities
—

 
—

 
110,055

 
110,055

Real Estate
—

 
—

 
13,512

 
13,512

Short-term investments and other (d)
—

 
—

 
11,492

 
11,492

Total
$
449,826

 
$
248,132

 
$
135,059

 
$
833,017


(a)
These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.
(b)
This category consists primarily of debt securities issued by municipalities.
(c)
This category primarily consists of US common stock equities.
(d)
This category includes plan receivables and payables.

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016, 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)
 
Other (a)
 
Balance at December 31, 2016
Pension Plan:
 

 
 

 
 
 
 

Cash and cash equivalents
$
13,995

 
$
—

 
$
—

 
$
13,995

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
1,210,453

 
—

 
1,210,453

U.S. Treasury
112,583

 
—

 
—

 
112,583

Other (b)
—

 
102,170

 
—

 
102,170

Common stock equities (c)
235,109

 
—

 
—

 
235,109

Mutual funds (d)
251,506

 
—

 
—

 
251,506

Common and collective trusts:
 
 
 
 
 
 
 
   Equities
—

 
—

 
266,840

 
266,840

   Real estate
—

 
—

 
161,449

 
161,449

Partnerships
—

 
—

 
208,915

 
208,915

Short-term investments and other (e)
—

 
—

 
112,337

 
112,337

Total
$
613,193

 
$
1,312,623

 
$
749,541

 
$
2,675,357

Other Benefits:
 

 
 

 
 
 
 

Cash and cash equivalents
$
304

 
$
—

 
$
—

 
$
304

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
268,193

 
—

 
268,193

U.S. Treasury
145,255

 
—

 
—

 
145,255

Other (b)
—

 
34,506

 
—

 
34,506

Common stock equities (c)
243,741

 
—

 
—

 
243,741

Mutual funds (d)
67,418

 
—

 
—

 
67,418

Common and collective trusts:
 

 
 

 
 
 
 

   Equities
—

 
—

 
95,814

 
95,814

   Real estate
—

 
—

 
14,509

 
14,509

Partnerships
—

 
—

 
3,060

 
3,060

Short-term investments and other (e)
—

 
—

 
9,851

 
9,851

Total
$
456,718

 
$
302,699

 
$
123,234

 
$
882,651


(a)
These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.
(b)
This category consists primarily of debt securities issued by municipalities.
(c)
This category primarily consists of US common stock equities.
(d)
These funds invest in US and international common stock equities.
(e)
This category includes plan receivables and payables.

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
2017
 
$
172,859

 
$
31,126

2018
 
173,232

 
33,795

2019
 
182,944

 
36,195

2020
 
191,037

 
37,998

2021
 
196,292

 
39,368

Years 2022-2026
 
1,049,149

 
201,944

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
2017
 
$
12,330

 
$
11,919

2018
 
10,987

 
10,690

2019
 
9,019

 
8,767

2020
 
7,688

 
7,439

2021
 
5,266

 
5,020

Thereafter
 
59,647

 
57,207

Total future lease commitments
 
$
104,937

 
$
101,042

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, 2016 (dollars in thousands):

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

 
 
 
 

 
 

 
 

 
Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,770,324

 
$
1,080,072

 
$
17,615

 
Palo Verde Unit 2 (a)
 
16.8
%
 

 
581,572

 
360,757

 
9,717

 
Palo Verde Common
 
28.0
%
 
(b)
 
672,799

 
242,649

 
62,479

 
Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
237,535

 
—

 
Four Corners Generating Station
 
63.0
%
 

 
934,837

 
578,924

 
248,072

 
Navajo Generating Station Units 1, 2 and 3
 
14.0
%
 

 
279,629

 
176,931

 
5,761

 
Cholla common facilities (c)
 
63.3
%
 
(b)
 
159,707

 
58,276

 
806

(d)
Transmission facilities:
 
 

 
 
 
 

 
 

 
 

 
ANPP 500kV System
 
33.6
%
 
 (b)
 
127,970

 
38,610

 
2,291

 
Navajo Southern System
 
22.5
%
 
(b)
 
62,135

 
20,491

 
334

 
Palo Verde — Yuma 500kV System
 
19.0
%
 
(b)
 
13,699

 
5,368

 
408

 
Four Corners Switchyards
 
51.3
%
 
 (b)
 
39,850

 
10,474

 
1,044

 
Phoenix — Mead System
 
17.1
%
 
(b)
 
39,330

 
13,725

 
85

 
Palo Verde — Rudd 500kV System
 
50.0
%
 
(b)
 
91,904

 
19,818

 
227

 
Morgan — Pinnacle Peak System
 
65.2
%
 
 (b)
 
140,374

 
13,557

 
—

 
Round Valley System
 
50.0
%
 
(b)
 
515

 
127

 
—

 
Palo Verde — Morgan System
 
85.8
%
 
(b)
 
125,908

 
1,326

 
28,949

 
Hassayampa — North Gila System
 
80.0
%
 
(b)
 
142,541

 
3,231

 
—

 
Cholla 500kV Switchyard
 
85.7
%
 
(b)
 
5,078

 
1,201

 
—

 
Saguaro 500kV Switchyard
 
75.0
%
 
(b)
 
20,456

 
12,426

 
2

 

(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.
(d)
Due to the closure of Cholla Unit 2 in 2015, all new Cholla common facilities construction is owned by APS at 50.5%
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,
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
Coal take-or-pay commitments (a)
$
195,428

 
$
189,588

 
$
193,818

 
$
198,160

 
$
202,619

 
$
2,068,355

 
(a)
Total take-or-pay commitments are approximately $3.0 billion.  The total net present value of these commitments is approximately $2.1 billion.
Summary of actual take-or-pay commitments 
 
 
Year Ended December 31,
 
2016
 
2015
 
2014
Total purchases
$
160,066

 
$
211,327

 
$
236,773

Asset Retirement Obligations (Tables)
Change in asset retirement obligations
The following table shows the change in our asset retirement obligations for 2016 and 2015 (dollars in thousands):

 
2016
 
2015
Asset retirement obligations at the beginning of year
$
443,576

 
$
390,750

Changes attributable to:
 

 
 

Accretion expense
26,656

 
25,163

Settlements
(15,732
)
 
(32,048
)
Estimated cash flow revisions
151,046

 
17,556

Newly incurred or acquired obligations
18,929

 
42,155

Asset retirement obligations at the end of year
$
624,475

 
$
443,576

Selected Quarterly Financial Data (Unaudited) (Tables)
Schedule of quarterly financial information 
Consolidated quarterly financial information for 2016 and 2015 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.

 
2016 Quarter Ended
 
2016
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
677,167

 
$
915,394

 
$
1,166,922

 
$
739,199

 
$
3,498,682

Operations and maintenance
243,195

 
242,279

 
217,568

 
208,277

 
911,319

Operating income
50,162

 
231,748

 
451,258

 
122,816

 
855,984

Income taxes
1,914

 
65,742

 
141,446

 
27,309

 
236,411

Net income
9,326

 
126,182

 
267,900

 
58,119

 
461,527

Net income attributable to common shareholders
4,453

 
121,308

 
263,027

 
53,246

 
442,034

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.04

 
$
1.09

 
$
2.36

 
$
0.48

 
$
3.97

Net income attributable to common shareholders — Diluted
0.04

 
1.08

 
2.35

 
0.47

 
3.95

 
 
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

Schedule of quarterly financial information 
APS's quarterly financial information for 2016 and 2015 is as follows (dollars in thousands):
 
 
2016 Quarter Ended,
 
2016
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
676,632

 
$
909,757

 
$
1,166,359

 
$
737,006

 
$
3,489,754

Operations and maintenance
238,711

 
233,712

 
209,366

 
197,319

 
879,108

Operating income
48,930

 
165,684

 
307,601

 
95,765

 
617,980

Net income attributable to common shareholder
7,253

 
127,188

 
269,220

 
58,480

 
462,141

 
 
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

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, 2016 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, 2016
Assets
 

 
 

 
 

 
 

 
 
 
 

Coal reclamation trust - cash equivalents (b)
$
14,521

 
$
—

 
$
—

 
$
—

 
 
 
$
14,521

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
43,722

 
11,076

 
(35,103
)
 
(c)
 
19,695

Nuclear decommissioning trust:
 

 
 

 
 

 
 
 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
353,261

 
(d)
 
353,261

Fixed income securities:
 

 
 

 
 

 
 
 
 
 
 

     Cash and cash equivalent funds
—

 
—

 
—

 
795

 
(e)
 
795

U.S. Treasury
95,441

 
—

 
—

 
—

 
 
 
95,441

Corporate debt
—

 
111,623

 
—

 
—

 
 
 
111,623

Mortgage-backed securities
—

 
115,337

 
—

 
—

 
 
 
115,337

Municipal bonds
—

 
80,997

 
—

 
—

 
 
 
80,997

Other
—

 
22,132

 
—

 
—

 
 
 
22,132

Subtotal nuclear decommissioning trust
95,441

 
330,089

 
—

 
354,056

 

 
779,586

Total
$
109,962

 
$
373,811

 
$
11,076

 
$
318,953

 

 
$
813,802

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(45,641
)
 
$
(58,482
)
 
$
31,049

 
(c)
 
$
(73,074
)

(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets.
(c)
Represents counterparty netting, margin and collateral.  See Note 16.
(d)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(e)
Represents nuclear decommissioning trust net pending securities sales and purchases.

 
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

 
(c)
 
314,957

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
12,260

 
—

 
—

 
(335
)
 
(d)
 
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

 
291,069

 
—

 
314,622

 

 
735,196

Total
$
129,505

 
$
314,061

 
$
30,364

 
$
289,277

 

 
$
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)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(d)
Represents nuclear decommissioning trust net pending securities sales and purchases.
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments 
s.
 
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2016 and December 31, 2015:
 
 
December 31, 2016
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
10,648

 
$
32,042

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$16.43 - $41.07
 
$
29.86

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
428

 
26,440

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.32 - $3.60
 
$
2.81

Total
$
11,076

 
$
58,482

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.

 
 
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 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, 2016 and 2015 (dollars in thousands):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2016
 
2015
Net derivative balance at beginning of period
 
$
(32,979
)
 
$
(41,386
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 
—

 
—

Included in OCI
 
88

 
(452
)
Deferred as a regulatory asset or liability
 
(37,543
)
 
(4,009
)
Settlements
 
15,146

 
14,809

Transfers into Level 3 from Level 2
 
1,900

 
(6,256
)
Transfers from Level 3 into Level 2
 
5,982

 
4,315

Net derivative balance at end of period
 
$
(47,406
)
 
$
(32,979
)
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, 2016, 2015 and 2014 (in thousands, except per share amounts):
 
2016
 
2015
 
2014
Net income attributable to common shareholders
$
442,034

 
$
437,257

 
$
397,595

Weighted average common shares outstanding — basic
111,409

 
111,026

 
110,626

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
637

 
526

 
552

Weighted average common shares outstanding — diluted
112,046

 
111,552

 
111,178

Earnings per weighted-average common share outstanding
 
 
 
 
 
Net income attributable to common shareholders - basic
$
3.97

 
$
3.94

 
$
3.59

Net Income attributable to common shareholders - diluted
$
3.95

 
$
3.92

 
$
3.58

Stock-Based Compensation (Tables)
Summary of Nonvested Restricted Stock, Stock Grants and Stock Units 
The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2016, 2015 and 2014.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Units granted
141,811

 
152,651

 
179,291

 
166,666

 
151,430

 
166,244

Weighted-average grant date fair value
$
67.34

 
$
64.12

 
$
54.89

 
$
66.60

 
$
64.97

 
$
54.86

(a)
Units granted includes awards that will be cash settled of 43,952 in 2016, 45,104 in 2015, and 49,018 in 2014.
(b)
Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2016 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, 2016
428,287

 
$
56.69

 
305,832

 
$
58.86

Granted
141,811

 
67.34

 
166,666

 
66.60

Change in performance factor
—

 
—

 
15,573

 
54.09

Vested
(230,881
)
 
55.07

 
(171,303
)
 
54.09

Forfeited (c)
(3,958
)
 
62.86

 
(4,044
)
 
62.34

Nonvested at December 31, 2016
335,259

(a)
62.04

 
312,724

 
65.32

Vested Awards Outstanding at December 31, 2016
174,201

 


 
171,303

 



 
(a)
Includes 112,554 of awards that will be cash settled.
(b)
The nonvested performance shares are reflected at target payout level.  The performance metric component 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.
(c)
We account for forfeitures as they occur.

Summary of Nonvested Performance Shares 
The following table is a summary of the status of non-vested awards as of December 31, 2016 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, 2016
428,287

 
$
56.69

 
305,832

 
$
58.86

Granted
141,811

 
67.34

 
166,666

 
66.60

Change in performance factor
—

 
—

 
15,573

 
54.09

Vested
(230,881
)
 
55.07

 
(171,303
)
 
54.09

Forfeited (c)
(3,958
)
 
62.86

 
(4,044
)
 
62.34

Nonvested at December 31, 2016
335,259

(a)
62.04

 
312,724

 
65.32

Vested Awards Outstanding at December 31, 2016
174,201

 


 
171,303

 



 
(a)
Includes 112,554 of awards that will be cash settled.
(b)
The nonvested performance shares are reflected at target payout level.  The performance metric component 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.
(c)
We account for forfeitures as they occur.

