PINNACLE WEST CAPITAL CORP, 10-K filed on 2/23/2018
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2017
Feb. 16, 2018
Jun. 30, 2017
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, 2017 
 
 
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
 
 
$ 9,461,736,502 
Entity Common Stock, Shares Outstanding
 
111,799,789 
 
Document Fiscal Year Focus
2017 
 
 
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, 2017 
 
 
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
2017 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
OPERATING REVENUES
$ 3,565,296 
$ 3,498,682 
$ 3,495,443 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
981,301 
1,075,510 
1,101,298 
Operations and maintenance
924,443 
911,319 
868,377 
Depreciation and amortization
534,118 
485,829 
494,422 
Taxes other than income taxes
184,347 
166,499 
171,812 
Other expenses
6,660 
3,541 
4,932 
Total
2,630,869 
2,642,698 
2,640,841 
OPERATING INCOME
934,427 
855,984 
854,602 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
47,011 
42,140 
35,215 
Other income (Note 17)
4,006 
901 
621 
Other expense (Note 17)
(21,539)
(15,337)
(17,823)
Total
29,478 
27,704 
18,013 
INTEREST EXPENSE
 
 
 
Interest charges
219,796 
205,720 
194,964 
Allowance for borrowed funds used during construction (Note 1)
(22,112)
(19,970)
(16,259)
Total
197,684 
185,750 
178,705 
INCOME BEFORE INCOME TAXES
766,221 
697,938 
693,910 
INCOME TAXES (Note 4)
258,272 
236,411 
237,720 
NET INCOME
507,949 
461,527 
456,190 
Less: Net income attributable to noncontrolling interests (Note 18)
19,493 
19,493 
18,933 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
488,456 
442,034 
437,257 
Weighted Average common shares outstanding — basic (in shares)
111,839 
111,409 
111,026 
Weighted Average common shares outstanding — diluted (in shares)
112,367 
112,046 
111,552 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 4.37 
$ 3.97 
$ 3.94 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 4.35 
$ 3.95 
$ 3.92 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
ELECTRIC OPERATING REVENUES
3,554,139 
3,489,754 
3,492,357 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
992,744 
1,082,625 
1,101,298 
Operations and maintenance
891,129 
879,108 
853,135 
Depreciation and amortization
532,423 
484,909 
494,298 
Taxes other than income taxes
182,979 
165,779 
171,499 
Income taxes (Note 4)
275,295 
259,353 
260,143 
Total
2,874,570 
2,871,774 
2,880,373 
OPERATING INCOME
679,569 
617,980 
611,984 
OTHER INCOME (DEDUCTIONS)
 
 
 
Income taxes (Note 4)
6,127 
13,511 
14,302 
Allowance for equity funds used during construction (Note 1)
47,011 
42,140 
35,215 
Other income (Note 17)
6,526 
8,607 
2,834 
Other expense (Note 17)
(23,380)
(17,514)
(19,019)
Total
36,284 
46,744 
33,332 
INTEREST EXPENSE
 
 
 
Interest on long-term debt
200,211 
189,828 
180,123 
Interest on short-term borrowings
9,119 
7,983 
7,376 
Debt discount, premium and expense
4,833 
4,760 
4,793 
Allowance for borrowed funds used during construction (Note 1)
(22,112)
(19,481)
(16,183)
Total
192,051 
183,090 
176,109 
INCOME TAXES (Note 4)
269,168 
245,842 
245,841 
NET INCOME
523,802 
481,634 
469,207 
Less: Net income attributable to noncontrolling interests (Note 18)
19,493 
19,493 
18,933 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 504,309 
$ 462,141 
$ 450,274 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
NET INCOME
$ 507,949 
$ 461,527 
$ 456,190 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(35)
(538)
(957)
Reclassification of net realized loss, net of tax benefit
2,225 
2,941 
4,187 
Pension and other postretirement benefits activity, net of tax (expense) benefit
(3,370)
(1,477)
20,163 
Total other comprehensive income (loss)
(1,180)
926 
23,393 
COMPREHENSIVE INCOME
506,769 
462,453 
479,583 
Less: Comprehensive income attributable to noncontrolling interests
19,493 
19,493 
18,933 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
487,276 
442,960 
460,650 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
NET INCOME
523,802 
481,634 
469,207 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(35)
(538)
(957)
Reclassification of net realized loss, net of tax benefit
2,225 
2,941 
4,187 
Pension and other postretirement benefits activity, net of tax (expense) benefit
(3,750)
(729)
18,006 
Total other comprehensive income (loss)
(1,560)
1,674 
21,236 
COMPREHENSIVE INCOME
522,242 
483,308 
490,443 
Less: Comprehensive income attributable to noncontrolling interests
19,493 
19,493 
18,933 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 502,749 
$ 463,815 
$ 471,510 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Net unrealized loss, tax (expense)
$ 24 
$ (585)
$ (342)
Reclassification of net realized loss, tax benefit
1,294 
985 
1,801 
Pension and other postretirement benefits activity, tax benefit (expense)
693 
633 
(13,302)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net unrealized loss, tax (expense)
24 
(585)
(342)
Reclassification of net realized loss, tax benefit
1,294 
985 
1,801 
Pension and other postretirement benefits activity, tax benefit (expense)
$ 977 
$ 293 
$ (11,776)
CONSOLIDATED BALANCE SHEETS (USD $)
Dec. 31, 2017
Dec. 31, 2016
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 13,892,000 
$ 8,881,000 
Customer and other receivables
305,147,000 
250,491,000 
Accrued unbilled revenues
112,434,000 
107,949,000 
Allowance for doubtful accounts
(2,513,000)
(3,037,000)
Materials and supplies (at average cost)
264,012,000 
253,979,000 
Fossil fuel (at average cost)
25,258,000 
28,608,000 
Income tax receivable (Note 4)
0 
3,751,000 
Assets from risk management activities (Note 16)
1,931,000 
19,694,000 
Deferred fuel and purchased power regulatory asset (Note 3)
75,637,000 
12,465,000 
Other regulatory assets (Note 3)
172,451,000 
94,410,000 
Other current assets
48,039,000 
45,028,000 
Total current assets
1,016,288,000 
822,219,000 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
51,000 
1,000 
Nuclear decommissioning trust (Notes 13 and 19)
871,000,000 
779,586,000 
Other assets
84,531,000 
69,063,000 
Total investments and other assets
955,582,000 
848,650,000 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
17,798,061,000 
17,341,888,000 
Accumulated depreciation and amortization
(6,128,535,000)
(5,970,100,000)
Net
11,669,526,000 
11,371,788,000 
Construction work in progress
1,291,498,000 
1,019,947,000 
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)
109,645,000 
113,515,000 
Intangible assets, net of accumulated amortization of $582,272 and $603,637
257,189,000 
90,022,000 
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202
117,408,000 
119,004,000 
Total property, plant and equipment
13,445,266,000 
12,714,276,000 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,202,302,000 
1,313,428,000 
Assets for other postretirement benefits (Note 7)
268,978,000 
166,206,000 
Other
130,666,000 
139,474,000 
Total deferred debits
1,601,946,000 
1,619,108,000 
Total Assets
17,019,082,000 
16,004,253,000 
CURRENT LIABILITIES
 
 
Accounts payable
256,442,000 
264,631,000 
Accrued taxes (Note 4)
148,946,000 
138,964,000 
Accrued interest
56,397,000 
52,835,000 
Common dividends payable
77,667,000 
72,926,000 
Short-term borrowings (Note 5)
95,400,000 
177,200,000 
Current maturities of long-term debt (Note 6)
82,000,000 
125,000,000 
Customer deposits
70,388,000 
82,520,000 
Liabilities from risk management activities (Note 16)
59,252,000 
25,836,000 
Liabilities for asset retirements (Note 11)
4,745,000 
9,135,000 
Regulatory liabilities (Note 3)
100,086,000 
99,899,000 
Other current liabilities
246,529,000 
244,000,000 
Total current liabilities
1,197,852,000 
1,292,946,000 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
4,789,713,000 
4,021,785,000 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes (Note 4)
1,690,805,000 
2,945,232,000 
Regulatory liabilities (Notes 1, 3, 4 and 7)
2,452,536,000 
948,916,000 
Liabilities for asset retirements (Note 11)
674,784,000 
615,340,000 
Liabilities for pension benefits (Note 7)
327,300,000 
509,310,000 
Liabilities from risk management activities (Note 16)
37,170,000 
47,238,000 
Customer advances
113,996,000 
88,672,000 
Coal mine reclamation
231,597,000 
221,910,000 
Deferred investment tax credit
205,575,000 
210,162,000 
Unrecognized tax benefits (Note 4)
13,115,000 
10,046,000 
Other
148,909,000 
156,784,000 
Total deferred credits and other
5,895,787,000 
5,753,610,000 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,816,170 and 111,392,053 issued at respective dates
2,614,805,000 
2,596,030,000 
Treasury stock at cost; 64,463 shares at end of 2017 and 55,317 shares at end of 2016
(5,624,000)
(4,133,000)
Total common stock
2,609,181,000 
2,591,897,000 
Retained earnings
2,442,511,000 
2,255,547,000 
Accumulated other comprehensive loss
(45,002,000)
(43,822,000)
Total shareholders’ equity
5,006,690,000 
4,803,622,000 
Noncontrolling interests (Note 18)
129,040,000 
132,290,000 
Total equity
5,135,730,000 
4,935,912,000 
Total Liabilities and Equity
17,019,082,000 
16,004,253,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
13,851,000 
8,840,000 
Customer and other receivables
292,791,000 
262,611,000 
Accrued unbilled revenues
112,434,000 
107,949,000 
Allowance for doubtful accounts
(2,513,000)
(3,037,000)
Materials and supplies (at average cost)
262,630,000 
252,777,000 
Fossil fuel (at average cost)
25,258,000 
28,608,000 
Income tax receivable (Note 4)
0 
11,174,000 
Assets from risk management activities (Note 16)
1,931,000 
19,694,000 
Deferred fuel and purchased power regulatory asset (Note 3)
75,637,000 
12,465,000 
Other regulatory assets (Note 3)
172,451,000 
94,410,000 
Other current assets
41,055,000 
41,849,000 
Total current assets
995,525,000 
837,340,000 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
51,000 
1,000 
Nuclear decommissioning trust (Notes 13 and 19)
871,000,000 
779,586,000 
Other assets
67,103,000 
48,320,000 
Total investments and other assets
938,154,000 
827,907,000 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
17,654,078,000 
17,228,787,000 
Accumulated depreciation and amortization
(6,041,965,000)
(5,881,941,000)
Net
11,612,113,000 
11,346,846,000 
Construction work in progress
1,266,636,000 
989,497,000 
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)
109,645,000 
113,515,000 
Intangible assets, net of accumulated amortization of $582,272 and $603,637
257,028,000 
89,868,000 
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202
117,408,000 
119,004,000 
Total property, plant and equipment
13,362,830,000 
12,658,730,000 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,202,302,000 
1,313,428,000 
Assets for other postretirement benefits (Note 7)
265,139,000 
162,911,000 
Other
129,801,000 
130,859,000 
Total deferred debits
1,597,242,000 
1,607,198,000 
Total Assets
16,893,751,000 
15,931,175,000 
CURRENT LIABILITIES
 