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2016, 2015 and 2014.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Units granted
141,811

 
152,651

 
179,291

 
166,666

 
151,430

 
166,244

Weighted-average grant date fair value
$
67.34

 
$
64.12

 
$
54.89

 
$
66.60

 
$
64.97

 
$
54.86

(a)
Units granted includes awards that will be cash settled of 43,952 in 2016, 45,104 in 2015, and 49,018 in 2014.
(b)
Reflects the target payout level.
Derivative Accounting (Tables)
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) 
As of December 31, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
Commodity
 
Quantity
Power
 
1,314

 
GWh
Gas
 
194

 
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, 2016, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2016
 
2015
 
2014
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
47

 
$
(615
)
 
$
(372
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(3,926
)
 
(5,988
)
 
(21,415
)

(a)
During the years ended December 31, 2016, 2015, and 2014, 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, 2016, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2016
 
2015
 
2014
Net Gain Recognized in Income
 
Operating revenues
 
$
771

 
$
574

 
$
324

Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
25,711

 
(108,973
)
 
(66,367
)
Total
 
 
 
$
26,482

 
$
(108,399
)
 
$
(66,043
)

(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, 2016 and 2015.  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, 2016:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$
—

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
1

 
—

 
1

Total assets
 
54,798

 
(35,103
)
 
19,695

 
—

 
19,695

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(50,182
)
 
28,400

 
(21,782
)
 
(4,054
)
 
(25,836
)
Deferred credits and other
 
(53,941
)
 
6,703

 
(47,238
)
 
—

 
(47,238
)
Total liabilities
 
(104,123
)
 
35,103

 
(69,020
)
 
(4,054
)
 
(73,074
)
Total
 
$
(49,325
)
 
$
—

 
$
(49,325
)
 
$
(4,054
)
 
$
(53,379
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(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 $4,054.
 
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.
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, 2016 and 2015.  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, 2016:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$
—

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
1

 
—

 
1

Total assets
 
54,798

 
(35,103
)
 
19,695

 
—

 
19,695

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(50,182
)
 
28,400

 
(21,782
)
 
(4,054
)
 
(25,836
)
Deferred credits and other
 
(53,941
)
 
6,703

 
(47,238
)
 
—

 
(47,238
)
Total liabilities
 
(104,123
)
 
35,103

 
(69,020
)
 
(4,054
)
 
(73,074
)
Total
 
$
(49,325
)
 
$
—

 
$
(49,325
)
 
$
(4,054
)
 
$
(53,379
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(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 $4,054.
 
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.
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, 2016 (dollars in thousands):
 
 
December 31, 2016
Aggregate fair value of derivative instruments in a net liability position
$
104,123

Cash collateral posted
—

Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)
23,914


(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 2016, 2015 and 2014 (dollars in thousands):
 
 
2016
 
2015
 
2014
Other income:
 

 
 

 
 

Interest income
$
884

 
$
493

 
$
1,010

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

 
—

 
8,386

Miscellaneous
17

 
128

 
212

Total other income
$
901

 
$
621

 
$
9,608

Other expense:
 

 
 

 
 

Non-operating costs
$
(9,235
)
 
$
(11,292
)
 
$
(9,657
)
Investment losses — net
(1,747
)
 
(2,080
)
 
(9,426
)
Miscellaneous
(4,355
)
 
(4,451
)
 
(2,663
)
Total other expense
$
(15,337
)
 
$
(17,823
)
 
$
(21,746
)
Detail of other income and other expense 
The following table provides detail of APS’s other income and other expense for 2016, 2015 and 2014 (dollars in thousands):
 
 
2016
 
2015
 
2014
Other income:
 

 
 

 
 

Interest income
$
261

 
$
163

 
$
689

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

 
—

 
8,386

Gain on disposition of property
5,745

 
716

 
1,197

Miscellaneous
2,601

 
1,955

 
1,023

Total other income
$
8,607

 
$
2,834

 
$
11,295

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(11,034
)
 
$
(11,648
)
 
$
(10,397
)
Loss on disposition of property
(1,246
)
 
(2,219
)
 
(615
)
Miscellaneous
(5,234
)
 
(5,152
)
 
(2,391
)
Total other expense
$
(17,514
)
 
$
(19,019
)
 
$
(13,403
)

(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, 2016 and December 31, 2015 include the following amounts relating to the VIEs (dollars in thousands):
 
 
December 31, 2016
 
December 31, 2015
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation
$
113,515

 
$
117,385

Equity-Noncontrolling interests
132,290

 
135,540

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, 2016 and December 31, 2015 (dollars in thousands):
 
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
December 31, 2016
 

 
 

 
 

Equity securities
$
353,261

 
$
188,091

 
$
—

Fixed income securities
425,530

 
9,820

 
(4,962
)
Net receivables (a)
795

 
—

 
—

Total
$
779,586

 
$
197,911

 
$
(4,962
)
 
 
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
)

(a)
Net receivables/(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,
 
2016
 
2015
 
2014
Realized gains
$
11,213

 
$
5,189

 
$
4,725

Realized losses
(10,106
)
 
(6,225
)
 
(4,525
)
Proceeds from the sale of securities (a)
633,410

 
478,813

 
356,195


(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, 2016 is as follows (dollars in thousands):
 
 
Fair Value
Less than one year
$
13,063

1 year – 5 years
119,292

5 years – 10 years
105,612

Greater than 10 years
187,563

Total
$
425,530

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, 2016 and 2015 (dollars in thousands): 
 
Year Ended December 31,
 
2016
 
2015
Balance at beginning of period
$
(44,748
)
 
$
(68,141
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(538
)
 
(957
)
Amounts reclassified from accumulated other comprehensive loss (a)
2,941

 
4,187

Net current period OCI (loss)
2,403

 
3,230

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
(4,509
)
 
16,980

Amounts reclassified from accumulated other comprehensive loss (b)
3,032

 
3,183

Net current period OCI (loss)
(1,477
)
 
20,163

Balance at end of period
$
(43,822
)
 
$
(44,748
)

(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, 2016 and 2015 (dollars in thousands): 
 
Year Ended December 31,
 
2016
 
2015
Balance at beginning of period
$
(27,097
)
 
$
(48,333
)
Derivative Instruments
 
 
 
OCI (loss) before reclassifications
(538
)
 
(957
)
Amounts reclassified from accumulated other comprehensive loss (a)
2,941

 
4,187

Net current period OCI (loss)
2,403

 
3,230

Pension and Other Postretirement Benefits
 
 
 
OCI (loss) before reclassifications
(3,821
)
 
14,726

Amounts reclassified from accumulated other comprehensive loss (b)
3,092

 
3,280

Net current period OCI (loss)
(729
)
 
18,006

Balance at end of period
$
(25,423
)
 
$
(27,097
)

(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, 2016
Dec. 31, 2015
Dec. 31, 2014
May 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Pinnacle West
Dec. 31, 2016
Minimum
Dec. 31, 2016
Maximum
Dec. 31, 2016
Maximum
Dec. 31, 2016
Fossil plant
Dec. 31, 2016
Nuclear plant
Dec. 31, 2016
Other generation
Dec. 31, 2016
Transmission
Dec. 31, 2016
Distribution
Dec. 31, 2016
General plant
Dec. 31, 2016
El Paso's Interest in Four Corners
4CA
Jul. 6, 2016
El Paso's Interest in Four Corners
4CA
Utility Plant and Depreciation [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership interest acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
7.00% 
Approximate remaining average useful lives of utility property
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average useful life
 
 
 
 
 
 
 
 
 
19 years 
27 years 
26 years 
39 years 
33 years 
7 years 
 
 
Cost of services, depreciation
$ 422 
$ 430 
$ 396 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation rates (as a percent)
2.66% 
2.74% 
2.77% 
 
 
 
0.30% 
 
14.12% 
 
 
 
 
 
 
 
 
Allowance for Funds Used During Construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Composite rate used to calculate AFUDC (as a percent)
7.17% 
8.02% 
8.47% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 
58 
53 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated amortization expense on existing intangible assets over the next five years
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
41 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
23 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
12 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2021
$ 1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Remaining amortization period for intangible assets
6 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership percentage for classification as cost method investments by El Dorado
 
 
 
 
 
 
 
20.00% 
 
 
 
 
 
 
 
 
 
Preferred Stock
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock, shares authorized (in shares)
 
 
 
 
15,535,000 
10,000,000 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock par or stated value per share 1 (in dollars per share)
 
 
 
 
$ 25 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock par or stated value per share 2 (in dollars per share)
 
 
 
 
$ 50 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock par or stated value per share 3 (in dollars per share)
 
 
 
 
$ 100 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of Significant Accounting Policies - Schedule of Reclassification of Prior Period Adjustments (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Stock compensation
$ 18,883 
$ 18,756 
$ 33,059 
Change in other long-term liabilities
(82,793)
(100,715)
(114,052)
As previously reported
 
 
 
Stock compensation
 
0 
0 
Change in other long-term liabilities
 
(81,959)
(80,993)
Reclassifications to conform to current year presentation
 
 
 
Stock compensation
 
18,756 
33,059 
Change in other long-term liabilities
 
$ (18,756)
$ (33,059)
Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Utility Plant and Depreciation [Line Items]
 
 
Net
$ 11,371,788 
$ 10,628,138 
Construction work in progress
1,019,947 
816,307 
Palo Verde sale leaseback, net of accumulated depreciation
113,515 
117,385 
Intangible assets, net of accumulated amortization
90,022 
123,975 
Nuclear fuel, net of accumulated amortization
119,004 
123,139 
Total property, plant and equipment
12,714,276 
11,808,944 
Electric Service
 
 
Utility Plant and Depreciation [Line Items]
 
 
Generation
7,874,898 
7,336,902 
Transmission
2,746,508 
2,494,744 
Distribution
5,738,801 
5,543,561 
General plant
981,681 
847,025 
Plant in service and held for future use
17,341,888 
16,222,232 
Accumulated depreciation and amortization
(5,970,100)
(5,594,094)
Net
11,371,788 
10,628,138 
Construction work in progress
1,019,947 
816,307 
Palo Verde sale leaseback, net of accumulated depreciation
113,515 
117,385 
Intangible assets, net of accumulated amortization
90,022 
123,975 
Nuclear fuel, net of accumulated amortization
119,004 
123,139 
Total property, plant and equipment
$ 12,714,276 
$ 11,808,944 
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Accounting Policies [Abstract]
 
 
 
Income tax (benefit), net of refunds
$ 9,956 
$ 6,550 
$ (102,154)
Interest, net of amounts capitalized
184,462 
170,209 
177,074 
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
 
 
 
Accrued capital expenditures
114,855 
83,798 
44,712 
Dividends declared but not paid
$ 72,926 
$ 69,363 
$ 65,790 
New Accounting Standards - Narrative (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
New Accounting Pronouncement, Early Adoption [Line Items]
 
Stock compensation cumulative effect adjustments
$ 45,855 
Retained Earnings
 
New Accounting Pronouncement, Early Adoption [Line Items]
 
Stock compensation cumulative effect adjustments
5,475 
Retained Earnings |
Accountings Standards Update 2016-09 |
New Accounting Pronouncement, Early Adoption, Effect
 
New Accounting Pronouncement, Early Adoption [Line Items]
 
Stock compensation cumulative effect adjustments
$ 6,000 
Regulatory Matters (Details) (APS, USD $)
0 Months Ended 2 Months Ended 1 Months Ended 0 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 0 Months Ended 1 Months Ended
Dec. 31, 2016
Lost Fixed Cost Recovery Mechanism
Jul. 12, 2016
ACC
2016 DSMAC
Apr. 1, 2016
ACC
2016 DSMAC
Jun. 1, 2015
ACC
2016 DSMAC
Jun. 1, 2016
ACC
2017 DSMAC
Dec. 5, 2016
ACC
Residential demand response, energy storage and load management program
Jul. 12, 2016
ACC
Electric Energy Efficiency Standard
Apr. 30, 2014
ACC
Electric Energy Efficiency Standard
workshop
Sep. 30, 2016
ACC
Modernization and Expansion of the Renewal Energy Standard
Dec. 20, 2016
ACC
Net Metering
Jun. 1, 2016
ACC
Retail Rate Case Filing with Arizona Corporation Commission
kWh
Jan. 1, 2016
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Dec. 31, 2015
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Jun. 1, 2016
FERC
Transmission rates, transmission cost adjustor and other transmission matters
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
Jan. 15, 2016
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Mar. 2, 2015
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Dec. 31, 2016
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Mar. 20, 2015
Cost Recovery Mechanisms
ACC
2015 DSMAC
project
Dec. 31, 2016
Cost Recovery Mechanisms
ACC
RES
Jul. 1, 2015
Cost Recovery Mechanisms
ACC
Arizona Renewable Energy Standard and Tariff 2016
Jul. 1, 2016
Cost Recovery Mechanisms
ACC
Arizona Renewable Energy Standard and Tariff 2017
Feb. 1, 2016
Cost Recovery Mechanisms
ACC
Power Supply Adjustor (PSA)
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
Jan. 27, 2017
Subsequent Event
ACC
2017 DSMAC
Feb. 1, 2017
Subsequent Event
ACC
Power Supply Adjustor (PSA)
Jan. 13, 2017
Subsequent Event
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Jan. 13, 2017
Subsequent Event
Cost Recovery Mechanisms
Lost Fixed Cost Recovery Mechanism
Jun. 1, 2016
Four Corners Power Plant
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Jun. 1, 2016
Ocotillo Plant
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Dec. 31, 2014
Alternative to AZ Sun Program, Phase 1
Arizona Renewable Energy Standard and Tariff 2014
MW
Dec. 31, 2014
Alternative to AZ Sun Program Phase 2
Arizona Renewable Energy Standard and Tariff 2014
penetration_feeder
storage_system
MW
Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net retail rate increase
 
 
 
 
 
 
 
 
 
 
$ 165,900,000 
 
 
 
 
$ 95,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjuster account balance transferred into base rates
 
 
 
 
 
 
 
 
 
 
 
 
267,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in average customer bill
 
 
 
 
 
 
 
 
 
 
5.74% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in average residential customer bill
 
 
 
 
 
 
 
 
 
 
7.96% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
original cost rate base
 
 
 
 
 
 
 
 
 
 
6,800,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Required return on incremental fair value rate base above original cost rate base
 
 
 
 
 
 
 
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Base rate for fuel and purchased power costs
 
 
 
 
 
 
 
 
 
 
0.029882 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decrease in base rate for fuel and purchased power costs
 
 
 
 
 
 
 
 
 
 
0.03207 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorization to defer for potential future recovery of construction costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
400,000,000 
500,000,000 
 
 
Plan option, non-partial requirements customers, maximum average monthly energy usage
 
 
 
 
 
 
 
 
 
 
600 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Case completion term
 
 
 
 
 
 
 
 
 
 
12 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Case completion extension term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
33 days 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8 
2 
Number of energy storage systems
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
Number of high solar penetration feeders
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
Amount of proposed budget
 
 
 
 
62,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
68,900,000 
 
148,000,000 
150,000,000 
 
 
 
66,600,000 
 
 
 
 
 
 
 
Proposed renewal energy standard, percent of retail sales
 
 
 
 
 
 
 
 
30.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current renewal energy standard, percent of retail sales
 
 
 
 
 
 
 
 
15.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter number of resource savings projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of approved budget
 
 
68,900,000 
68,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional approved budget
 
4,000,000 
 
 
 
4,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public utilities, cost effective energy efficiency programs, number of workshops
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public utilities, cost effective efficiency programs, number of days to convene a workshop
 
 
 
 
 
 
120 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum increase (decrease) in PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.004 
 
 
 
 
 
 
 
 
 
PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001678 
 
 
 
(0.001348)
 
 
 
 
 
 
Forward component of PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.001027)
 
 
 
 
 
 
Historical component of PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.000321)
 
 
 
 
 
 
Increase (decrease) in annual wholesale transmission rates
 
 
 
 
 
 
 
 
 
 
 
 
 
24,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
(17,600,000)
 
 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of adjustment representing prorated sales losses pending approval
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
63,700,000 
 
 
 
 
Increase in amount of adjustment representing prorated sales losses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
17,300,000 
 
 
 
 
Cost of service, resource comparison proxy method, maximum annual percentage decrease
 
 
 
 
 
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of service for interconnected DG system customers, grandfathered period
 
 
 
 
 
 
 
 
 
20 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matters, cost of service for new customers, guaranteed export price period
 
 
 
 
 
 
 
 
 
10 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reduced system benefits charge, amount
 
 
 
 
 
 
 
 
 
 
 
$ 14,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Matters Regulatory Matters - Retail Rate Case Filing (Details) (Retail Rate Case Filing with Arizona Corporation Commission, ACC, ARIZONA PUBLIC SERVICE COMPANY)
0 Months Ended
Jun. 1, 2016
Retail Rate Case Filing with Arizona Corporation Commission |
ACC |
ARIZONA PUBLIC SERVICE COMPANY
 
Proposed Capital Structure and Costs of Capital
 
Requested debt capital structure (as a percent)
44.20% 
Requested debt cost of capital (as a percent)
5.13% 
Requested equity capital structure (as a percent)
55.80% 
Requested equity cost of capital (as a percent)
10.50% 
Requested weighted-average cost of capital (as a percent)
8.13% 
Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
$ (60,303)
$ 14,997 
$ (26,927)
Deferred fuel and purchased power amortization
38,152 
1,617 
40,757 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
(60,303)
14,997 
(26,927)
Deferred fuel and purchased power amortization
38,152 
1,617 
40,757 
ACC |
ARIZONA PUBLIC SERVICE COMPANY |
Power Supply Adjustor (PSA) |
Cost Recovery Mechanisms
 
 
 
Change in regulatory asset
 
 
 
Beginning balance
(9,688)
6,926 
 
Deferred fuel and purchased power
60,303 
(14,997)
 
Deferred fuel and purchased power amortization
(38,150)
(1,617)
 
Ending balance
$ 12,465 
$ (9,688)
 
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended
Jul. 31, 2012
Dec. 31, 2016
Retired power plant costs
APS
Dec. 30, 2013
SCE
Four Corners
APS
Jun. 30, 2016
SCE
Four Corners
APS
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, 2016
Four Corners Units 4 and 5
SCE
Four Corners cost deferral
APS
Feb. 13, 2017
Subsequent Event
Navajo Plant
APS
Jan. 13, 2017
Subsequent Event
Compromise Proposal to meet Environmental and Emissions Standards and Rules
ACC
APS
Acquisition
 
 
 
 
 
 
 
 
 
 
Ownership interest acquired
 
 
 
 
 
 
48.00% 
 
 
 
Settlement agreement, ACC approved rate adjustment, annualized customer impact
 
 
 
 
 
$ 57.1 
 
 
 
 
Regulatory assets
 
 
 
 
12 
 
 
64 
 
 
Regulatory asset amortization period
3 years 
 
 
 
 
 
 
10 years 
 
 
Transmission termination agreement net receipt due to negotiation of alternate arrangement
 
 
40 
 
 
 
 
 
 
 
Regulatory assets, write of amount
 
 
 
12 
 
 
 
 
 
 
Number of days to file a petition
 
 
 
 
 
 
 
 
 
60 days 
Regulatory asset, net book value
 
116 
 
 
 
 
 
 
 
 
Asset net book value
 
 
 
 
 
 
 
 
$ 108 
 
Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Detail of regulatory assets
 
 
Regulatory assets, current
$ 106,875 
$ 149,555 
Regulatory assets, non-current
1,313,428 
1,214,146 
Pension
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
711,059 
619,223 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
9,913 
9,913 
Regulatory assets, non-current
117,591 
127,518 
Income taxes - AFUDC equity
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,305 
5,495 
Regulatory assets, non-current
152,118 
133,712 
Deferred fuel and purchased power - mark-to-market
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
71,852 
Regulatory assets, non-current
42,963 
69,697 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,689 
6,689 
Regulatory assets, non-current
56,894 
63,582 
Income taxes — investment tax credit basis adjustment
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,120 
1,766 
Regulatory assets, non-current
54,356 
48,462 
Lost fixed cost recovery
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
61,307 
45,507 
Regulatory assets, non-current
0 
0 
Palo Verde VIE
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
18,775 
18,143 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
35,595 
34,751 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
73,200 
50,453 
Loss on reacquired debt
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,637 
1,515 
Regulatory assets, non-current
16,942 
16,375 
AG-1 deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
5,868 
0 
Demand side management (b)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
3,744 
0 
Regulatory assets, non-current
0 
0 
Tax expense of Medicare subsidy
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,513 
1,520 
Regulatory assets, non-current
10,589 
12,163 
Transmission vegetation management
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
4,543 
Regulatory assets, non-current
0 
0 
Mead-Phoenix transmission line CIAC
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
332 
332 
Regulatory assets, non-current
10,708 
11,040 
Deferred fuel and purchased power
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
12,465 
0 
Regulatory assets, non-current
0 
0 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
418 
418 
Regulatory assets, non-current
5,182 
6,085 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
432 
5 
Regulatory assets, non-current
$ 1,588 
$ 2,942 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 99,899 
$ 145,766 
Regulatory liabilities, non-current
948,916 
994,152 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
279,976 
277,554 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
29,899 
39,746 
Regulatory liabilities, non-current
223,145 
240,367 
Other postretirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
32,662 
34,100 
Regulatory liabilities, non-current
123,913 
179,521 
Income taxes — deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
4,368 
3,604 
Regulatory liabilities, non-current
108,827 
97,175 
Income taxes - change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
1,771 
1,113 
Regulatory liabilities, non-current
70,898 
72,454 
Spent nuclear fuel
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
3,051 
Regulatory liabilities, non-current
71,726 
67,437 
Renewable energy standard (b)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
26,809 
43,773 
Regulatory liabilities, non-current
0 
4,365 
Demand side management (b)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
6,079 
Regulatory liabilities, non-current
20,472 
19,115 
Sundance maintenance
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
15,287 
13,678 
Deferred fuel and purchased power (b) (c)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
9,688 
Regulatory liabilities, non-current
0 
0 
Deferred gains on utility property
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,063 
2,062 
Regulatory liabilities, non-current
8,895 
6,001 
Four Corners coal reclamation
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
18,248 
8,920 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,327 
2,550 
Regulatory liabilities, non-current
$ 7,529 
$ 7,565 
Income Taxes (Details) (USD $)
12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2016
Feb. 17, 2011
ARIZONA
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Apr. 4, 2013
NEW MEXICO
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
NEW MEXICO
State Jurisdiction
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Palo Verde VIE
Income Taxes
 
 
 
 
 
 
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
 
 
74,000,000 
 
2,000,000 
 
General business tax credit carryforwards that will begin to expire in 2031
98,000,000 
 
 
 
 
 
Amount of federal and state loss carryforwards which will begin to expire in 2019
5,000,000 
 
 
 
 
 
increase (decrease) in deferred income taxes due to regulation adoption
$ 27,000,000 
 
 
 
 
 
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
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
$ 34,447 
$ 44,775 
$ 41,997 
Additions for tax positions of the current year
2,695 
2,175 
4,309 
Additions for tax positions of prior years
886 
0 
751 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(1,953)
(10,244)
(2,282)
Settlements with taxing authorities
0 
0 
0 
Lapses of applicable statute of limitations
0 
(2,259)
0 
Total unrecognized tax benefits, end of the year
36,075 
34,447 
44,775 
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
34,447 
44,775 
41,997 
Additions for tax positions of the current year
2,695 
2,175 
4,309 
Additions for tax positions of prior years
886 
0 
751 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(1,953)
(10,244)
(2,282)
Settlements with taxing authorities
0 
0 
0 
Lapses of applicable statute of limitations
0 
(2,259)
0 
Total unrecognized tax benefits, end of the year
$ 36,075 
$ 34,447 
$ 44,775 
Income Taxes - Summary of Unrecognized Tax Benefits (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax [Line Items]
 
 
 
Tax positions, that if recognized, would decrease our effective tax rate
$ 11,313 
$ 9,523 
$ 11,207 
Unrecognized tax benefit interest expense/(benefit) recognized
529 
(161)
752 
Unrecognized tax benefit interest accrued
1,333 
804 
965 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Income Tax [Line Items]
 
 
 
Tax positions, that if recognized, would decrease our effective tax rate
11,313 
9,523 
11,207 
Unrecognized tax benefit interest expense/(benefit) recognized
529 
(161)
752 
Unrecognized tax benefit interest accrued
$ 1,333 
$ 804 
$ 965 
Income Taxes - Components of Income Tax Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
$ 8,630 
$ (12,335)
$ 25,054 
State
 
 
 
 
 
 
 
 
1,259 
4,763 
10,382 
Total current
 
 
 
 
 
 
 
 
9,889 
(7,572)
35,436 
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
201,743 
221,505 
167,365 
State
 
 
 
 
 
 
 
 
24,779 
23,787 
17,904 
Total deferred
 
 
 
 
 
 
 
 
226,522 
245,292 
185,269 
Income tax expense
27,309 
141,446 
65,742 
1,914 
22,847 
139,555 
67,371 
7,947 
236,411 
237,720 
220,705 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
711 
6,485 
40,115 
State
 
 
 
 
 
 
 
 
4,276 
7,813 
15,598 
Total current
 
 
 
 
 
 
 
 
4,987 
14,298 
55,713 
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
215,178 
208,326 
165,027 
State
 
 
 
 
 
 
 
 
25,677 
23,217 
16,620 
Total deferred
 
 
 
 
 
 
 
 
240,855 
231,543 
181,647 
Income tax expense
 
 
 
 
 
 
 
 
$ 245,842 
$ 245,841 
$ 237,360 
Income Taxes - Effective Tax Rate Reconciliation (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
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
 
 
 
 
 
 
 
 
$ 244,278 
$ 242,869 
$ 225,540 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
16,311 
18,265 
18,149 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
0 
(2,169)
0 
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
844 
837 
830 
Allowance for equity funds used during construction (see Note 1)
 
 
 
 
 
 
 