 
Accounts payable
247,852,000 
259,161,000 
Accrued taxes (Note 4)
157,349,000 
130,576,000 
Accrued interest
55,533,000 
52,525,000 
Common dividends payable
77,700,000 
72,900,000 
Short-term borrowings (Note 5)
0 
135,500,000 
Current maturities of long-term debt (Note 6)
82,000,000 
0 
Customer deposits
70,388,000 
82,520,000 
Liabilities from risk management activities (Note 16)
59,252,000 
25,836,000 
Liabilities for asset retirements (Note 11)
4,192,000 
8,703,000 
Regulatory liabilities (Note 3)
100,086,000 
99,899,000 
Other current liabilities
243,922,000 
226,417,000 
Total current liabilities
1,098,274,000 
1,094,037,000 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes (Note 4)
1,742,485,000 
2,999,295,000 
Regulatory liabilities (Notes 1, 3, 4 and 7)
2,452,536,000 
948,916,000 
Liabilities for asset retirements (Note 11)
666,527,000 
607,234,000 
Liabilities for pension benefits (Note 7)
306,542,000 
488,253,000 
Liabilities from risk management activities (Note 16)
37,170,000 
47,238,000 
Customer advances
113,996,000 
88,672,000 
Coal mine reclamation
215,830,000 
206,645,000 
Deferred investment tax credit
205,575,000 
210,162,000 
Unrecognized tax benefits (Note 4)
43,876,000 
37,408,000 
Other
133,779,000 
143,560,000 
Total deferred credits and other
5,918,316,000 
5,777,383,000 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Total common stock
178,162,000 
178,162,000 
Additional paid-in capital
2,571,696,000 
2,421,696,000 
Retained earnings
2,533,954,000 
2,331,245,000 
Accumulated other comprehensive loss
(26,983,000)
(25,423,000)
Total shareholders’ equity
5,256,829,000 
4,905,680,000 
Noncontrolling interests (Note 18)
129,040,000 
132,290,000 
Total equity
5,385,869,000 
5,037,970,000 
Long-term debt less current maturities (Note 6)
4,491,292,000 
4,021,785,000 
Total capitalization
9,877,161,000 
9,059,755,000 
Total Liabilities and Equity
$ 16,893,751,000 
$ 15,931,175,000 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 241,405 
$ 237,535 
Accumulated amortization on intangible assets
582,272 
603,637 
Accumulated amortization on nuclear fuel
144,070 
147,202 
EQUITY
 
 
Common stock, par value
$ 0 
$ 0 
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
111,816,170 
111,392,053 
Treasury stock at cost, shares
64,463 
55,317 
ARIZONA PUBLIC SERVICE COMPANY
 
 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
241,405 
237,535 
Accumulated amortization on intangible assets
581,135 
603,637 
Accumulated amortization on nuclear fuel
$ 144,070 
$ 147,202 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$ 507,949 
$ 461,527 
$ 456,190 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
610,629 
565,011 
571,664 
Deferred fuel and purchased power
(48,405)
(60,303)
14,997 
Deferred fuel and purchased power amortization
(14,767)
38,152 
1,617 
Allowance for equity funds used during construction
(47,011)
(42,140)
(35,215)
Deferred income taxes
248,164 
206,870 
236,819 
Deferred investment tax credit
(4,587)
23,082 
8,473 
Change in derivative instruments fair value
(373)
(403)
(381)
Stock compensation
20,502 
18,883 
18,756 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(93,797)
(2,489)
(22,219)
Accrued unbilled revenues
(4,485)
(11,709)
4,293 
Materials, supplies and fossil fuel
(6,683)
(1,491)
(23,945)
Income tax receivable
3,751 
(3,162)
2,509 
Other current assets
(10,580)
(23,324)
3,145 
Accounts payable
(23,769)
(66,917)
(34,266)
Accrued taxes
9,982 
447 
(2,013)
Other current liabilities
19,154 
29,594 
603 
Change in margin and collateral accounts — assets
(300)
673 
(324)
Change in margin and collateral accounts — liabilities
(533)
17,735 
22,776 
Change in unrecognized tax benefits
5,891 
1,628 
(10,328)
Change in long-term regulatory liabilities
45,764 
14,682 
(20,535)
Change in other long-term assets
(68,480)
(60,163)
2,426 
Change in other long-term liabilities
(29,980)
(82,793)
(100,715)
Net cash flow provided by operating activities
1,118,036 
1,023,390 
1,094,327 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,408,774)
(1,275,472)
(1,076,087)
Contributions in aid of construction
23,708 
64,296 
46,546 
Allowance for borrowed funds used during construction
(22,112)
(19,970)
(16,259)
Proceeds from nuclear decommissioning trust sales
542,246 
633,410 
478,813 
Investment in nuclear decommissioning trust
(544,527)
(635,691)
(496,062)
Other
(19,078)
(18,651)
(3,184)
Net cash flow used for investing activities
(1,428,537)
(1,252,078)
(1,066,233)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
848,239 
693,151 
842,415 
Repayment of long-term debt
(125,000)
(370,430)
(415,570)
Short-term borrowings and (repayments) — net
(107,800)
137,200 
(147,400)
Short-term debt borrowings under revolving credit facility
58,000 
40,000 
0 
Short-term debt repayments under revolving credit facility
(32,000)
0 
0 
Dividends paid on common stock
(289,793)
(274,229)
(260,027)
Common stock equity issuance and purchases - net
(13,390)
(4,867)
19,373 
Distributions to noncontrolling interests
(22,744)
(22,744)
(35,002)
Other
0 
0 
1 
Net cash flow provided by financing activities
315,512 
198,081 
3,790 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
5,011 
(30,607)
31,884 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
8,881 
39,488 
7,604 
CASH AND CASH EQUIVALENTS AT END OF YEAR
13,892 
8,881 
39,488 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
2,186 
9,956 
6,550 
Interest, net of amounts capitalized
189,288 
184,462 
170,209 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
130,404 
114,855 
83,798 
Dividends declared but not paid
77,667 
72,926 
69,363 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
523,802 
481,634 
469,207 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
608,935 
564,091 
571,540 
Deferred fuel and purchased power
(48,405)
(60,303)
14,997 
Deferred fuel and purchased power amortization
(14,767)
38,152 
1,617 
Allowance for equity funds used during construction
(47,011)
(42,140)
(35,215)
Deferred income taxes
249,465 
221,167 
223,069 
Deferred investment tax credit
(4,587)
23,082 
8,473 
Change in derivative instruments fair value
(373)
(403)
(381)
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(68,040)
(1,601)
(21,040)
Accrued unbilled revenues
(4,485)
(11,709)
4,293 
Materials, supplies and fossil fuel
(6,503)
(1,454)
(23,945)
Income tax receivable
11,174 
(14,567)
0 
Other current assets
(6,775)
(21,640)
4,498 
Accounts payable
(26,561)
(67,543)
(34,891)
Accrued taxes
26,773 
(13,912)
13,378 
Other current liabilities
27,912 
5,097 
(3,718)
Change in margin and collateral accounts — assets
(300)
673 
(324)
Change in margin and collateral accounts — liabilities
(533)
17,735 
22,776 
Change in unrecognized tax benefits
5,891 
1,628 
(10,328)
Change in long-term regulatory liabilities
45,764 
14,682 
(20,535)
Change in other long-term assets
(78,540)
(45,866)
(813)
Change in other long-term liabilities
(31,106)
(76,855)
(82,628)
Net cash flow provided by operating activities
1,161,730 
1,009,948 
1,100,030 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,381,930)
(1,248,010)
(1,072,053)
Contributions in aid of construction
23,708 
64,296 
46,546 
Allowance for borrowed funds used during construction
(22,112)
(19,481)
(16,183)
Proceeds from nuclear decommissioning trust sales
542,246 
633,410 
478,813 
Investment in nuclear decommissioning trust
(544,527)
(635,691)
(496,062)
Other
(18,538)
(13,865)
(1,093)
Net cash flow used for investing activities
(1,401,153)
(1,219,341)
(1,060,032)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
549,478 
693,151 
842,415 
Repayment of long-term debt
0 
(370,430)
(415,570)
Short-term borrowings and (repayments) — net
(135,500)
135,500 
(147,400)
Dividends paid on common stock
(296,800)
(281,300)
(266,900)
Equity infusion from Pinnacle West
150,000 
42,000 
0 
Distributions to noncontrolling interests
(22,744)
(22,744)
(35,002)
Net cash flow provided by financing activities
244,434 
196,177 
(22,457)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
5,011 
(13,216)
17,541 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
8,840 
22,056 
4,515 
CASH AND CASH EQUIVALENTS AT END OF YEAR
13,851 
8,840 
22,056 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
(14,098)
26,864 
14,831 
Interest, net of amounts capitalized
184,210 
181,809 
167,670 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
130,057 
114,874 
83,798 
Dividends declared but not paid
$ 77,700 
$ 72,900 
$ 69,400 
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, 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 
Beginning 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 
 