 
(11,724)
(9,711)
(8,523)
Palo Verde VIE noncontrolling interest (see Note 18)
 
 
 
 
 
 
 
 
(6,823)
(6,626)
(9,135)
Investment tax credit amortization
 
 
 
 
 
 
 
 
(5,887)
(5,527)
(4,928)
Other
 
 
 
 
 
 
 
 
(588)
(218)
(1,228)
Income tax expense
27,309 
141,446 
65,742 
1,914 
22,847 
139,555 
67,371 
7,947 
236,411 
237,720 
220,705 
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
 
 
 
 
 
 
 
 
254,617 
250,267 
239,638 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
18,750 
20,433 
21,148 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
0 
(1,892)
0 
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
844 
837 
830 
Allowance for equity funds used during construction (see Note 1)
 
 
 
 
 
 
 
 
(11,724)
(9,711)
(8,523)
Palo Verde VIE noncontrolling interest (see Note 18)
 
 
 
 
 
 
 
 
(6,823)
(6,626)
(9,135)
Investment tax credit amortization
 
 
 
 
 
 
 
 
(5,887)
(5,527)
(4,928)
Other
 
 
 
 
 
 
 
 
(3,935)
(1,940)
(1,670)
Income tax expense
 
 
 
 
 
 
 
 
$ 245,842 
$ 245,841 
$ 237,360 
Income Taxes - Components of Deferred Income Tax Liability (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
DEFERRED TAX ASSETS
 
 
Risk management activities
$ 26,614 
$ 70,498 
Regulatory liabilities:
 
 
Asset retirement obligation and removal costs
200,140 
216,765 
Unamortized investment tax credits
113,195 
100,779 
Other postretirement liabilities
60,375 
83,034 
Other
63,311 
60,707 
Pension liabilities
204,436 
191,028 
Renewable energy incentives
56,379 
60,956 
Credit and loss carryforwards
75,944 
59,557 
Other
158,421 
149,033 
Total deferred tax assets
958,815 
992,357 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(3,297,989)
(3,116,752)
Risk management activities
(7,594)
(10,626)
Other postretirement assets
(63,477)
(71,737)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(61,088)
(54,110)
Deferred fuel and purchased power — mark-to-market
(21,396)
(55,020)
Pension benefits
(274,184)
(240,692)
Retired power plant costs (see Note 3)
(49,166)
(53,420)
Other
(123,987)
(108,441)
Other
(5,166)
(4,984)
Total deferred tax liabilities
(3,904,047)
(3,715,782)
Deferred income taxes — net
(2,945,232)
(2,723,425)
ARIZONA PUBLIC SERVICE COMPANY
 
 
DEFERRED TAX ASSETS
 
 
Risk management activities
26,614 
70,498 
Regulatory liabilities:
 
 
Asset retirement obligation and removal costs
200,140 
216,765 
Unamortized investment tax credits
113,195 
100,779 
Other postretirement liabilities
60,375 
83,034 
Other
63,311 
60,707 
Pension liabilities
194,981 
181,787 
Renewable energy incentives
56,379 
60,956 
Credit and loss carryforwards
1,645 
0 
Other
187,453 
176,016 
Total deferred tax assets
904,093 
950,542 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(3,297,989)
(3,116,752)
Risk management activities
(7,594)
(10,626)
Other postretirement assets
(62,819)
(70,986)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(61,088)
(54,110)
Deferred fuel and purchased power — mark-to-market
(21,396)
(55,020)
Pension benefits
(274,184)
(240,692)
Retired power plant costs (see Note 3)
(49,166)
(53,420)
Other
(123,987)
(108,441)
Other
(5,165)
(4,984)
Total deferred tax liabilities
(3,903,388)
(3,715,031)
Deferred income taxes — net
$ (2,999,295)
$ (2,764,489)
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Pinnacle West
 
 
Lines of Credit and Short-Term Borrowings
 
 
Commitment fees (as a percent)
0.125% 
0.125% 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Lines of Credit and Short-Term Borrowings
 
 
Commitment fees (as a percent)
0.10% 
0.10% 
Revolving credit facility
 
 
Lines of Credit and Short-Term Borrowings
 
 
Amount committed
$ 1,275,000,000 
$ 1,200,000,000 
Commercial paper
(177,200,000)
0 
Unused amount
1,097,800,000 
1,200,000,000 
Revolving credit facility |
Pinnacle West
 
 
Lines of Credit and Short-Term Borrowings
 
 
Amount committed
275,000,000 
200,000,000 
Commercial paper
(41,700,000)
0 
Unused amount
233,300,000 
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 
Commercial paper
(135,500,000)
0 
Unused amount
$ 864,500,000 
$ 1,000,000,000 
Lines of Credit and Short-Term Borrowings (Details) (USD $)
0 Months Ended 0 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2016
Pinnacle West
Dec. 31, 2015
Pinnacle West
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Feb. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 31, 2016
Revolving credit facility
Dec. 31, 2015
Revolving credit facility
Dec. 31, 2016
Revolving credit facility
Pinnacle West
Dec. 31, 2015
Revolving credit facility
Pinnacle West
Aug. 31, 2016
Revolving credit facility
Pinnacle West
Revolving credit facility maturing August 2017
Dec. 31, 2016
Revolving credit facility
Pinnacle West
Revolving credit facility maturing August 2017
Aug. 31, 2016
Revolving credit facility
Pinnacle West
Revolving credit facility maturing August 2017
May 12, 2016
Revolving credit facility
Pinnacle West
Revolving credit facility maturing in May 2019
Dec. 31, 2016
Revolving credit facility
Pinnacle West
Revolving credit facility maturing May 2021
May 13, 2016
Revolving credit facility
Pinnacle West
Revolving credit facility maturing May 2021
Dec. 31, 2016
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
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 in May 2019
Dec. 31, 2016
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing May 2021
May 13, 2016
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing May 2021
Dec. 31, 2016
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing in 2020 and 2021
Facility
Dec. 31, 2016
Letter of credit
Pinnacle West
Revolving credit facility maturing May 2021
Dec. 31, 2016
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing in 2020 and 2021
Dec. 31, 2016
Commercial paper
Pinnacle West
Revolving credit facility maturing May 2021
Dec. 31, 2016
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Mar. 31, 2016
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing in 2020 and 2021
Aug. 31, 2016
London Interbank Offered Rate (LIBOR) [Member]
Revolving credit facility
Pinnacle West
Revolving credit facility maturing August 2017
Lines of Credit and Short-Term Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount committed
 
 
 
 
 
 
 
$ 1,275,000,000 
$ 1,200,000,000 
$ 275,000,000 
$ 200,000,000 
 
 
 
$ 200,000,000 
 
$ 200,000,000 
$ 1,000,000,000 
$ 1,000,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 1,000,000,000 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders
 
 
 
 
 
 
 
 
 
 
 
 
 
75,000,000 
 
300,000,000 
 
 
 
700,000,000 
 
700,000,000 
 
1,400,000,000 
 
 
 
 
 
 
 
 
 
Long-term line of credit
 
 
 
 
 
 
 
177,200,000 
0 
41,700,000 
0 
 
 
 
 
0 
 
135,500,000 
0 
 
 
 
 
0 
 
 
 
 
 
 
 
135,500,000 
 
Outstanding letters of credit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
35,000,000 
0 
 
 
 
 
 
 
Debt instrument, term
 
 
 
 
 
 
 
 
 
 
 
364 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, basis spread on variable rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.80% 
Commercial paper
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,700,000 
 
 
 
 
 
Short-term borrowings
177,200,000 
0 
41,700,000 
0 
135,500,000 
0 
 
 
 
 
 
 
40,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum commercial paper support available under credit facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000,000 
500,000,000 
250,000,000 
 
 
Number of credit facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
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 $)
0 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2016
Maximum
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 5, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Minimum
ACC
Dec. 31, 2016
Pinnacle West
Dec. 31, 2015
Pinnacle West
Apr. 22, 2016
Term Loan Facility Maturing April 22, 2019
ARIZONA PUBLIC SERVICE COMPANY
Term loan
May 6, 2016
Unsecured Senior Notes 3.75 Percent Mature on 15 May, 2046
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
Jun. 1, 2016
Arizona Pollution Control Corporation Revenue Refunding Bonds, 2009 Series D and E
ARIZONA PUBLIC SERVICE COMPANY
Current maturities of long-term debt
Jun. 1, 2016
Arizona pollution control corporation revenue refunding bonds, 2009 series A
ARIZONA PUBLIC SERVICE COMPANY
Aug. 1, 2016
Unsecured Senior Notes 6.25 Percent Mature on 01 August, 2016
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
Aug. 1, 2016
Unsecured Senior Notes 6.25 Percent Mature on 01 August, 2016
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
Sep. 20, 2016
Unsecured Senior Notes 2.55 Percent Mature on 15 September, 2026
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
Sep. 20, 2016
Arizona Pollution Control Corporation Revenue Refunding Bond, 2009 Series B
ARIZONA PUBLIC SERVICE COMPANY
Current maturities of long-term debt
Dec. 6, 2016
Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds
ARIZONA PUBLIC SERVICE COMPANY
Current maturities of long-term debt
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes issued
 
 
 
 
 
 
 
 
 
 
 
$ 100,000,000 
$ 350,000,000 
 
 
 
 
$ 250,000,000 
 
 
Interest rate (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
3.75% 
 
 
 
6.25% 
2.55% 
 
 
Principal balance repaid
 
 
 
 
 
 
 
 
 
 
 
 
 
64,000,000 
13,000,000 
 
 
 
27,000,000 
17,000,000 
Repayments of debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250,000,000 
 
 
 
 
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)
 
 
 
47.00% 
 
 
 
 
 
48.00% 
 
 
 
 
 
 
 
 
 
 
Required common equity ratio ordered by ACC (as a percent) (at least)
 
 
 
 
 
 
 
 
40.00% 
 
 
 
 
 
 
 
 
 
 
 
Total shareholder equity
4,803,622,000 
4,583,917,000 
 
4,905,680,000 
4,679,254,000 
4,900,000,000 
 
 
 
4,803,622,000 
4,583,917,000 
 
 
 
 
 
 
 
 
 
Total capitalization
 
 
 
 
 
9,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
3,600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
Dec. 31, 2016
Dec. 31, 2015
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Total long-term debt
$ 4,146,785 
$ 3,819,971 
Long-term debt less current maturities
4,021,785 
3,462,391 
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
4,058,125 
 
Unamortized discount
(11,816)
(10,374)
Unamortized premium
4,506 
4,686 
Unamortized debt issue costs
(29,030)
(27,896)
Total long-term debt
4,021,785 
3,694,971 
Less current maturities
0 
(357,580)
Total long-term debt less current maturities
4,021,785 
3,337,391 
Pinnacle West
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
4,183,125 
 
Total long-term debt
125,000 
125,000 
Long-term debt less current maturities
0 
125,000 
Pollution Control Bonds - Variable |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
35,975 
92,405 
Pollution Control Bonds - Variable |
APS |
Minimum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
0.81% 
0.01% 
Pollution Control Bonds - Variable |
APS |
Maximum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
 
0.24% 
Pollution Control Bonds - Fixed |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
147,150 
211,150 
Pollution Control Bonds - Fixed |
APS |
Minimum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Interest rate (as a percent)
1.75% 
1.75% 
Pollution Control Bonds - Fixed |
APS |
Maximum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Interest rate (as a percent)
4.70% 
4.70% 
Total Pollution Control Bonds |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
183,125 
303,555 
Senior unsecured notes |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Gross long-term debt
3,725,000 
3,375,000 
Senior unsecured notes |
APS |
Minimum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Interest rate (as a percent)
2.20% 
2.20% 
Senior unsecured notes |
APS |
Maximum
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Interest rate (as a percent)
8.75% 
8.75% 
Term loan facility |
Pinnacle West
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Total long-term debt
125,000 
125,000 
Less current maturities
(125,000)
0 
Total long-term debt less current maturities
0 
125,000 
Weighted-average interest rate (as a percent)
1.52% 
1.174% 
Term loan |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Weighted-average interest rate (as a percent)
1.427% 
1.024% 
Term loan |
Term loan facility maturing June 26, 2018 |
APS
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
Term loans
$ 150,000 
$ 50,000 
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Pinnacle West
 
Principal payments due on long-term debt
 
2017
$ 125,000 
2018
82,000 
2019
600,000 
2020
250,000 
2021
0 
Thereafter
3,126,125 
Total
4,183,125 
ARIZONA PUBLIC SERVICE COMPANY
 