 
 
 
 
 
 
 
 
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 
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)
 
 
Other
 
 
 
 
 
 
0 
 
 
0 
 
 
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 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
187,818 
 
 
 
 
 
 
 
 
 
Equity infusion from Pinnacle West
 
 
 
 
 
 
42,000 
 
42,000 
 
 
 
Stock compensation cumulative effect adjustments
45,855 
40,380 
 
5,475 
 
 
5,411 
 
 
5,411 
 
 
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 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
507,949 
 
 
488,456 
 
19,493 
523,802 
 
 
504,309 
 
19,493 
Other comprehensive income
(1,180)
 
 
 
(1,180)
 
(1,560)
 
 
 
(1,560)
 
Dividends on common stock
(301,492)
 
 
(301,492)
 
 
(301,600)
 
 
(301,600)
 
 
Issuance of common stock
18,775 
18,775 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
424,117 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(17,755)
 
(17,755)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(216,911)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
16,264 
 
16,264 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
207,765 
 
 
 
 
 
 
 
 
 
Equity infusion from Pinnacle West
 
 
 
 
 
 
150,000 
 
150,000 
 
 
 
Net capital activities by noncontrolling interests
(22,743)
 
 
 
 
(22,743)
(22,743)
 
 
 
 
(22,743)
Ending balance at Dec. 31, 2017
$ 5,135,730 
$ 2,614,805 
$ (5,624)
$ 2,442,511 
$ (45,002)
$ 129,040 
$ 5,385,869 
$ 178,162 
$ 2,571,696 
$ 2,533,954 
$ (26,983)
$ 129,040 
Ending Balance (in shares) at Dec. 31, 2017
111,816,170 
111,816,170 
64,463 
 
 
 
 
71,264,947 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.70 
$ 2.56 
$ 2.44 
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 a more condensed form on the Consolidated Balance Sheets than in the prior year. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on accumulated other comprehensive loss. The following tables show the impacts of the reclassifications of the prior year (previously reported) amounts (dollars in thousands):

Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current year
presentation
Accumulated other comprehensive loss:
 
 
 
 
 
Pension and other postretirement benefits
$
(39,070
)
 
$
39,070

 
$
—

Derivative instruments
(4,752
)
 
4,752

 
—

Total accumulated other comprehensive loss
(43,822
)
 
43,822

 
—

Accumulated other comprehensive loss
—

 
(43,822
)
 
(43,822
)

Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current year
presentation
Accumulated other comprehensive loss:
 
 
 
 
 
Pension and other postretirement benefits
$
(20,671
)
 
$
20,671

 
$
—

Derivative instruments
(4,752
)
 
4,752

 
—

Total accumulated other comprehensive loss
(25,423
)
 
25,423

 
—

Accumulated other comprehensive loss
—

 
(25,423
)
 
(25,423
)

 
Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

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 amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to 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, 2017 and 2016 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2017
 
2016
Generation
$
7,963,998

 
$
7,874,898

Transmission
2,836,578

 
2,746,508

Distribution
6,025,856

 
5,738,801

General plant
971,629

 
981,681

Plant in service and held for future use
17,798,061

 
17,341,888

Accumulated depreciation and amortization
(6,128,535
)
 
(5,970,100
)
Net
11,669,526

 
11,371,788

Construction work in progress
1,291,498

 
1,019,947

Palo Verde sale leaseback, net of accumulated depreciation
109,645

 
113,515

Intangible assets, net of accumulated amortization
257,189

 
90,022

Nuclear fuel, net of accumulated amortization
117,408

 
119,004

Total property, plant and equipment
$
13,445,266

 
$
12,714,276



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 and amortization 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, 2017 were as follows:
 
•Fossil plant — 21 years;
•Nuclear plant — 26 years;
•Other generation — 25 years;
•Transmission — 38 years;
•Distribution — 33 years; and
•General plant — 6 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $453 million in 2017, $422 million in 2016, and $430 million in 2015. For the years 2015 through 2017, the depreciation rates ranged from a low of 0.18% to a high of 16.44%.  The weighted-average depreciation rate was 2.80% in 2017, 2.66% in 2016, and 2.74% in 2015.

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.

See Note 11 for further information on Asset Retirement Obligations.

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 6.68% for 2017, 7.17% for 2016, and 8.02% for 2015.  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, coal reclamation escrow accounts, 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 reduced the fee to zero.  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 2019. 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 and are based on currently enacted tax rates.  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,
 
2017
 
2016
 
2015
Cash paid during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
2,186

 
$
9,956

 
$
6,550

Interest, net of amounts capitalized
189,288

 
184,462

 
170,209

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
130,404

 
$
114,855

 
$
83,798

Dividends declared but not paid
77,667

 
72,926

 
69,363


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 $72 million in 2017, $58 million in 2016, and $58 million in 2015.  Estimated amortization expense on existing intangible assets over the next five years is $53 million in 2018, $38 million in 2019, $28 million in 2020, $22 million in 2021, and $17 million in 2022.  At December 31, 2017, the weighted-average remaining amortization period for intangible assets was 6 years.
 
Investments
 
El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for 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, and coal reclamation escrow, 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.

See Note 2 for new accounting guidance relating to financial instruments including investments in equity securities, effective for us in 2018.  

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, 2017, 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 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, became 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 adopted this standard on January 1, 2018 using the modified retrospective transition approach. The adoption of this standard will not have significant impact on our financial statement results. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment the adoption of this guidance does not generally impact the timing of our revenue recognition relating to these customers. The adoption of the new standard will result in expanded revenue related disclosures.

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 became effective for us on January 1, 2018. Certain aspects of the standard require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We adopted this standard on a prospective basis on January 1, 2018. The adoption of this standard will not have a significant impact on our financial statement results, as we did not have significant equity investments impacted by this standard.

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. In January 2018, additional lease guidance was issued specifically relating to land easements and how entities may elect to account for these arrangements at transition. The new standard, and related amendments, 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 plan on adopting this standard, and related amendments, on January 1, 2019, and are evaluating the transition practical expedients we may elect. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. We expect the adoption of the new guidance will impact our Consolidated Balance Sheets as we will be required to reflect lease assets and lease liabilities relating to certain operating lease arrangements. We are currently evaluating the significance of the expected balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures.

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 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. The adoption of this guidance will not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. We do not expect the adoption of this guidance will impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents are generally insignificant.


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 became effective for us on January 1, 2018 using a prospective approach. We adopted this new standard on January 1, 2018, using a prospective approach with no impacts on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard became effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We adopted this standard on January 1, 2018 using a modified retrospective transition approach. The adoption of this guidance did not have a significant impact on our financial statement results.

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance became effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. Beginning in the first quarter of 2018, we will present the non-service cost components of net benefit costs in other income instead of operating income. Prior year non-service cost components will also be reclassified from operating income to other income. Upon adoption, we will no longer capitalize a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income. See note 7 for additional information related to our pension plans and other postretirement benefits.
  
ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as we are currently not applying hedge accounting.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the 2017 Tax Cuts and Jobs Act legislation on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Cuts and Jobs Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Cuts and Jobs Act was recognized. We are currently evaluating this new guidance to determine whether we will elect this reclassification adjustment. The adoption of this guidance will not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Cuts and Jobs Act.
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 excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested 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 had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%).

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement is an increase of 3.28% (the average annual bill impact for a typical APS residential customer is 4.54%).

Other key provisions of the agreement include the following:

•
an agreement by APS not to file another general retail rate case application before June 1, 2019;
•
an authorized return on common equity of 10.0%;
•
a capital structure comprised of 44.2% debt and 55.8% common equity;
•
a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;
•
a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at Four Corners;
•
a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;
•
an expansion of the PSA to include certain environmental chemical costs and third-party battery storage costs;
•
a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year, and not more than $15 million per year;
•
an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;
•
rate design changes, including:
▪
a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;
▪
non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;
▪
a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and
•
an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated.   APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS has filed a motion to intervene. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant is requesting that the ACC hold a hearing on her amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS), and if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  APS cannot predict the outcome of this matter.

Prior Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case 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 5-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
  
In 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014.  The revised rules went into effect on April 21, 2015.    

In 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 costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

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. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement.  On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program requiring APS to spend $10-$15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.

In September 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 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. On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy reform policies tied to clean energy sources. The proposal would rename the RES to the Clean Resource Energy Standard and Tariff ("CREST").  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") annually for review by and approval of the ACC. 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 ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed 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 Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018.   On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million.
     
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 Commissioners 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.
 
Power Supply Adjustor 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 or refunded 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 2017 and 2016 (dollars in thousands):
 
Twelve Months Ended
December 31,
 
2017
 
2016
Beginning balance
$
12,465

 
$
(9,688
)
Deferred fuel and purchased power costs — current period
48,405

 
60,303

Amounts refunded/(charged) to customers
14,767

 
(38,150
)
Ending balance
$
75,637

 
$
12,465


 
The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh. On November 30, 2017, APS submitted its calculation for the 2018 PSA year beginning February 1, 2018. The current PSA rate is $.004555 per kWh consisting of a forward component of $.002009 per kWh and a historical component of $.002546 per kWh.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the 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, 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.    

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 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, 2017.

On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans.  A transmission customer intervened and protested certain aspects of APS’s filing.  FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed.  APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 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 DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first 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.  These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. 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.  DG sales losses are determined from the metered output from the DG units.
 
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). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its LFCR Adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease over 2017 levels). Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Tax Expense Adjustor Mechanism and FERC Tax Filing.  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps.  The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit.  APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million annually through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction will be effective March 1, 2018.

The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018.
    
The TEAM expressly applies to APS's retail rates with the exception noted above. The Company expects to make a filing with FERC in the first quarter of 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG 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 Administrative Law Judge 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 opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes 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 RCP 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 RCP method will be updated annually (between general retail 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 general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS 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 August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

•
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 general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017.

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 asserted 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 filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

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. This adjustment is subsumed within the 2017 Settlement Agreement and its associated revenue requirement.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on 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 the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter.

In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

Renewable Energy Ballot Initiative
On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS intends to oppose this effort. We believe the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. We cannot predict the outcome of this matter.
Clean Resource Energy Standard and Tariff

On January 30, 2018, ACC Commissioner Tobin proposed the CREST, which consists of a series of energy reform policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the Integrated Resource Plan process. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. APS cannot predict the outcome of this matter.

Four Corners
 
SCE-Related Matters. 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 retail 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 included 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 provided 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 $56 million as of December 31, 2017 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.
 
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. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS intends to file the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019. 

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla 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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($105 million as of December 31, 2017), 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. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026.
Navajo Plant
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

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.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($99 million as of December 31, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant 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 this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.

Regulatory Assets and Liabilities
 
The detail of regulatory assets is as follows (dollars in thousands):
S
 
 
December 31, 2017
 
December 31, 2016
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
576,188

 
$
—

 
$
711,059

Retired power plant costs
2033
 
27,402

 
188,843

 
9,913

 
117,591

Income taxes - AFUDC equity
2047
 
3,828

 
142,852

 
6,305

 
152,118

Deferred fuel and purchased power — mark-to-market (Note 16)
2020
 
52,100

 
34,845

 
—

 
42,963

Four Corners cost deferral
2024
 
8,077

 
48,305

 
6,689

 
56,894

Income taxes — investment tax credit basis adjustment
2046
 
1,066

 
26,218

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
59,844

 
—

 
61,307

 
—

Palo Verde VIEs (Note 18)
2046
 
—

 
19,395

 
—

 
18,775

Deferred compensation
2036
 
—

 
36,413

 
—

 
35,595

Deferred property taxes
2027
 
8,569

 
74,926

 
—

 
73,200

Loss on reacquired debt
2038
 
1,637

 
15,305

 
1,637

 
16,942

AG-1 deferral
2022
 
2,654

 
8,472

 
—

 
5,868

Demand side management (b)
2017
 
—

 
—

 
3,744

 
—

Tax expense of Medicare subsidy
2024
 
1,236

 
7,415

 
1,513

 
10,589

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,376

 
332

 
10,708

Deferred fuel and purchased power (b) (c)
2018
 
75,637

 
—

 
12,465

 
—

Coal reclamation
2026
 
1,068

 
12,396

 
418

 
5,182

Other
Various
 
4,638

 
353

 
432

 
1,588

Total regulatory assets (d)
 
 
$
248,088

 
$
1,202,302

 
$
106,875

 
$
1,313,428

(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)
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):
 
 
 
December 31, 2017
 
December 31, 2016
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - Tax Cuts and Jobs Act
(a)
 
$
—

 
$
1,520,274

 
$
—

 
$
—

Asset retirement obligations
2057
 
—

 
332,171

 
—

 
279,976

Removal costs
(b)
 
18,238

 
209,191

 
29,899

 
223,145

Other post retirement benefits
(d)
 
37,642

 
151,985

 
32,662

 
123,913

Income taxes - deferred investment tax credit
2046
 
2,164

 
52,497

 
4,368

 
108,827

Income taxes - change in rates
2046
 
2,573

 
70,537

 
1,771

 
70,898

Spent nuclear fuel
2027
 
6,924

 
62,132

 
—

 
71,726

Renewable energy standard (c)
2018
 
23,155

 
—

 
26,809

 
—

Demand side management (c)
2019
 
3,066

 
4,921

 
—

 
20,472

Sundance maintenance
2030
 
—

 
16,897

 
—

 
15,287

Deferred gains on utility property
2022
 
4,423

 
10,988

 
2,063

 
8,895

Four Corners coal reclamation
2038
 
1,858

 
18,921

 
—

 
18,248

Other
Various
 
43

 
2,022

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
100,086

 
$
2,452,536

 
$
99,899

 
$
948,916

(a)
See Note 4. While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months.
(b)
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).
(c)
See “Cost Recovery Mechanisms” discussion above.
(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 (“ITC”) basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.
 
On December 22, 2017, the Tax Cuts and Jobs Act ("Tax Act") was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate to 21% effective January 1, 2018. In accordance with generally accepted accounting principles, the effects of this corporate tax rate reduction were recognized for the year ending December 31, 2017. As a result of this rate reduction, the Company has recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017.

In accordance with accounting for regulated companies, the effect of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a regulatory liability of $1.52 billion and a new $377 million deferred tax asset. The company intends to amortize the regulatory liability in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining regulatory life of the related property, and in a manner to be approved by its federal and state regulatory agencies. See Note 3 for more details.

Additionally, as a result of the corporate tax rate reduction, the Company recorded income tax expense of $9.3 million, for the year ended December 31, 2017, to recognize the effect of certain reductions in deferred tax assets, for which the Company did not believe recovery was probable through its revenue requirement.

Several sections of the Tax Cuts and Jobs Act contain technical ambiguities. These ambiguities include certain transition rules regarding the applicability of bonus depreciation to property acquired, or under construction, prior to September 28, 2017 and the continued deductibility of certain executive compensation arrangements in place prior to November 3, 2017. Management has recognized tax positions which it believes are more likely than not to be sustained upon examination based upon its interpretation of this legislation. Clarifying guidance may be issued through additional legislation, Treasury regulations, or other technical guidance, within the next 12 months which may impact the income tax effects of the Tax Act as recorded by the Company. As of December 31, 2017, the Company does not have a reasonable estimate of what the income tax effects of such clarifying guidance may be, if any.

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Total unrecognized tax benefits, January 1
$
36,075

 
$
34,447

 
$
44,775

 
$
36,075

 
$
34,447

 
$
44,775

Additions for tax positions of the current year
2,937

 
2,695

 
2,175

 
2,937

 
2,695

 
2,175

Additions for tax positions of prior years
4,783

 
886

 
—

 
4,783

 
886

 
—

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(1,829
)
 
(1,953
)
 
(10,244
)
 
(1,829
)
 
(1,953
)
 
(10,244
)
Settlements with taxing authorities
—

 
—

 
—

 
—

 
—

 
—

Lapses of applicable statute of limitations
—

 
—

 
(2,259
)
 
—

 
—

 
(2,259
)
Total unrecognized tax benefits, December 31
$
41,966

 
$
36,075

 
$
34,447

 
$
41,966

 
$
36,075

 
$
34,447



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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Tax positions, that if recognized, would decrease our effective tax rate
$
16,373

 
$
11,313

 
$
9,523

 
$
16,373

 
$
11,313

 
$
9,523


 
As of the balance sheet date, the tax year ended December 31, 2014 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 2013.
 