Principal payments due on long-term debt
 
2017
0 
2018
82,000 
2019
600,000 
2020
250,000 
2021
0 
Thereafter
3,126,125 
Total
$ 4,058,125 
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
$ 4,146,785 
$ 3,819,971 
Fair Value
4,425,789 
4,106,367 
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
4,021,785 
3,694,971 
Fair Value
$ 4,300,789 
$ 3,981,367 
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, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2016
Pension Benefits
Dec. 31, 2015
Pension Benefits
Dec. 31, 2014
Pension Benefits
Dec. 31, 2016
Pension Benefits
Fixed income securities
Dec. 31, 2016
Pension Benefits
Return-generating assets
Dec. 31, 2016
Pension Benefits
Developed equities
Dec. 31, 2016
Pension Benefits
Emerging equities
Dec. 31, 2016
Pension Benefits
Alternative investments
Dec. 31, 2016
Other postretirement benefits
Dec. 31, 2015
Other postretirement benefits
Dec. 31, 2014
Other postretirement benefits
Jan. 1, 2015
Other postretirement benefits
Age
Dec. 31, 2016
Other postretirement benefits
Fixed income
Dec. 31, 2016
Other postretirement benefits
Non-fixed income
Dec. 31, 2016
Pinnacle West
Dec. 31, 2015
Pinnacle West
Dec. 31, 2014
Pinnacle West
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Other postretirement benefits
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Other postretirement benefits
Dec. 31, 2014
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent asset
 
166,206,000 
185,997,000 
 
 
 
 
0 
0 
 
 
 
 
 
 
166,206,000 
185,997,000 
 
 
 
 
 
 
 
162,911,000 
182,625,000 
 
 
 
 
 
 
Amount of other postretirement benefit trust assets for union employee medical costs
 
140,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
 
 
 
6.55% 
 
 
 
 
 
 
 
6.37% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
54,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
 
 
 
 
 
 
57.00% 
43.00% 
 
 
 
 
 
 
 
51.00% 
49.00% 
 
 
 
 
 
 
 
 
 
 
 
Contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Employer's contributions under the plan
 
 
 
 
 
 
 
100,000,000 
100,000,000 
175,000,000 
 
 
 
 
 
819,000 
1,000,000 
1,000,000 
 
 
 
 
 
 
 
 
100,000,000 
100,000,000 
175,000,000 
1,000,000 
1,000,000 
1,000,000 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017 (less than)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018 (less than)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019 (less than)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 10,000,000 
$ 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, 2016
Dec. 31, 2015
Dec. 31, 2014
Pension Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost-benefits earned during the period
$ 53,792 
$ 59,627 
$ 53,080 
Interest cost on benefit obligation
131,647 
123,983 
129,194 
Expected return on plan assets
(173,906)
(179,231)
(158,998)
Amortization of prior service cost (credit)
527 
594 
869 
Amortization of net actuarial loss
40,717 
31,056 
10,963 
Net periodic benefit cost
52,777 
36,029 
35,108 
Portion of cost charged to expense
26,172 
20,036 
21,985 
Other Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost-benefits earned during the period
14,993 
16,827 
18,139 
Interest cost on benefit obligation
29,721 
28,102 
41,243 
Expected return on plan assets
(36,495)
(36,855)
(46,400)
Amortization of prior service cost (credit)
(37,883)
(37,968)
(9,626)
Amortization of net actuarial loss
4,589 
4,881 
1,175 
Net periodic benefit cost
(25,075)
(25,013)
4,531 
Portion of cost charged to expense
$ (12,435)
$ (10,391)
$ 6,000 
Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Pension Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
$ 3,033,803 
$ 3,078,648 
 
Service cost
53,792 
59,627 
53,080 
Interest cost
131,647 
123,983 
129,194 
Benefit payments
(142,247)
(137,115)
 
Actuarial (gain) loss
127,467 
(91,340)
 
Benefit obligation at the end of the period
3,204,462 
3,033,803 
3,078,648 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
2,542,774 
2,615,404 
 
Actual return on plan assets
166,408 
(44,690)
 
Employer's contributions under the plan
100,000 
100,000 
175,000 
Benefit payments
(133,825)
(127,940)
 
Balance at the end of the period
2,675,357 
2,542,774 
2,615,404 
Funded Status at the end of the period
(529,105)
(491,029)
 
Other Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
647,020 
682,335 
 
Service cost
14,993 
16,827 
18,139 
Interest cost
29,721 
28,102 
41,243 
Benefit payments
(26,231)
(24,988)
 
Actuarial (gain) loss
50,942 
(55,256)
 
Benefit obligation at the end of the period
716,445 
647,020 
682,335 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
833,017 
834,625 
 
Actual return on plan assets
63,463 
(2,399)
 
Employer's contributions under the plan
819 
1,000 
1,000 
Benefit payments
(14,648)
0 
 
Balance at the end of the period
882,651 
833,017 
834,625 
Funded Status at the end of the period
$ 166,206 
$ 185,997 
 
Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) (Pension Benefits, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
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
$ 3,204,462 
$ 3,033,803 
Accumulated benefit obligation
3,049,406 
2,873,467 
Fair value of plan assets
$ 2,675,357 
$ 2,542,774 
Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Amounts recognized on the Consolidated Balance Sheets
 
 
Noncurrent asset
$ 166,206 
$ 185,997 
Pension Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Noncurrent asset
0 
0 
Current liability
(19,795)
(10,031)
Noncurrent liability
(509,310)
(480,998)
Net amount recognized
(529,105)
(491,029)
Other Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Noncurrent asset
166,206 
185,997 
Current liability
0 
0 
Noncurrent liability
0 
0 
Net amount recognized
$ 166,206 
$ 185,997 
Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Details related to accumulated other comprehensive loss
 
 
Accumulated other comprehensive loss
$ 39,070 
$ 37,593 
Other Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
146,509 
127,124 
Prior service cost (credit)
(303,417)
(341,301)
APS’s portion recorded as a regulatory (asset) liability
156,575 
213,621 
Income tax expense (benefit)
833 
925 
Accumulated other comprehensive loss
500 
369 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
5,181 
 
Prior service cost (credit)
(37,842)
 
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017
(32,661)
 
Pension Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
773,750 
679,501 
Prior service cost (credit)
81 
609 
APS’s portion recorded as a regulatory (asset) liability
(711,059)
(619,223)
Income tax expense (benefit)
(24,202)
(23,663)
Accumulated other comprehensive loss
38,570 
37,224 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
46,971 
 
Prior service cost (credit)
81 
 
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017
$ 47,052 
 
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, 2016
Dec. 31, 2015
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
Rate of compensation increase (as a percent)
 
 
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% 
7.00% 
Initial post-65 health care cost trend rate (as a percent)
5.00% 
7.50% 
5.00% 
5.00% 
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 
0 years 
Pension Benefits
 
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
Discount rate (as a percent)
 
 
4.08% 
4.37% 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
 
Discount rate (as a percent)
4.88% 
4.88% 
4.37% 
4.02% 
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% 
6.90% 
Other Benefits
 
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
 
Discount rate (as a percent)
 
 
4.17% 
4.52% 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
 
Discount rate (as a percent)
4.41% 
5.10% 
4.52% 
4.14% 
Expected long-term return on plan assets (as a percent)
4.25% 
6.80% 
4.45% 
4.45% 
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
 
 
 8,430 
 
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
 
 
(5,455)
 
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs
 
 
8,440 
 
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs
 
 
(6,527)
 
Effect of 1% increase on the accumulated other postretirement benefit obligation
 
 
108,046 
 
Effect of 1% decrease on the accumulated other postretirement benefit obligation
 
 
 (86,651)
 
Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Pension Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
$ 2,675,357 
$ 2,542,774 
$ 2,615,404 
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
749,541 
680,351 
 
Fair value of plan assets
2,675,357 
2,542,774 
 
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
613,193 
640,679 
 
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
1,312,623 
1,221,744 
 
Other Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
882,651 
833,017 
834,625 
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
123,234 
135,059 
 
Fair value of plan assets
882,651 
833,017 
 
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
456,718 
449,826 
 
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
302,699 
248,132 
 
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
13,995 
1,893 
 
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
13,995 
1,893 
 
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
304 
240 
 
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
304 
240 
 
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
1,210,453 
1,108,736 
 
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
1,210,453 
1,108,736 
 
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
268,193 
217,026 
 
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
268,193 
217,026 
 
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
112,583 
274,778 
 
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
112,583 
274,778 
 
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
145,255 
131,435 
 
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
145,255 
131,435 
 
Other |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
102,170 
113,008 
 
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
102,170 
113,008 
 
Other |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
34,506 
31,106 
 
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
34,506 
31,106 
 
Common stock 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
235,109 
247,701 
 
Common stock 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
235,109 
247,701 
 
Common stock 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
243,741 
265,583 
 
Common stock 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
243,741 
265,583 
 
Mutual fund |
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
251,506 
 
 
Mutual fund |
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
251,506 
 
 
Mutual fund |
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
67,418 
 
 
Mutual fund |
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
67,418 
 
 
Equities |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
266,840 
315,989 
 
Fair value of plan assets
266,840 
315,989 
 
Equities |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
95,814 
110,055 
 
Fair value of plan assets
95,814 
110,055 
 
Real estate |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
161,449 
150,359 
 
Fair value of plan assets
161,449 
150,359 
 
Real estate |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
14,509 
13,512 
 
Fair value of plan assets
14,509 
13,512 
 
Partnerships |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
208,915 
169,937 
 
Fair value of plan assets
208,915 
169,937 
 
Partnerships |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
3,060 
 
 
Fair value of plan assets
3,060 
 
 
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
 
 
 
Other
112,337 
44,066 
 
Fair value of plan assets
112,337 
44,066 
 
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
 
 
 
Other
9,851 
11,492 
 
Fair value of plan assets
9,851 
11,492 
 
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 
 
Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Pension Benefits
 
Estimated Future Benefit Payments
 
2017
$ 172,859 
2018
173,232 
2019
182,944 
2020
191,037 
2021
196,292 
Years 2022-2026
1,049,149 
Other Benefits
 
Estimated Future Benefit Payments
 
2017
31,126 
2018
33,795 
2019
36,195 
2020
37,998 
2021
39,368 
Years 2022-2026
$ 201,944 
Leases (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Trust
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 1986
Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
Lease expense
$ 16,000,000 
$ 17,000,000 
$ 18,000,000 
 
Pinnacle West
 
 
 
 
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
2017
12,330,000 
 
 
 
2018
10,987,000 
 
 
 
2019
9,019,000 
 
 
 
2020
7,688,000 
 
 
 
2021
5,266,000 
 
 
 
Thereafter
59,647,000 
 
 
 
Total future lease commitments
104,937,000 
 
 
 
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
 
 
 
 
2017
11,919,000 
 
 
 
2018
10,690,000 
 
 
 
2019
8,767,000 
 
 
 
2020
7,439,000 
 
 
 
2021
5,020,000 
 
 
 
Thereafter
57,207,000 
 
 
 
Total future lease commitments
101,042,000 
 
 
 
Lease expense
$ 15,000,000 
$ 14,000,000 
$ 15,000,000 
 
Number of VIE lessor trusts
3 
 
 
3 
Jointly-Owned Facilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Jul. 6, 2016
4CA
 
 
Interests in jointly-owned facilities
 
 
Plant in Service
$ 110,000 
 
Accumulated Depreciation
79,000 
 
Construction work in progress
30,000 
 
Palo Verde Units 1 and 3 |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
29.10% 
 
Plant in Service
1,770,324 
 
Accumulated Depreciation
1,080,072 
 
Construction work in progress
17,615 
 
Palo Verde Unit 2 |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
16.80% 
 
Plant in Service
581,572 
 
Accumulated Depreciation
360,757 
 
Construction work in progress
9,717 
 
Palo Verde Common |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
28.00% 
 
Plant in Service
672,799 
 
Accumulated Depreciation
242,649 
 
Construction work in progress
62,479 
 
Palo Verde Sale Leaseback |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Plant in Service
351,050 
 
Accumulated Depreciation
237,535 
 
Construction work in progress
0 
 
Four Corners Generating Station |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
63.00% 
 
Plant in Service
934,837 
 
Accumulated Depreciation
578,924 
 
Construction work in progress
248,072 
 
Navajo Generating Station Units 1, 2 and 3 |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
14.00% 
 
Plant in Service
279,629 
 
Accumulated Depreciation
176,931 
 
Construction work in progress
5,761 
 
Cholla Common Facilities |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
63.30% 
 
Plant in Service
159,707 
 
Accumulated Depreciation
58,276 
 
Construction work in progress
806 
 
ANPP 500kV System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
33.60% 
 
Plant in Service
127,970 
 
Accumulated Depreciation
38,610 
 
Construction work in progress
2,291 
 
Navajo Southern System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
22.50% 
 
Plant in Service
62,135 
 
Accumulated Depreciation
20,491 
 
Construction work in progress
334 
 
Palo Verde — Yuma 500kV System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
19.00% 
 
Plant in Service
13,699 
 
Accumulated Depreciation
5,368 
 
Construction work in progress
408 
 
Four Corners Switchyards |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
51.30% 
 
Plant in Service
39,850 
 
Accumulated Depreciation
10,474 
 
Construction work in progress
1,044 
 
Phoenix — Mead System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
17.10% 
 
Plant in Service
39,330 
 
Accumulated Depreciation
13,725 
 
Construction work in progress
85 
 
Palo Verde — Rudd 500kV System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
50.00% 
 
Plant in Service
91,904 
 
Accumulated Depreciation
19,818 
 
Construction work in progress
227 
 
Morgan — Pinnacle Peak System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
65.20% 
 
Plant in Service
140,374 
 
Accumulated Depreciation
13,557 
 
Construction work in progress
0 
 
Round Valley System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
50.00% 
 
Plant in Service
515 
 
Accumulated Depreciation
127 
 
Construction work in progress
0 
 
Palo Verde — Morgan System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
85.80% 
 