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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Unrecognized tax benefit interest expense/(benefit) recognized
$
577

 
$
529

 
$
(161
)
 
$
577

 
$
529

 
$
(161
)

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Unrecognized tax benefit interest accrued
$
1,910

 
$
1,333

 
$
804

 
$
1,910

 
$
1,333

 
$
804



Additionally, as of December 31, 2017, 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,
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Current:
 

 
 

 
 

 
 
 
 
 
 
Federal
$
11,624

 
$
8,630

 
$
(12,335
)
 
$
21,512

 
$
711

 
$
6,485

State
3,052

 
1,259

 
4,763

 
2,778

 
4,276

 
7,813

Total current
14,676

 
9,889

 
(7,572
)
 
24,290

 
4,987

 
14,298

Deferred:
 

 
 

 
 

 
 

 
 

 
 

Federal
223,729

 
201,743

 
221,505

 
221,078

 
215,178

 
208,326

State
19,867

 
24,779

 
23,787

 
23,800

 
25,677

 
23,217

Total deferred
243,596

 
226,522

 
245,292

 
244,878

 
240,855

 
231,543

Income tax expense
$
258,272

 
$
236,411

 
$
237,720

 
$
269,168

 
$
245,842

 
$
245,841



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,
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Federal income tax expense at 35% statutory rate
$
268,177

 
$
244,278

 
$
242,869

 
$
277,540

 
$
254,617

 
$
250,267

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

 
 

 
 

 
 

State income tax net of federal income tax benefit
14,897

 
16,311

 
18,265

 
17,276

 
18,750

 
20,433

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

 
—

 
(2,169
)
 
—

 
—

 
(1,892
)
Medicare Subsidy Part-D
853

 
844

 
837

 
853

 
844

 
837

Stock compensation
(6,659
)
 
(2,951
)
 
—

 
(3,489
)
 
(1,937
)
 
—

Excess Deferred Income Taxes - Tax Cuts and Jobs Act
9,348

 
—

 
—

 
9,431

 
—

 
—

Allowance for equity funds used during construction (see Note 1)
(12,937
)
 
(11,724
)
 
(9,711
)
 
(12,937
)
 
(11,724
)
 
(9,711
)
Palo Verde VIE noncontrolling interest (see Note 18)
(6,823
)
 
(6,823
)
 
(6,626
)
 
(6,823
)
 
(6,823
)
 
(6,626
)
Investment tax credit amortization
(6,715
)
 
(5,887
)
 
(5,527
)
 
(6,715
)
 
(5,887
)
 
(5,527
)
Other
(1,869
)
 
2,363

 
(218
)
 
(5,968
)
 
(1,998
)
 
(1,940
)
Income tax expense
$
258,272

 
$
236,411

 
$
237,720

 
$
269,168

 
$
245,842

 
$
245,841


 
    
 
The components of the net deferred income tax liability were as follows (dollars in thousands):
 
 
Pinnacle West Consolidated
 
APS Consolidated
 
December 31,
 
December 31,
 
2017
 
2016
 
2017
 
2016
DEFERRED TAX ASSETS
 

 
 

 
 
 
 
Risk management activities
$
25,103

 
$
26,614

 
$
25,103

 
$
26,614

Regulatory liabilities:
 

 
 

 
 

 
 
Excess Deferred Income Taxes - Tax Cuts and Jobs Act
376,906

 
—

 
376,906

 
—

Asset retirement obligation and removal costs
135,847

 
200,140

 
135,847

 
200,140

Unamortized investment tax credits
54,661

 
113,195

 
54,661

 
113,195

Other postretirement benefits
47,021

 
60,375

 
47,021

 
60,375

Other
37,489

 
63,311

 
37,489

 
63,311

Pension liabilities
83,126

 
204,436

 
77,280

 
194,981

Renewable energy incentives
33,546

 
56,379

 
33,546

 
56,379

Credit and loss carryforwards
53,946

 
75,944

 
1,920

 
1,645

Other
102,432

 
158,421

 
108,223

 
187,453

Total deferred tax assets
950,077

 
958,815

 
897,996

 
904,093

DEFERRED TAX LIABILITIES
 

 
 

 
 

 
 
Plant-related
(2,220,886
)
 
(3,297,989
)
 
(2,220,886
)
 
(3,297,989
)
Risk management activities
(491
)
 
(7,594
)
 
(491
)
 
(7,594
)
Other postretirement assets
(66,134
)
 
(63,477
)
 
(65,733
)
 
(62,819
)
Regulatory assets:
 

 
 

 
 
 
 

Allowance for equity funds used during construction
(36,365
)
 
(61,088
)
 
(36,365
)
 
(61,088
)
Deferred fuel and purchased power — mark-to-market
(40,778
)
 
(21,396
)
 
(40,778
)
 
(21,396
)
Pension benefits
(142,848
)
 
(274,184
)
 
(142,848
)
 
(274,184
)
Retired power plant costs (see Note 3)
(53,611
)
 
(49,166
)
 
(53,611
)
 
(49,166
)
Other
(74,423
)
 
(123,987
)
 
(74,423
)
 
(123,987
)
Other
(5,346
)
 
(5,166
)
 
(5,346
)
 
(5,165
)
Total deferred tax liabilities
(2,640,882
)
 
(3,904,047
)
 
(2,640,481
)
 
(3,903,388
)
Deferred income taxes — net
$
(1,690,805
)
 
$
(2,945,232
)
 
$
(1,742,485
)
 
$
(2,999,295
)

 
As of December 31, 2017, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $79 million, which first begin to expire in 2034, and other federal and state credit carryforwards of $6 million, which first begin to expire in 2031. The credit and loss carryforwards amount above has been reduced by $31 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, 2017 and 2016 (dollars in thousands):
 
 
December 31, 2017
 
December 31, 2016
 
Pinnacle West
APS
Total
 
Pinnacle West
APS
Total
Commitments under Credit Facilities
$
325,000

$
1,000,000

$
1,325,000

 
$
275,000

$
1,000,000

$
1,275,000

Outstanding Commercial Paper and Revolving Credit Facility Borrowings
(95,400
)
—

(95,400
)
 
(41,700
)
(135,500
)
(177,200
)
Amount of Credit Facilities Available
$
229,600

$
1,000,000

$
1,229,600

 
$
233,300

$
864,500

$
1,097,800

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

Pinnacle West
 
At December 31, 2017, Pinnacle West had a $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, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $29.4 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018.  Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At December 31, 2017, Pinnacle West had $66 million outstanding under the facility.
 
APS
 
On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022.

At December 31, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in May 2021 and the above-mentioned $500 million facility. 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, 2017, APS had no 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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. 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, 2017 and 2016 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2017
 
2016
APS
 
 
 
 
 

 
 

Pollution control bonds:
 
 
 
 
 

 
 

Variable
2029
 
(b)
 
$
35,975

 
$
35,975

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

 
147,150

Total pollution control bonds
 
 
 
 
183,125

 
183,125

Senior unsecured notes
2019-2046
 
2.20%-8.75%
 
4,275,000

 
3,725,000

Term loans
2018-2019
 
(c)
 
150,000

 
150,000

Unamortized discount
 
 
 
 
(11,288
)
 
(11,816
)
Unamortized premium
 
 
 
 
8,049

 
4,506

Unamortized debt issuance cost
 
 
 
 
(31,594
)
 
(29,030
)
Total APS long-term debt
 
 
 
 
4,573,292

 
4,021,785

Less current maturities

 
 
 
82,000

 
—

Total APS long-term debt less current maturities
 
 
 
 
4,491,292

 
4,021,785

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(d)
 
—

 
125,000

Senior unsecured notes

2020
 
2.25%
 
300,000

 
—

Unamortized discount
 
 
 
 
(184
)
 
—

Unamortized debt issuance cost
 
 
 
 
(1,395
)
 
—

Total PNW long-term debt
 
 
 
 
298,421

 
125,000

Less current maturities
 
 
 
 
—

 
125,000

Total PNW long-term debt less current maturities
 
 
 
 
298,421

 
—

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
4,789,713

 
$
4,021,785

(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 1.77% at December 31, 2017 and 0.81% at December 31, 2016.
(c)
The weighted-average interest rate was 2.236% at December 31, 2017, and 1.427% at December 31, 2016.
(d)
The interest rate was 1.520% at December 31, 2016.

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
2018
 
$
82,000

 
$
82,000

2019
 
600,000

 
600,000

2020
 
550,000

 
250,000

2021
 
—

 
—

2022
 
—

 
—

Thereafter
 
3,676,125

 
3,676,125

Total
 
$
4,908,125

 
$
4,608,125


 
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, 2017
 
As of
December 31, 2016
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
298,421

 
$
298,608

 
$
125,000

 
$
125,000

APS
4,573,292

 
5,006,348

 
4,021,785

 
4,300,789

Total
$
4,871,713

 
$
5,304,956

 
$
4,146,785

 
$
4,425,789


 
Credit Facilities and Debt Issuances
 
Pinnacle West

On November 30, 2017, Pinnacle West issued $300 million of 2.25% unsecured senior notes that mature on November 30, 2020.  The net proceeds from the sale were used to repay our $125 million term loan and for general corporate purposes.

APS
 
On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% senior unsecured notes that mature on November 15, 2045.  The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures.

On September 11, 2017, APS issued $300 million of 2.95% senior unsecured notes that mature on September 15, 2027. The net proceeds from the sale were used to refinance commercial paper and other indebtedness and to replenish cash used to fund capital expenditures.

On November 30, 2017, PNW contributed $150 million into APS in the form of an equity infusion.  APS used this contribution to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

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, 2017, the ratio was approximately 50% 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. Its total shareholder equity was approximately $5.3 billion, and total capitalization was approximately $10.0 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.0 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2017.

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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt.  The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application.  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 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 2014 remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income.
 
Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $186 million of 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 transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account.  The Company negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, the Company submitted proof of the transfer to the IRS and expects to execute a final Closing Agreement early in 2018. Per the terms of an order from FERC, the Company must also make an informational filing with FERC. The Company made this FERC filing during February 2018. It is the Company’s understanding that completion of these regulatory requirements will then permit access to the approximately $186 million for the sole purpose of paying active union employee medical benefits.

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Service cost-benefits earned during the period
$
54,858

 
$
53,792

 
$
59,627

 
$
17,119

 
$
14,993

 
$
16,827

Interest cost on benefit obligation
129,756

 
131,647

 
123,983

 
29,959

 
29,721

 
28,102

Expected return on plan assets
(174,271
)
 
(173,906
)
 
(179,231
)
 
(53,401
)
 
(36,495
)
 
(36,855
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
81

 
527

 
594

 
(37,842
)
 
(37,883
)
 
(37,968
)
Net actuarial loss
47,900

 
40,717

 
31,056

 
5,118

 
4,589

 
4,881

Net periodic benefit cost
$
58,324

 
$
52,777

 
$
36,029

 
$
(39,047
)
 
$
(25,075
)
 
$
(25,013
)
Portion of cost charged to expense
$
27,295

 
$
26,172

 
$
20,036

 
$
(18,274
)
 
$
(12,435
)
 
$
(10,391
)


See Note 2 for additional information regarding accounting changes relating to ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.
 
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2017 and 2016 (dollars in thousands):
 
Pension
 
Other Benefits
 
2017
 
2016
 
2017
 
2016
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
3,204,462

 
$
3,033,803

 
$
716,445

 
$
647,020

Service cost
54,858

 
53,792

 
17,119

 
14,993

Interest cost
129,756

 
131,647

 
29,959

 
29,721

Benefit payments
(166,342
)
 
(142,247
)
 
(30,144
)
 
(26,231
)
Actuarial loss
171,452

 
127,467

 
20,014

 
50,942

Benefit obligation at December 31
3,394,186

 
3,204,462

 
753,393

 
716,445

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,675,357

 
2,542,774

 
882,651

 
833,017

Actual return on plan assets
428,374

 
166,408

 
139,367

 
63,463

Employer contributions
100,000

 
100,000

 
353

 
819

Benefit payments
(146,704
)
 
(133,825
)
 
—

 
(14,648
)
Fair value of plan assets at December 31
3,057,027

 
2,675,357

 
1,022,371

 
882,651

Funded Status at December 31
$
(337,159
)
 
$
(529,105
)
 
$
268,978

 
$
166,206



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, 2017 and 2016 (dollars in thousands):
 
2017
 
2016
Projected benefit obligation
$
3,394,186

 
$
3,204,462

Accumulated benefit obligation
3,227,233

 
3,049,406

Fair value of plan assets
3,057,027

 
2,675,357


 
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2017 and 2016 (dollars in thousands):
 
Pension
 
Other Benefits
 
2017
 
2016
 
2017
 
2016
Noncurrent asset
$
—

 
$
—

 
$
268,978

 
$
166,206

Current liability
(9,859
)
 
(19,795
)
 
—

 
—

Noncurrent liability
(327,300
)
 
(509,310
)
 
—

 
—

Net amount recognized
$
(337,159
)
 
$
(529,105
)
 
$
268,978

 
$
166,206


 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2017 and 2016 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2017
 
2016
 
2017
 
2016
Net actuarial loss
$
643,199

 
$
773,750

 
$
75,439

 
$
146,509

Prior service cost (credit)
—

 
81

 
(265,575
)
 
(303,417
)
APS’s portion recorded as a regulatory (asset) liability
(576,188
)
 
(711,059
)
 
189,627

 
156,575

Income tax expense (benefit)
(24,915
)
 
(24,202
)
 
853

 
833

Accumulated other comprehensive loss
$
42,096

 
$
38,570

 
$
344

 
$
500


 
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 2018 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
28,334

 
$
—

Prior service credit
—

 
(37,842
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018
$
28,334

 
$
(37,842
)


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,
 
2017
 
2016
 
2017
 
2016
 
2015
Discount rate – pension
3.65
%
 
4.08
%
 
4.08
%
 
4.37
%
 
4.02
%
Discount rate – other benefits
3.71
%
 
4.17
%
 
4.17
%
 
4.52
%
 
4.14
%
Rate of compensation increase
4.00
%
 
4.00
%
 
4.00
%
 
4.00
%
 
4.00
%
Expected long-term return on plan assets - pension
N/A

 
N/A

 
6.55
%
 
6.90
%
 
6.90
%
Expected long-term return on plan assets - other benefits
N/A

 
N/A

 
6.05
%
 
4.45
%
 
4.45
%
Initial healthcare cost trend rate (pre-65 participants)
7.00
%
 
7.00
%
 
7.00
%
 
7.00
%
 
7.00
%
Initial healthcare cost trend rate (post-65 participants)
4.75
%
 
5.00
%
 
5.00
%
 
5.00
%
 
5.00
%
Ultimate healthcare cost trend rate
4.75
%
 
5.00
%
 
5.00
%
 
5.00
%
 
5.00
%
Number of years to ultimate trend rate (pre-65 participants)
8

 
4

 
4

 
4

 
4


 
In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan.  For 2018, we are assuming a 6.05% long-term rate of return for pension assets and 5.55% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

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 on our December 31, 2017 amounts (dollars in thousands): 
 
1% Increase
 
1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
$
8,424

 
$
(5,616
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
9,145

 
(7,037
)
Effect on the accumulated other postretirement benefit obligation
128,203

 
(98,143
)

 
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 2017, the target and actual allocation for the pension plan at December 31, 2017 are as follows:
 
Pension
 
Target Allocation
 
Actual Allocation
Long-term fixed income assets
62
%
 
58
%
Return-generating assets
38
%
 
42
%
Total
100
%
 
100
%
The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the Plan's funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:
Asset Class
Target Allocation
Equities in US and other developed markets
18
%
Equities in emerging markets
6
%
Alternative investments
14
%
Total
38
%


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, 2017, 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. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2017:
 
Other Benefits
 
Actual Allocation
Long-term fixed income assets
67
%
Return-generating assets
33
%
Total
100
%

 
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, which includes exchange traded funds (ETFs), are classified as Level 1 and 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, and fixed income securities is derived from the 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, 2017, 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, 2017, approximately $58 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, 2017, 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, 2017
Pension Plan:
 

 
 

 
 
 
 

Cash and cash equivalents
$
3,830

 
$
—

 
$
—

 
$
3,830

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
1,365,194

 
—

 
1,365,194

U.S. Treasury
221,291

 
—

 
—

 
221,291

Other (b)
—

 
100,599

 
—

 
100,599

Common stock equities (c)
228,088

 
—

 
—

 
228,088

Mutual funds (d)
233,732

 
—

 
—

 
233,732

Common and collective trusts:
 
 
 
 
 
 
 
   Equities
—

 
—

 
408,763

 
408,763

   Real estate
—

 
—

 
171,569

 
171,569

   Fixed Income
—

 
—

 
90,869

 
90,869

Partnerships
—

 
—

 
133,379

 
133,379

Short-term investments and other (e)
—

 
1,208

 
98,505

 
99,713

Total
$
686,941

 
$
1,467,001

 
$
903,085

 
$
3,057,027

Other Benefits:
 

 
 

 
 

 
 

Cash and cash equivalents
$
143

 
$
—

 
$
—

 
$
143

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
306,008

 
—

 
306,008

U.S. Treasury
336,963

 
—

 
—

 
336,963

Other (b)
—

 
32,508

 
—

 
32,508

Common stock equities (c)
196,153

 
—

 
—

 
196,153

Mutual funds (d)
39,269

 
—

 
—

 
39,269

Common and collective trusts:
 

 
 

 
 
 
 

   Equities
—

 
—

 
75,310

 
75,310

   Real estate
—

 
—

 
15,422

 
15,422

Short-term investments and other (e)
11,268

 
149

 
9,178

 
20,595

Total
$
583,796

 
$
338,665

 
$
99,910

 
$
1,022,371

(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 U.S. common stock equities.
(d)
These funds invest in U.S. 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, 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 U.S. common stock equities.
(d)
These funds invest in U.S. and international common stock equities.
(e)
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 2017, $100 million in 2016, and $100 million in 2015.  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 $250 million during the 2018-2020 period.  With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2017, 2016 and 2015.  We do not expect to make any contributions over 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 2017, $100 million in 2016 and $100 million in 2015.  APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2017, 2016 and 2015.
 
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
2018
 
$
175,383

 
$
31,891

2019
 
181,902

 
34,000

2020
 
191,586

 
35,658

2021
 
196,583

 
37,090

2022
 
201,463

 
37,860

Years 2023-2027
 
1,068,568

 
191,207


 
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 2017, 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 2017, $10 million for 2016, and $9 million for 2015.
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 $18 million in 2017, $16 million in 2016, and $17 million in 2015.  APS’s lease expense was $17 million in 2017, $15 million in 2016, and $14 million in 2015.
 
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
2018
 
$
13,412

 
$
13,110

2019
 
11,054

 
10,802

2020
 
9,641

 
9,392

2021
 
7,105

 
6,858

2022
 
4,609

 
4,510

Thereafter
 
55,940

 
53,605

Total future lease commitments
 
$
101,761

 
$
98,277


 
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, 2017 (dollars in thousands):

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

 
 
 
 

 
 

 
 

 
Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,872,104

 
$
1,092,049

 
$
24,257

 
Palo Verde Unit 2 (a)
 
16.8
%
 

 
619,263

 
364,516

 
14,672

 
Palo Verde Common
 
28.0
%
 
(b)
 
726,223

 
262,065

 
46,577

 
Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
241,405

 
—

 
Four Corners Generating Station
 
63.0
%
 

 
1,196,683

 
568,304

 
240,514

 
Cholla common facilities (c)
 
50.5
%
 

 
180,907

 
69,633

 
1,091

 
Transmission facilities:
 
 

 
 
 
 

 
 

 
 

 
ANPP 500kV System
 
34.0
%
 
 (b)
 
130,767

 
46,400

 
684

 
Navajo Southern System
 
27.5
%
 
(b)
 
85,299

 
28,915

 
180

 
Palo Verde — Yuma 500kV System
 
18.1
%
 
(b)
 
14,765

 
6,614

 
486

 
Four Corners Switchyards
 
63.2
%
 
 (b)
 
66,386

 
12,605

 
327

 
Phoenix — Mead System
 
17.1
%
 
(b)
 
39,383

 
17,600

 
41

 
Palo Verde — Rudd 500kV System
 
50.0
%
 

 
97,600

 
23,884

 
245

 
Morgan — Pinnacle Peak System
 
64.6
%
 
 (b)
 
117,721

 
14,569

 
1

 
Round Valley System
 
50.0
%
 

 
515

 
141

 
—

 
Palo Verde — Morgan System
 
90.9
%
 
(b)
 
137,887

 
3,948

 
94,350

 
Hassayampa — North Gila System
 
80.0
%
 

 
142,541

 
6,953

 
—

 
Cholla 500kV Switchyard
 
85.7
%
 

 
5,243

 
1,312

 
190

 
Saguaro 500kV Switchyard
 
60.0
%
 

 
20,473

 
12,574

 
—

 
Kyrene — Knox System
 
50.0
%
 

 
578

 
297

 
—

 
(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.