Plant in Service
125,908 
 
Accumulated Depreciation
1,326 
 
Construction work in progress
28,949 
 
Hassayampa — North Gila System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
80.00% 
 
Plant in Service
142,541 
 
Accumulated Depreciation
3,231 
 
Construction work in progress
0 
 
Cholla 500kV Switchyard |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
85.70% 
 
Plant in Service
5,078 
 
Accumulated Depreciation
1,201 
 
Construction work in progress
0 
 
Saguaro 500kV Switchyard |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
75.00% 
 
Plant in Service
20,456 
 
Accumulated Depreciation
12,426 
 
Construction work in progress
$ 2 
 
Cholla common construction facilities |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
50.50% 
 
El Paso's Interest in Four Corners |
4CA
 
 
Interests in jointly-owned facilities
 
 
Ownership interest acquired
7.00% 
7.00% 
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)
9 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended
Sep. 30, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Coal take-or-pay commitments
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, 2016
ARIZONA PUBLIC SERVICE COMPANY
Renewable energy credits
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Obligations
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Balance Sheet Obligations
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Balance Sheet Obligations
Dec. 31, 2016
4CA
Coal Mine Reclamation Obligations
Dec. 31, 2016
4CA
Coal Mine Reclamation Balance Sheet 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
Dec. 31, 2016
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Dec. 31, 2016
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
ARIZONA PUBLIC SERVICE COMPANY
time_period
claim
Jan. 1, 2017
Subsequent Event
ARIZONA PUBLIC SERVICE COMPANY
Feb. 1, 2017
Subsequent Event
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Feb. 1, 2017
Subsequent Event
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Litigation settlement, amount
 
 
 
 
 
 
 
 
 
 
 
 
$ 57,400,000 
$ 16,700,000 
 
 
 
$ 11,300,000 
$ 3,300,000 
New claims filed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
Number of settlement agreement time periods
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
Proceeds from legal settlements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
53,900,000 
15,700,000 
 
 
 
Maximum insurance against public liability per occurrence for a nuclear incident
 
13,400,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum available nuclear liability insurance
375,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
450,000,000 
 
 
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program
 
13,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
13,000,000,000 
 
 
Maximum assessment per reactor for each nuclear incident
 
127,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual limit per incident with respect to maximum assessment
 
18,900,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of VIE lessor trusts
 
3 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum potential retrospective assessment per incident of APS
 
111,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
23,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Collateral assurance provided based on rating triggers
 
64,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Period to provide collateral assurance based on rating triggers
 
20 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
977,000,000 
 
195,428,000 
 
 
40,000,000 
17,000,000 
 
 
1,000,000 
 
 
 
 
 
 
 
 
2018
 
737,000,000 
 
189,588,000 
 
 
40,000,000 
18,000,000 
 
 
1,000,000 
 
 
 
 
 
 
 
 
2019
 
598,000,000 
 
193,818,000 
 
 
40,000,000 
19,000,000 
 
 
1,000,000 
 
 
 
 
 
 
 
 
2020
 
525,000,000 
 
198,160,000 
 
 
40,000,000 
21,000,000 
 
 
1,000,000 
 
 
 
 
 
 
 
 
2021
 
524,000,000 
 
202,619,000 
 
 
40,000,000 
22,000,000 
 
 
2,000,000 
 
 
 
 
 
 
 
 
Thereafter
 
7,300,000,000 
 
2,068,355,000 
 
 
420,000,000 
241,000,000 
 
 
17,000,000 
 
 
 
 
 
 
 
 
Total obligation
 
 
 
3,000,000,000 
 
 
 
 
207,000,000 
202,000,000 
 
15,000,000 
 
 
 
 
 
 
 
Present value of commitments
 
 
 
2,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total purchases
 
 
 
$ 160,066,000 
$ 211,327,000 
$ 236,773,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)
In Millions, unless otherwise specified
0 Months Ended 12 Months Ended 0 Months Ended
Sep. 8, 2011
Customer
kV
Dec. 31, 2016
Aug. 6, 2013
Contaminated groundwater wells
Defendant
Superfund
 
 
 
Costs related to investigation and study under Superfund site
 
$ 2 
 
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit
 
 
24 
Southwest Power Outage
 
 
 
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 
 
 
Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)
12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2016
Jul. 6, 2016
Payment Guarantee
guarantee
Dec. 31, 2016
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Cholla Units 1-3
ARIZONA PUBLIC SERVICE COMPANY
Mar. 16, 2016
New Mexico Tax Matter
Four Corners
May 23, 2013
New Mexico Tax Matter
Four Corners
Mar. 16, 2016
New Mexico Tax Matter
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
May 23, 2013
New Mexico Tax Matter
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Equity Lessors Sale Leaseback Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Four Corners Units 4 and 5
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Four Corners Units 4 and 5
Navajo Plant
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Four Corners Units 4 and 5
Natural Gas Tolling Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
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, 2016
Mercury and Air Toxic Standards
Navajo Generating Station
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Coal Combustion Waste
Navajo Generating Station
ARIZONA PUBLIC SERVICE COMPANY
Jun. 24, 2016
Coal Combustion Waste
Boron Inclusion on List of Groundwater Constituents
Navajo Generating Station
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Coal Combustion Waste
Minimum
Cholla
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Coal Combustion Waste
Maximum
Cholla
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
El Paso's Interest in Four Corners
4CA
Jul. 6, 2016
El Paso's Interest in Four Corners
4CA
Environmental Matters [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage share 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 
 
 
 
 
 
 
 
45,000,000 
 
 
 
 
 
1,000,000 
 
5,000,000 
40,000,000 
 
 
Period to complete rulemaking proceeding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
Clean power plan, optional extension period
2 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal severance surtax, penalty, and interest
 
 
 
 
 
30,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share of the assessment
 
 
 
 
 
 
 
12,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partial payment assessment
 
 
 
 
 
 
 
800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Litigation settlement, amount
 
 
 
 
1,000,000 
 
800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
 
 
 
$ 35,000,000 
$ 53,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Number of parental guarantees
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership interest acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
7.00% 
Asset Retirement Obligations (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Changes attributable to:
 
 
Asset retirement obligations, current
$ 9,135,000 
$ 28,573,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Change in asset retirement obligations
 
 
Asset retirement obligations at the beginning of year
443,576,000 
390,750,000 
Changes attributable to:
 
 
Accretion expense
26,656,000 
25,163,000 
Settlements
(15,732,000)
(32,048,000)
Estimated cash flow revisions
151,046,000 
17,556,000 
Newly incurred or acquired obligations
18,929,000 
42,155,000 
Asset retirement obligations at the end of year
624,475,000 
443,576,000 
Asset retirement obligations, current
8,703,000 
28,573,000 
Ocotillo Steam Units |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Asset Retirement Obligations
 
 
Number of constructed turbine units
5 
 
Changes attributable to:
 
 
Newly incurred or acquired obligations
10,000,000 
 
El Paso's Share of Four Corners Units 4 & 5 [Member] |
4CA
 
 
Changes attributable to:
 
 
Newly incurred or acquired obligations
9,000,000 
 
Four Corners |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Changes attributable to:
 
 
Settlements
(16,000,000)
(32,000,000)
Estimated cash flow revisions
 
24,000,000 
Palo Verde Nuclear Generating Station |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Asset Retirement Obligations
 
 
Increase in plant services
131,000,000 
 
Decrease in regulatory liability
20,000,000 
 
Changes attributable to:
 
 
Estimated cash flow revisions
151,000,000 
 
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 or acquired obligations
 
$ 39,000,000 
Selected Quarterly Financial Data (Unaudited) (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
OPERATING REVENUES
$ 739,199 
$ 1,166,922 
$ 915,394 
$ 677,167 
$ 734,430 
$ 1,199,146 
$ 890,648 
$ 671,219 
$ 3,498,682 
$ 3,495,443 
$ 3,491,632 
Operations and maintenance
208,277 
217,568 
242,279 
243,195 
222,019 
220,449 
210,965 
214,944 
911,319 
868,377 
908,025 
Operating income
122,816 
451,258 
231,748 
50,162 
109,834 
445,111 
231,973 
67,684 
855,984 
854,602 
811,242 
INCOME TAXES (Note 4)
27,309 
141,446 
65,742 
1,914 
22,847 
139,555 
67,371 
7,947 
236,411 
237,720 
220,705 
Net income
58,119 
267,900 
126,182 
9,326 
45,978 
261,978 
127,507 
20,727 
461,527 
456,190 
423,696 
Net income attributable to common shareholders
53,246 
263,027 
121,308 
4,453 
41,117 
257,116 
122,902 
16,122 
442,034 
437,257 
397,595 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.48 
$ 2.36 
$ 1.09 
$ 0.04 
$ 0.37 
$ 2.32 
$ 1.11 
$ 0.15 
$ 3.97 
$ 3.94 
$ 3.59 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 0.47 
$ 2.35 
$ 1.08 
$ 0.04 
$ 0.37 
$ 2.30 
$ 1.10 
$ 0.14 
$ 3.95 
$ 3.92 
$ 3.58 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
737,006 
1,166,359 
909,757 
676,632 
733,586 
1,198,380 
889,723 
670,668 
3,489,754 
3,492,357 
3,488,946 
Operations and maintenance
197,319 
209,366 
233,712 
238,711 
219,146 
216,011 
208,031 
209,947 
879,108 
853,135 
882,442 
Operating income
95,765 
307,601 
165,684 
48,930 
86,709 
301,238 
162,704 
61,333 
617,980 
611,984 
592,792 
INCOME TAXES (Note 4)
 
 
 
 
 
 
 
 
245,842 
245,841 
237,360 
Net income
 
 
 
 
 
 
 
 
481,634 
469,207 
447,320 
Net income attributable to common shareholders
$ 58,480 
$ 269,220 
$ 127,188 
$ 7,253 
$ 43,857 
$ 261,187 
$ 125,362 
$ 19,868 
$ 462,141 
$ 450,274 
$ 421,219 
Fair Value Measurements - Fair Value of Assets and Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Assets
 
 
Nuclear decommissioning trust
$ 779,586 
$ 735,196 
Total assets
11,076 
30,364 
Fair value measurement on a recurring basis
 
 
Assets
 
 
Coal reclamation trust - Cash equivalents
14,521 
 
Other
(35,103)
(25,345)
Derivative assets
19,695 
28,011 
Other
354,056 
314,622 
Nuclear decommissioning trust
779,586 
735,196 
Other
318,953 
289,277 
Total assets
813,802 
763,207 
Liabilities
 
 
Other
31,049 
39,698 
Derivative Liability
(73,074)
(167,689)
Fair value measurement on a recurring basis |
US commingled equity funds
 
 
Assets
 
 
Other
353,261 
314,957 
Nuclear decommissioning trust
353,261 
314,957 
Fair value measurement on a recurring basis |
Cash and cash equivalents
 
 
Assets
 
 
Other
795 
(335)
Nuclear decommissioning trust
795 
11,925 
Fair value measurement on a recurring basis |
U.S. Treasury
 
 
Assets
 
 
Nuclear decommissioning trust
95,441 
117,245 
Fair value measurement on a recurring basis |
Corporate
 
 
Assets
 
 
Nuclear decommissioning trust
111,623 
96,243 
Fair value measurement on a recurring basis |
Mortgage-backed securities
 
 
Assets
 
 
Nuclear decommissioning trust
115,337 
99,065 
Fair value measurement on a recurring basis |
Municipality bonds
 
 
Assets
 
 
Nuclear decommissioning trust
80,997 
72,206 
Fair value measurement on a recurring basis |
Other
 
 
Assets
 
 
Nuclear decommissioning trust
22,132 
23,555 
Fair value measurement on a recurring basis |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Coal reclamation trust - Cash equivalents
14,521 
 
Decommissioning fund investments, gross fair value
95,441 
129,505 
Gross assets, fair value disclosure
109,962 
129,505 
Liabilities
 
 
Gross derivative liability
0 
0 
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
95,441 
117,245 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Gross derivative assets
43,722 
22,992 
Decommissioning fund investments, gross fair value
330,089 
291,069 
Gross assets, fair value disclosure
373,811 
314,061 
Liabilities
 
 
Gross derivative liability
(45,641)
(144,044)
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Corporate
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
111,623 
96,243 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
115,337 
99,065 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Municipality bonds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
80,997 
72,206 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Other
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
22,132 
23,555 
Fair value measurement on a recurring basis |
Significant Unobservable Inputs (Level 3)
 
 
Assets
 
 
Gross derivative assets
11,076 
30,364 
Gross assets, fair value disclosure
11,076 
30,364 
Liabilities
 
 
Gross derivative liability
$ (58,482)
$ (63,343)
Fair Value Measurements - Level 3 Quantitative Information (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
$ 11,076 
$ 30,364 
Liabilities
58,482 
63,343 
Electricity forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
10,648 
24,543 
Liabilities
32,042 
54,679 
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)
16.43 
15.92 
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)
41.07 
40.73 
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)
29.86 
26.86 
Option Contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Liabilities
 
5,628 
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 
Implied electricity price volatilities (as a percent)
   
40.00% 
Implied natural gas price volatilities (as a percent)
   
32.00% 
Natural gas forward price (per MMbtu)
 
   
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 
Implied electricity price volatilities (as a percent)
   
59.00% 
Implied natural gas price volatilities (as a percent)
   
40.00% 
Natural gas forward price (per MMbtu)
 
   
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 
Implied electricity price volatilities (as a percent)
 
52.00% 
Implied natural gas price volatilities (as a percent)
 
35.00% 
Natural gas forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
428 
5,821 
Liabilities
$ 26,440 
$ 3,036 
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)
2.32 
2.18 
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)
3.60 
3.14 
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)
 
2.61 
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)
2.81 
 
Fair Value Measurements Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Total net gains (losses) realized/unrealized:
 
 
Net derivative beginning balance
$ (32,979,000)
$ (41,386,000)
Included in earnings
0 
0 
Included in OCI
88,000 
(452,000)
Deferred as a regulatory asset or liability
(37,543,000)
(4,009,000)
Settlements
15,146,000 
14,809,000 
Transfers into Level 3 from Level 2
1,900,000 
(6,256,000)
Transfers from Level 3 into Level 2
5,982,000 
4,315,000 
Net derivative ending balance
(47,406,000)
(32,979,000)
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, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Earnings Per Share [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common shareholders
$ 53,246 
$ 263,027 
$ 121,308 
$ 4,453 
$ 41,117 
$ 257,116 
$ 122,902 
$ 16,122 
$ 442,034 
$ 437,257 
$ 397,595 
Weighted Average common shares outstanding — basic (in shares)
 
 
 
 
 
 
 
 
111,409 
111,026 
110,626 
Net effect of dilutive securities:
 
 
 
 
 
 
 
 
 
 
 
Contingently issuable performance shares and restricted stock units
 
 
 
 
 
 
 
 
637 
526 
552 
Weighted average common shares outstanding — diluted (in shares)
 
 
 
 
 
 
 
 
112,046 
111,552 
111,178 
Earnings per average common share attributable to common shareholders — basic (in dollars per share)
$ 0.48 
$ 2.36 
$ 1.09 
$ 0.04 
$ 0.37 
$ 2.32 
$ 1.11 
$ 0.15 
$ 3.97 
$ 3.94 
$ 3.59 
Earnings per average common share attributable to common shareholders — diluted (in dollars per share)
$ 0.47 
$ 2.35 
$ 1.08 
$ 0.04 
$ 0.37 
$ 2.30 
$ 1.10 
$ 0.14 
$ 3.95 
$ 3.92 
$ 3.58 
Stock-Based Compensation (Details) (USD $)
3 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 3 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
performance_criteria
non_financial_seperate_performance_metric
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Restricted stock unit awards
Dec. 31, 2015
Restricted stock unit awards
Dec. 31, 2014
Restricted stock unit awards
Dec. 31, 2016
Restricted Stock Units, Stock Grants, and Stock Units
Dec. 31, 2016
Performance Shares
Dec. 31, 2015
Performance Shares
Dec. 31, 2014
Performance Shares
Dec. 31, 2016
Performance Shares
Maximum
Dec. 31, 2016
Performance Shares
Minimum
Dec. 31, 2016
Officers and Key Employees
Restricted stock unit awards
Dec. 31, 2012
Chief Executive Officer
Retention units
Dec. 31, 2016
Non-Officer Board of Director Member
Restricted stock unit awards
Dec. 31, 2016
2012 Plan
Dec. 31, 2016
Accountings Standards Update 2016-09
New Accounting Pronouncement, Early Adoption, Effect
Dec. 31, 2015
Retained Earnings
Dec. 31, 2015
Retained Earnings
Accountings Standards Update 2016-09
New Accounting Pronouncement, Early Adoption, Effect
Dec. 31, 2015
Retained Earnings
Accountings Standards Update 2016-09, Income Tax Expense Component
New Accounting Pronouncement, Early Adoption, Effect
Stock-Based Compensation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares available for grant (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,600,000 
 
 
 
 
Common shares available for issuance (in shares)
2,500,000 
 
 
 
 
 
 
 
2,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock compensation cumulative effect adjustments
 
 
 
 
$ 45,855,000 
 
 
 
 
$ 45,855,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 5,475,000 
$ 6,000,000 
$ 3,000,000 
Operations and maintenance
(208,277,000)
(217,568,000)
(242,279,000)
(243,195,000)
(222,019,000)
(220,449,000)
(210,965,000)
(214,944,000)
(911,319,000)
(868,377,000)
(908,025,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
12,000,000 
 
 
 
Compensation cost that has been charged against income
 
 
 
 
 
 
 
 
19,000,000 
19,000,000 
33,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total income tax benefit recognized
 
 
 
 
 
 
 
 
10,000,000 
7,000,000 
13,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted
13,000,000 
 
 
 
 
 
 
 
13,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected weighted-average period of recognition of unrecognized compensation cost
 
 
 
 
 
 
 
 
2 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total fair value of shares vested
 
 
 
 
 
 
 
 
22,000,000 
21,000,000 
22,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-based liabilities paid
 
 
 
 
 
 
 
 
 
 
 
3,000,000 
10,000,000 
9,000,000 
 
 
16,000,000 
12,000,000 
 
 
 
 
 
 
 
 
 
 
Cash flow effect, cash used to settle awards
 
 
 
 
 
 
 
 
 
 
 
$ 3,000,000 
$ 3,000,000 
$ 3,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
141,811 
166,666 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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, 2016
Dec. 31, 2015
Dec. 31, 2014
Restricted Stock Units, Stock Grants, and Stock Units
 
 
 
Stocks granted and the weighted average fair value
 
 
 
Units granted (in shares)
141,811 
152,651 
179,291 
Grant date fair value (in dollars per share)
$ 67.34 
$ 64.12 
$ 54.89 
Number of granted awards to be settled in cash (in shares)
43,952 
45,104 
49,018 
Performance Shares
 
 
 
Stocks granted and the weighted average fair value
 
 
 
Units granted (in shares)
166,666 
151,430 
166,244 
Grant date fair value (in dollars per share)
$ 66.60 
$ 64.97 
$ 54.86 
Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Restricted Stock Units, Stock Grants, and Stock Units
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
428,287 
 
 
Granted (in shares)
141,811 
 
 
Change in performance factor (in shares)
0 
 
 
Vested (in shares)
(230,881)
 
 
Forfeited (in shares)
(3,958)
 
 
Balance at the end of the period (in shares)
335,259 
428,287 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 56.69 
 
 
Granted (in dollars per share)
$ 67.34 
$ 64.12 
$ 54.89 
Change in performance factor (in dollars per share)
$ 0.00 
 
 
Vested (in dollars per share)
$ 55.07 
 
 
Forfeited (in dollars per share)
$ 62.86 
 
 
Balance at the end of the period (in dollars per share)
$ 62.04 
$ 56.69 
 
Vested Awards Outstanding at December 31, 2016
174,201 
 
 
Vested Awards Outstanding at December 31, 2015 (in shares)
   
 
 
Number of nonvested awards to be settled in cash (in shares)
112,554 
 
 
Performance Shares
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
305,832 
 
 
Granted (in shares)
166,666 
 
 
Change in performance factor (in shares)
15,573 
 
 
Vested (in shares)
(171,303)
 
 
Forfeited (in shares)
(4,044)
 
 
Balance at the end of the period (in shares)
312,724 
305,832 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 58.86 
 
 
Granted (in dollars per share)
$ 66.60 
$ 64.97 
$ 54.86 
Change in performance factor (in dollars per share)
$ 54.09 
 
 
Vested (in dollars per share)
$ 54.09 
 
 
Forfeited (in dollars per share)
$ 62.34 
 
 
Balance at the end of the period (in dollars per share)
$ 65.32 
$ 58.86 
 
Vested Awards Outstanding at December 31, 2016
171,303 
 
 
Vested Awards Outstanding at December 31, 2015 (in shares)
   
 
 
Derivative Accounting (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Designated as Hedging Instruments
Dec. 31, 2015
Designated as Hedging Instruments
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Commodity Contracts
Dec. 31, 2015
Commodity Contracts
Dec. 31, 2016
Commodity Contracts
Designated as Hedging Instruments
Derivative [Line Items]
 
 
 
 
 
 
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change
 
 
100.00% 
 
 
 
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income
 
 
 
 
 
$ (3,000,000)
Derivative liability
2,000,000 
3,000,000 
 
73,074,000 
167,689,000 
 
Additional collateral to counterparties for energy related non-derivative instrument contracts
 
 
 
$ 144,000,000 
 
 
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) (Commodity Contracts)
12 Months Ended
Dec. 31, 2016
MMcf
GWh
Commodity Contracts
 
Outstanding gross notional amount of derivatives
 
Power
1,314 
Gas
194,000 
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Designated as Hedging Instruments
 
 
 
Derivative Instruments in Designated Cash Flows Hedges
 
 
 
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
$ 47,000 
$ (615,000)
$ (372,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)
(3,926,000)
(5,988,000)
(21,415,000)
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
26,482,000 
(108,399,000)
(66,043,000)
Revenue |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
771,000 
574,000 
324,000 
Fuel and purchased power |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
$ 25,711,000 
$ (108,973,000)
$ (66,367,000)
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) (USD $)
Dec. 31, 2016
Dec. 31, 2015
Commodity Contracts
 
 
Assets
 
 
Gross Recognized Derivatives
$ 54,798,000 
$ 53,356,000 
Amounts Offset
(35,103,000)
(26,017,000)
Net Recognized Derivatives
19,695,000 
27,339,000 
Other
0 
672,000 
Amount Reported on Balance Sheet
19,695,000 
28,011,000 
Liabilities
 
 
Gross Recognized Derivatives
(104,123,000)
(207,387,000)
Amounts Offset
35,103,000 
44,077,000 
Net Recognized Derivatives
(69,020,000)
(163,310,000)
Other
(4,054,000)
(4,379,000)
Amount Reported on Balance Sheet
(73,074,000)
(167,689,000)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(49,325,000)
(154,031,000)
Amounts Offset
0 
18,060,000 
Net Recognized Derivatives
(49,325,000)
(135,971,000)
Other
(4,054,000)
(3,707,000)
Amount Reported on Balance Sheet
(53,379,000)
(139,678,000)
Commodity Contracts |
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
48,094,000 
37,396,000 
Amounts Offset
(28,400,000)
(22,163,000)
Net Recognized Derivatives
19,694,000 
15,233,000 
Other
0 
672,000 
Amount Reported on Balance Sheet
19,694,000 
15,905,000 
Commodity Contracts |
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
6,704,000 
15,960,000 
Amounts Offset
(6,703,000)
(3,854,000)
Net Recognized Derivatives
1,000 
12,106,000 
Other
0 
0 
Amount Reported on Balance Sheet
1,000 
12,106,000 
Commodity Contracts |
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(50,182,000)
(113,560,000)
Amounts Offset
28,400,000 
40,223,000 
Net Recognized Derivatives
(21,782,000)
(73,337,000)
Other
(4,054,000)
(4,379,000)
Amount Reported on Balance Sheet
(25,836,000)
(77,716,000)
Commodity Contracts |
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(53,941,000)
(93,827,000)
Amounts Offset
6,703,000 
3,854,000 
Net Recognized Derivatives
(47,238,000)
(89,973,000)
Other
0 
0 
Amount Reported on Balance Sheet
(47,238,000)
(89,973,000)
Designated as Hedging Instruments
 
 
Liabilities
 
 
Amount Reported on Balance Sheet
$ (2,000,000)
$ (3,000,000)
Derivative Accounting - Credit Risk and Related Contingent Features (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Commodity Contracts
 
Credit Risk and Credit-Related Contingent Features
 
Aggregate Fair Value of Derivative Instruments in a Net Liability Position
$ 104,123 
Cash Collateral Posted
0 
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered
$ 23,914 
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Other income:
 
 
 
Interest income
$ 884 
$ 493 
$ 1,010 
Debt return on the purchase of Four Corners units 4 & 5
 
 
8,386 
Miscellaneous
17 
128 
212 
Total other income
901 
621 
9,608 
Other expense:
 
 
 
Non-operating costs
(9,235)
(11,292)
(9,657)
Investment losses — net
(1,747)
(2,080)
(9,426)
Miscellaneous
(4,355)
(4,451)
(2,663)
Total other expense
(15,337)
(17,823)
(21,746)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Other income:
 
 
 
Interest income
261 
163 
689 
Debt return on the purchase of Four Corners units 4 & 5
0 
0 
8,386 
Gain on disposition of property
5,745 
716 
1,197 
Miscellaneous
2,601 
1,955 
1,023 
Total other income
8,607 
2,834 
11,295 
Other expense:
 
 
 
Non-operating costs
(11,034)
(11,648)
(10,397)
Loss on disposition of property
(1,246)
(2,219)
(615)
Miscellaneous
(5,234)
(5,152)
(2,391)
Total other expense
$ (17,514)
$ (19,019)
$ (13,403)
Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)
12 Months Ended 12 Months Ended 0 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2016
Period Through 2023
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Lease
Dec. 31, 2016
Period Through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Lease
Dec. 31, 2016
Period 2017 through 2023
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2016
Period 2024 through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2016
Maximum
Period 2024 through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Jan. 1, 2017
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
19,493,000 
18,933,000 
26,101,000 
19,493,000 
18,933,000 
26,101,000 
 