APS also has a 14% ownership in the Navajo Plant.  In the second quarter of 2017, APS’s remaining net book value of its interest was reclassified from property, plant and equipment to a regulatory asset.  See “Navajo Plant” in Note 3 for more details.
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, 2017, 4CA had plant in service of $141 million, accumulated depreciation of $83 million and construction work in progress of $25 million.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
 
Palo Verde 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 United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 retail rate case settlement, this regulatory liability is being refunded to customers (see Note 3). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE in the fourth quarter of 2017 in the amount of $9 million (APS's share is $2.6 million). In February 2018, the DOE approved this claim.
 
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 $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $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 $19 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 $24 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 $64.8 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 2018 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $715 million in 2018; $578 million in 2019; $548 million in 2020; $548 million in 2021; $554 million in 2022; and $6.5 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,
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
Coal take-or-pay commitments (a)
$
159,997

 
$
185,365

 
$
186,632

 
$
190,607

 
$
194,678

 
$
1,750,739

 
(a)
Total take-or-pay commitments are approximately $2.7 billion.  The total net present value of these commitments is approximately $1.9 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,
 
2017
 
2016
 
2015
Total purchases
$
165,220

 
$
160,066

 
$
211,327


 
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 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; $40 million in 2022; and $370 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 $216 million at December 31, 2017 and $207 million at December 31, 2016. 4CA recorded an obligation for the coal mine final reclamation of approximately $16 million at December 31, 2017 and $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows:  $31 million in 2018; $32 million in 2019; $21 million in 2020; $20 million in 2021; $22 million in 2022; and $191 million thereafter.  4CA expects to make payments for the final mine reclamation as follows: $1 million in 2018; $1 million in 2019; $2 million in 2020; $2 million in 2021; $2 million in 2022; and $16 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, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater RI/FS.  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in the summer or fall of 2018. 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. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. 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.
 
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 pollution control 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 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 Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is 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 had 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 purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. 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; however, given the future plans for the Navajo Plant, we do not expect to incur these costs.  See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy. 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.

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 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.  In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.
 
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.

ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover EGUs, including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017 the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017 a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings. While this filing identified certain provisions of the federal CCR regulations that EPA intends to revise, including allowances for risk-based groundwater protection standards for regulated CCR constituents for which no federal maximum contaminant level has been set, it is not clear at this time which specific provisions of the federal CCR rules will be modified, how they will be modified, or when such modification will occur.
       
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 2 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 APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

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 $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations 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.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. 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. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold.

Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of GHG emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal.

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 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.

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. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

Four Corners Coal Supply Agreement

Arbitration

On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the 2016 Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant. NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million. APS’s share of this amount is approximately $17 million. On September 20, 2017, NTEC amended its Demand for Arbitration removing its request for a declaratory judgment and at this time is only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year. We cannot predict the timing or outcome of this arbitration; however we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction.
The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% interest in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula at December 31, 2017 is approximately $20 million, which is due to 4CA at December 31, 2018. In future years there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements.
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, 2017, standby letters of credit totaled $5 million and will expire in 2018. As of December 31, 2017, surety bonds expiring through 2019 totaled $62 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, 2017. Since July 6, 2016, Pinnacle West has issued four 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
 
In 2017, APS received a new decommissioning study for the Navajo Plant. This resulted in an increase to the ARO in the amount of $22 million, an increase in regulatory asset of $2 million and a reduction of the regulatory liability of $20 million.

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 and 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 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.

The following table shows the change in our asset retirement obligations for 2017 and 2016 (dollars in thousands):

 
2017
 
2016
Asset retirement obligations at the beginning of year
$
624,475

 
$
443,576

Changes attributable to:
 

 
 

Accretion expense
33,104

 
26,656

Settlements
—

 
(15,732
)
Estimated cash flow revisions
21,950

 
151,046

Newly incurred or acquired obligations
—

 
18,929

Asset retirement obligations at the end of year
$
679,529

 
$
624,475


 
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 2017 and 2016 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.

 
2017 Quarter Ended
 
2017
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
677,728

 
$
944,587

 
$
1,183,322

 
$
759,659

 
$
3,565,296

Operations and maintenance
219,976

 
214,013

 
224,305

 
266,149

 
924,443

Operating income
73,506

 
304,229

 
466,082

 
90,610

 
934,427

Income taxes
4,211

 
88,967

 
144,319

 
20,775

 
258,272

Net income
28,185

 
172,317

 
280,945

 
26,502

 
507,949

Net income attributable to common shareholders
23,312

 
167,443

 
276,072

 
21,629

 
488,456

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.21

 
$
1.50

 
$
2.47

 
$
0.19

 
$
4.37

Net income attributable to common shareholders — Diluted
0.21

 
1.49

 
2.46

 
0.19

 
4.35

 
 
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

Selected Quarterly Financial Data (Unaudited) 
Selected Quarterly Financial Data (Unaudited) - APS
 
APS's quarterly financial information for 2017 and 2016 is as follows (dollars in thousands):
 
 
2017 Quarter Ended,
 
2017
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
676,869

 
$
942,615

 
$
1,178,106

 
$
756,549

 
$
3,554,139

Operations and maintenance
212,218

 
208,286

 
215,264

 
255,361

 
891,129

Operating income
65,468

 
212,790

 
322,053

 
79,258

 
679,569

Net income attributable to common shareholder
23,162

 
169,108

 
284,256

 
27,783

 
504,309

 
 
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

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.

Level 2 — Other significant observable inputs, including 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). 
 
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 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, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, and investments held in our coal reclamation escrow accounts and nuclear decommissioning trust. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 7 for fair value discussion of plan assets held in our retirement and other benefit plans.
 
Cash Equivalents
 
Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.

Risk Management Activities — Derivative Instruments
 
Exchange traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value.  We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.  These include valuation adjustments for liquidity and credit risks.  The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged.  The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.
 
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions.  Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
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.
 
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 Nuclear Decommissioning Trust and Coal Reclamation Escrow
 
The nuclear decommissioning trust invests in fixed income securities, equity securities, and may hold cash and cash equivalents. The coal reclamation escrow account invests in fixed income instruments and may also hold cash and cash equivalents. See Note 19 for additional discussion about our investment accounts.

The nuclear decommissioning trust's equity security investments 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.
 
Fixed income securities issued by the U.S. Treasury 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 fixed income 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.

Cash equivalents reported within Level 1 represent investments held in short-term investment exchange-traded mutual funds. These short-term investment accounts invest in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments.
 
We price investment securities using information provided by our trustees for our nuclear decommissioning trust assets, and provided by our escrow agent for coal reclamation escrow assets. Our trustee and escrow agent use pricing services that utilize the valuation methodologies described above 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 and escrow agent's internal operating controls and valuation processes. 
 
Fair Value Tables
 
The following table presents the fair value at December 31, 2017 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, 2017
Assets
 

 
 

 
 

 
 

 
 
 
 

Cash equivalents
$
10,630

 
$
—

 
$
—

 
$
—

 
 
 
$
10,630

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
5,683

 
1,036

 
(4,737
)
 
(b)
 
1,982

Coal reclamation escrow account (c):
455

 
31,562

 
—

 
525

 
 
 
32,542

Nuclear decommissioning trust:
 

 
 

 
 

 
 
 
 
 
 

Cash and cash equivalents
7,224

 
—

 
—

 
109

 
(d)
 
7,333

U.S. commingled equity funds
—

 
—

 
—

 
417,390

 
(e)
 
417,390

Fixed income securities:
 

 
 

 
 

 
 
 
 
 
 

U.S. Treasury
127,662

 
—

 
—

 
—

 
 
 
127,662

Corporate debt
—

 
114,007

 
—

 
—

 
 
 
114,007

Mortgage-backed securities
—

 
111,874

 
—

 
—

 
 
 
111,874

Municipal bonds
—

 
79,049

 
—

 
—

 
 
 
79,049

Other
—

 
13,685

 
—

 
—

 
 
 
13,685

Subtotal nuclear decommissioning trust
134,886

 
318,615

 
—

 
417,499

 

 
871,000

Total Assets
$
145,971

 
$
355,860

 
$
1,036

 
$
413,287

 

 
$
916,154

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(78,646
)
 
$
(19,292
)
 
$
1,516

 
(b)
 
$
(96,422
)
(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents counterparty netting, margin, and collateral. See Note 16.
(c)
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. Primarily consists of fixed income municipal bonds.
(d)
Represents nuclear decommissioning trust net pending securities sales and purchases.
(e)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.