19,000,000 
19,000,000 
26,000,000 
 
 
 
 
 
 
VIE entity initial loss exposure to noncontrolling interests during lease extension period, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
291,000,000 
VIE entity maximum loss exposure to noncontrolling interests during lease extension period, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 456,000,000 
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, 2016
Dec. 31, 2015
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback, net of accumulated depreciation
$ 113,515 
$ 117,385 
Equity - noncontrolling interests
132,290 
135,540 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback, net of accumulated depreciation
113,515 
117,385 
Equity - noncontrolling interests
132,290 
135,540 
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
113,515 
117,385 
Equity - noncontrolling interests
$ 132,290 
$ 135,540 
Nuclear Decommissioning Trusts (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
$ 779,586 
$ 735,196 
 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
Proceeds from the sale of securities
633,410 
478,813 
356,195 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
779,586 
735,196 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
779,586 
735,196 
 
Unrealized Gains
197,911 
169,053 
 
Unrealized Losses
(4,962)
(2,760)
 
Net receivables for securities purchases
795 
 
 
Net payables for securities purchases
 
(335)
 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
Realized gains
11,213 
5,189 
4,725 
Realized losses
(10,106)
(6,225)
(4,525)
Proceeds from the sale of securities
633,410 
478,813 
356,195 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
779,586 
735,196 
 
ARIZONA PUBLIC SERVICE COMPANY |
Equity Securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
353,261 
314,957 
 
Unrealized Gains
188,091 
157,098 
 
Unrealized Losses
0 
(115)
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
353,261 
314,957 
 
ARIZONA PUBLIC SERVICE COMPANY |
Fixed income securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
425,530 
420,574 
 
Unrealized Gains
9,820 
11,955 
 
Unrealized Losses
(4,962)
(2,645)
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Less than one year
13,063 
 
 
1 year - 5 years
119,292 
 
 
5 years - 10 years
105,612 
 
 
Greater than 10 years
187,563 
 
 
Total
$ 425,530 
$ 420,574 
 
Changes in Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
$ 4,719,457 
$ 4,519,102 
$ 4,340,460 
Total other comprehensive income
926 
23,393 
9,912 
Ending balance
4,935,912 
4,719,457 
4,519,102 
Derivative Instruments
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
(538)
(957)
 
Amounts reclassified from accumulated other comprehensive loss
2,941 
4,187 
 
Total other comprehensive income
2,403 
3,230 
 
Pension and Other Postretirement Benefits
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
(4,509)
16,980 
 
Amounts reclassified from accumulated other comprehensive loss
3,032 
3,183 
 
Total other comprehensive income
(1,477)
20,163 
 
AOCI Including Portion Attributable to Noncontrolling Interest
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Ending balance
(43,822)
(44,748)
(68,141)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Beginning balance
4,814,794 
4,629,852 
4,454,874 
Total other comprehensive income
1,674 
21,236 
5,039 
Ending balance
5,037,970 
4,814,794 
4,629,852 
ARIZONA PUBLIC SERVICE COMPANY |
Derivative Instruments
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
Ending balance
(25,423)
(27,097)
(48,333)
ARIZONA PUBLIC SERVICE COMPANY |
Pension and Other Postretirement Benefits
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
(538)
(957)
 
Amounts reclassified from accumulated other comprehensive loss
2,941 
4,187 
 
Total other comprehensive income
2,403 
3,230 
 
ARIZONA PUBLIC SERVICE COMPANY |
AOCI Including Portion Attributable to Noncontrolling Interest
 
 
 
Changes in accumulated other comprehensive income (loss) by component
 
 
 
OCI (loss) before reclassifications
(3,821)
14,726 
 
Amounts reclassified from accumulated other comprehensive loss
3,092 
3,280 
 
Total other comprehensive income
$ (729)
$ 18,006 
 
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, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 739,199 
$ 1,166,922 
$ 915,394 
$ 677,167 
$ 734,430 
$ 1,199,146 
$ 890,648 
$ 671,219 
$ 3,498,682 
$ 3,495,443 
$ 3,491,632 
Operating expenses
 
 
 
 
 
 
 
 
2,642,698 
2,640,841 
2,680,390 
OPERATING INCOME
122,816 
451,258 
231,748 
50,162 
109,834 
445,111 
231,973 
67,684 
855,984 
854,602 
811,242 
Other
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
27,704 
18,013 
18,652 
Interest expense
 
 
 
 
 
 
 
 
205,720 
194,964 
200,950 
Income tax benefit
27,309 
141,446 
65,742 
1,914 
22,847 
139,555 
67,371 
7,947 
236,411 
237,720 
220,705 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
53,246 
263,027 
121,308 
4,453 
41,117 
257,116 
122,902 
16,122 
442,034 
437,257 
397,595 
Other comprehensive income
 
 
 
 
 
 
 
 
926 
23,393 
9,912 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
442,960 
460,650 
407,507 
Pinnacle West
 
 
 
 
 
 
 
 
 
 
 
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
370 
550 
642 
Operating expenses
 
 
 
 
 
 
 
 
26,424 
12,733 
23,507 
OPERATING INCOME
 
 
 
 
 
 
 
 
(26,054)
(12,183)
(22,865)
Other
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
 
 
 
 
 
 
 
 
462,027 
446,508 
411,528 
Other expense
 
 
 
 
 
 
 
 
(1,771)
(3,302)
(3,276)
Total
 
 
 
 
 
 
 
 
460,256 
443,206 
408,252 
Interest expense
 
 
 
 
 
 
 
 
3,151 
2,672 
3,663 
INCOME BEFORE INCOME TAXES
 
 
 
 
 
 
 
 
431,051 
428,351 
381,724 
Income tax benefit
 
 
 
 
 
 
 
 
(10,983)
(8,906)
(15,871)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
442,034 
437,257 
397,595 
Other comprehensive income
 
 
 
 
 
 
 
 
926 
23,393 
9,912 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
$ 442,960 
$ 460,650 
$ 407,507 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Current assets
 
 
 
 
Cash and cash equivalents
$ 8,881 
$ 39,488 
$ 7,604 
$ 9,526 
Accounts receivable
250,491 
274,691 
 
 
Income tax receivable
3,751 
589 
 
 
Other current assets
45,028 
37,242 
 
 
Total current assets
822,219 
890,516 
 
 
Investments and other assets
 
 
 
 
Other assets
69,063 
52,518 
 
 
Total investments and other assets
848,650 
799,820 
 
 
Total Assets
16,004,253 
15,028,258 
 
 
Current liabilities
 
 
 
 
Accounts payable
264,631 
297,480 
 
 
Accrued taxes
138,964 
138,600 
 
 
Common dividends payable
72,926 
69,363 
 
 
Short-term borrowings
177,200 
0 
 
 
Current maturities of long-term debt
125,000 
357,580 
 
 
Other current liabilities
244,000 
197,861 
 
 
Total current liabilities
1,292,946 
1,442,317 
 
 
Deferred credits and other
 
 
 
 
Long-term debt less current maturities
4,021,785 
3,462,391 
 
 
Other
156,784 
186,345 
 
 
Total deferred credits and other
5,753,610 
5,404,093 
 
 
Common stock equity
 
 
 
 
Common stock
2,596,030 
2,541,668 
 
 
Accumulated other comprehensive loss
(43,822)
(44,748)
 
 
Retained earnings
2,255,547 
2,092,803 
 
 
Total shareholders’ equity
4,803,622 
4,583,917 
 
 
Noncontrolling interests
132,290 
135,540 
 
 
Total equity
4,935,912 
4,719,457 
4,519,102 
4,340,460 
Total Liabilities and Equity
16,004,253 
15,028,258 
 
 
Pinnacle West
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
41 
17,432 
3,088 
5,798 
Accounts receivable
81,751 
93,093 
 
 
Income tax receivable
0 
14,895 
 
 
Other current assets
340 
197 
 
 
Total current assets
82,132 
125,617 
 
 
Investments and other assets
 
 
 
 
Investments in subsidiaries
5,084,035 
4,815,236 
 
 
Deferred income taxes
53,805 
41,065 
 
 
Other assets
38,500 
43,422 
 
 
Total investments and other assets
5,176,340 
4,899,723 
 
 
Total Assets
5,258,472 
5,025,340 
 
 
Current liabilities
 
 
 
 
Accounts payable
5,421 
5,901 
 
 
Accrued taxes
12,050 
6,904 
 
 
Common dividends payable
72,926 
69,363 
 
 
Short-term borrowings
41,700 
0 
 
 
Current maturities of long-term debt
125,000 
0 
 
 
Other current liabilities
31,182 
33,120 
 
 
Total current liabilities
288,279 
115,288 
 
 
Deferred credits and other
 
 
 
 
Long-term debt less current maturities
0 
125,000 
 
 
Pension liabilities
21,057 
21,933 
 
 
Other
13,224 
43,662 
 
 
Total deferred credits and other
34,281 
65,595 
 
 
Common stock equity
 
 
 
 
Common stock
2,591,897 
2,535,862 
 
 
Accumulated other comprehensive loss
(43,822)
(44,748)
 
 
Retained earnings
2,255,547 
2,092,803 
 
 
Total shareholders’ equity
4,803,622 
4,583,917 
 
 
Noncontrolling interests
132,290 
135,540 
 
 
Total equity
4,935,912 
4,719,457 
 
 
Total Liabilities and Equity
$ 5,258,472 
$ 5,025,340 
 
 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Statements of Cash Flows (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Cash Flows from Operating Activities
 
 
 
Net income
$ 461,527 
$ 456,190 
$ 423,696 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
565,011 
571,664 
496,487 
Deferred income taxes
206,870 
236,819 
159,023 
Accounts receivable
(2,489)
(22,219)
(52,672)
Accounts payable
(66,917)
(34,266)
(353)
Net cash flow provided by operating activities
1,023,390 
1,094,327 
1,099,627 
Cash flows from investing activities
 
 
 
Net cash flow used for investing activities
(1,252,078)
(1,066,233)
(922,668)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
693,151 
842,415 
731,126 
Short-term debt borrowings under revolving credit facility
40,000 
0 
0 
Dividends paid on common stock
(274,229)
(260,027)
(246,671)
Repayment of long-term debt
(370,430)
(415,570)
(652,578)
Common stock equity issuance and purchases - net
(4,867)
19,373 
15,288 
Other
0 
1 
161 
Net cash flow provided by (used for) financing activities
198,081 
3,790 
(178,881)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(30,607)
31,884 
(1,922)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
39,488 
7,604 
9,526 
CASH AND CASH EQUIVALENTS AT END OF YEAR
8,881 
39,488 
7,604 
Pinnacle West
 
 
 
Cash Flows from Operating Activities
 
 
 
Net income
442,034 
437,257 
397,595 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Equity in earnings of subsidiaries - net
(462,027)
(446,508)
(411,528)
Depreciation and amortization
85 
92 
94 
Deferred income taxes
(12,402)
12,967 
4,406 
Accounts receivable
15,823 
11,336 
(22,945)
Accounts payable
10,402 
637 
2,017 
Accrued taxes and income tax receivable - net
20,041 
(12,882)
(1,795)
Dividends received from subsidiaries
239,300 
266,900 
253,600 
Other
5,514 
(6,995)
18,432 
Net cash flow provided by operating activities
258,770 
262,804 
239,876 
Cash flows from investing activities
 
 
 
Construction work in progress
(18,457)
(3,462)
0 
Investments in subsidiaries
(19,242)
(3,491)
(10,236)
Repayments of loans from subsidiaries
1,026 
157 
322 
Advances of loans to subsidiaries
(2,092)
(1,010)
(1,450)
Net cash flow used for investing activities
(38,765)
(7,806)
(11,364)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
0 
0 
125,000 
Short-term debt borrowings under revolving credit facility
40,000 
0 
0 
Commercial Paper - net
1,700 
0 
0 
Dividends paid on common stock
(274,229)
(260,027)
(246,671)
Repayment of long-term debt
0 
0 
(125,000)
Common stock equity issuance and purchases - net
(4,867)
19,373 
15,288 
Other
0 
0 
161 
Net cash flow provided by (used for) financing activities
(237,396)
(240,654)
(231,222)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(17,391)
14,344 
(2,710)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
17,432 
3,088 
5,798 
CASH AND CASH EQUIVALENTS AT END OF YEAR
$ 41 
$ 17,432 
$ 3,088 
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) (Reserve for uncollectibles., USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
$ 3,125 
$ 3,094 
$ 3,203 
Additions, Charged to cost and expenses
4,025 
4,073 
3,942 
Additions, Charged to other accounts
0 
0 
0 
Deductions
4,113 
4,042 
4,051 
Balance at end of period
3,037 
3,125 
3,094 
Pinnacle West
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
3,125 
3,094 
3,203 
Additions, Charged to cost and expenses
4,025 
4,073 
3,942 
Additions, Charged to other accounts
0 
0 
0 
Deductions
4,113 
4,042 
4,051 
Balance at end of period
$ 3,037 
$ 3,125 
$ 3,094