 
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 (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. Primarily consists of cash equivalents. Presented as Coal reclamation escrow in 2017.
(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.
 
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.  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.

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, 2017 and December 31, 2016:
 
 
December 31, 2017
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
21

 
$
15,485

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$18.51 - $38.75
 
$
27.89

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
1,015

 
3,807

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.33 - $3.11
 
$
2.71

Total
$
1,036

 
$
19,292

 
 
 
 
 
 
 
 

(a)
Includes swaps and physical and financial contracts.
 
 
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.
 
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, 2017 and 2016 (dollars in thousands):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2017
 
2016
Net derivative balance at beginning of period
 
$
(47,406
)
 
$
(32,979
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 
—

 
—

Included in OCI
 
3

 
88

Deferred as a regulatory asset or liability
 
(13,643
)
 
(37,543
)
Settlements
 
5,834

 
15,146

Transfers into Level 3 from Level 2
 
(10,026
)
 
1,900

Transfers from Level 3 into Level 2
 
46,982

 
5,982

Net derivative balance at end of period
 
$
(18,256
)
 
$
(47,406
)
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, 2017, 2016 and 2015 (in thousands, except per share amounts):
 
2017
 
2016
 
2015
Net income attributable to common shareholders
$
488,456

 
$
442,034

 
$
437,257

Weighted average common shares outstanding — basic
111,839

 
111,409

 
111,026

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
528

 
637

 
526

Weighted average common shares outstanding — diluted
112,367

 
112,046

 
111,552

Earnings per weighted-average common share outstanding
 
 
 
 
 
Net income attributable to common shareholders - basic
$
4.37

 
$
3.97

 
$
3.94

Net Income attributable to common shareholders - diluted
$
4.35

 
$
3.95

 
$
3.92

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, 2017, 2.2 million common shares were available for issuance under the 2012 Plan. During 2017, 2016, and 2015, 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. 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 2016 resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. The following amounts related to years ended 2017 and 2016 expense and activity include the effects of adopting this new accounting standard; however, expense and activities relating to 2015 reflect the historical accounting 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 $21 million in 2017, $19 million in 2016, and $19 million in 2015.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $15 million in 2017, $10 million in 2016, and $7 million in 2015.

As of December 31, 2017, there were approximately $12 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 2017, $22 million in 2016 and $21 million in 2015.
 
The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2017, 2016 and 2015.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Units granted
161,963

 
141,811

 
152,651

 
147,706

 
166,666

 
151,430

Weighted-average grant date fair value
$
72.60

 
$
67.34

 
$
64.12

 
$
78.99

 
$
66.60

 
$
64.97

(a)
Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.
(b)
Reflects the target payout level.
 
The following table is a summary of the status of non-vested awards as of December 31, 2017 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, 2017
335,259

 
$
62.04

 
312,724

 
$
65.32

Granted
161,963

 
72.60

 
147,706

 
78.99

Change in performance factor
—

 
—

 
18,266

 
64.97

Vested
(202,327
)
 
59.19

 
(164,396
)
 
63.87

Forfeited (c)
(3,607
)
 
69.58

 
(4,798
)
 
69.77

Nonvested at December 31, 2017
291,288

(a)
69.78

 
309,502

 
72.46

Vested Awards Outstanding at December 31, 2017
89,928

 


 
164,396

 


 
(a)
Includes 133,373 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 $4 million, $3 million and $10 million in 2017, 2016 and 2015, respectively. This includes cash used to settle restricted stock units of $4 million, $3 million and $3 million in 2017, 2016 and 2015, respectively. 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. In 2017 and 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, 100% cash, 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 did increase the number of awards that vested by 33,745 restricted stock units, payable in stock because certain performance requirements were met. In February 2017, 84,362 restricted stock units were released.

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 on non-financial 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 recipients 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 the 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
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates.  Risks associated with market volatility are managed 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.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may 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.

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, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
 
 
 
Quantity
Commodity
 
Unit of Measure
December 31, 2017
 
December 31, 2016
Power
 
GWh
583

 
1,314

Gas
 
Billion cubic feet
240

 
194

 
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, 2017, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2017
 
2016
 
2015
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(59
)
 
$
47

 
$
(615
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(3,519
)
 
(3,926
)
 
(5,988
)
(a)
During the years ended December 31, 2017, 2016, and 2015, 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 $2 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, 2017, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2017
 
2016
 
2015
Net Gain (Loss) Recognized in Income
 
Operating revenues
 
$
(1,192
)
 
$
771

 
$
574

Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
(87,991
)
 
25,711

 
(108,973
)
Total
 
 
 
$
(89,183
)
 
$
26,482

 
$
(108,399
)
(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.
 
As of December 31, 2017, we no longer have derivative instruments that are designated as cash flow hedging instruments. As of December 31, 2016, the Consolidated Balance Sheets included $2 million of gross liabilities related to derivative instruments designated as cash flow 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, 2017 and 2016.  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, 2017:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
5,427

 
$
(3,796
)
 
$
1,631

 
$
300

 
$
1,931

Investments and other assets
 
1,292

 
(1,241
)
 
51

 
—

 
51

Total assets
 
6,719

 
(5,037
)
 
1,682

 
300

 
1,982

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(59,527
)
 
3,796

 
(55,731
)
 
(3,521
)
 
(59,252
)
Deferred credits and other
 
(38,411
)
 
1,241

 
(37,170
)
 
—

 
(37,170
)
Total liabilities
 
(97,938
)
 
5,037

 
(92,901
)
 
(3,521
)
 
(96,422
)
Total
 
$
(91,219
)
 
$
—

 
$
(91,219
)
 
$
(3,221
)
 
$
(94,440
)
(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 $3,521 and cash margin provided to counterparties of $300.
 
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.

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, 2017, Pinnacle West has 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 counterparties 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, 2017 (dollars in thousands):
 
 
December 31, 2017
Aggregate fair value of derivative instruments in a net liability position
$
97,938

Cash collateral posted
—

Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)
91,071

(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 $110 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 2017, 2016 and 2015 (dollars in thousands):
 
 
2017
 
2016
 
2015
Other income:
 

 
 

 
 

Interest income
$
3,497

 
$
884

 
$
493

Miscellaneous
509

 
17

 
128

Total other income
$
4,006

 
$
901

 
$
621

Other expense:
 

 
 

 
 

Non-operating costs
$
(11,749
)
 
$
(9,235
)
 
$
(11,292
)
Investment losses — net
(4,113
)
 
(1,747
)
 
(2,080
)
Miscellaneous
(5,677
)
 
(4,355
)
 
(4,451
)
Total other expense
$
(21,539
)
 
$
(15,337
)
 
$
(17,823
)
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 2017, 2016 and 2015 (dollars in thousands):
 
 
2017
 
2016
 
2015
Other income:
 

 
 

 
 

Interest income
$
2,858

 
$
261

 
$
163

Gain on disposition of property
2,048

 
5,745

 
716

Miscellaneous
1,620

 
2,601

 
1,955

Total other income
$
6,526

 
$
8,607

 
$
2,834

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(12,395
)
 
$
(11,034
)
 
$
(11,648
)
Loss on disposition of property
(5,424
)
 
(1,246
)
 
(2,219
)
Miscellaneous
(5,561
)
 
(5,234
)
 
(5,152
)
Total other expense
$
(23,380
)
 
$
(17,514
)
 
$
(19,019
)
(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 2018 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 of $19 million for 2017, 2016 and 2015. The increase in net income is 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, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
December 31, 2017
 
December 31, 2016
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation
$
109,645

 
$
113,515

Equity-Noncontrolling interests
129,040

 
132,290


 
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 $293 million beginning in 2018, 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.
Investments
Investments
Investments
 
We have investments in debt and equity securities held in Nuclear Decommissioning Trusts and Coal Reclamation Escrow Accounts. These investments are classified as available for sale securities, and as a result we record the investments 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 investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning and coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The costs of securities sold are determined on the basis of specific identification.

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.  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, 2017 and December 31, 2016 (dollars in thousands):
 
 
December 31, 2017
 
December 31, 2016
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
Equity securities
$
417,390

 
$
248,623

 
$
—

 
$
353,261

 
$
188,091

 
$
—

Fixed income securities
446,277

 
11,537

 
(2,996
)
 
425,530

 
9,820

 
(4,962
)
Cash and cash equivalents
7,224

 
—

 
—

 
—

 
—

 
—

Net receivables (a)
109

 
—

 
—

 
795

 
—

 
—

Total
$
871,000

 
$
260,160

 
$
(2,996
)
 
$
779,586

 
$
197,911

 
$
(4,962
)
(a)
Net receivables/(payables) relate to pending purchases and sales of securities.
 
The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):
 
 
Nuclear Decommissioning

 
Year Ended December 31,
 
2017
 
2016
 
2015
Realized gains
$
21,813

 
$
11,213

 
$
5,189

Realized losses
(13,146
)
 
(10,106
)
 
(6,225
)
Proceeds from the sale of securities (a)
542,246

 
633,410

 
478,813

(a)
Proceeds are reinvested in the trust/account.

Coal Reclamation Escrow Accounts

APS has investments restricted for coal mine reclamation funding related to Four Corners. As of December 31, 2017, APS’s coal reclamation escrow accounts are invested in fixed income securities with a fair value of $30 million. The realized and unrealized gains and losses relating to these fixed income securities was immaterial for the twelve months ended December 31, 2017 and December 31, 2016. The proceeds from the sale of securities for the twelve months ended December 31, 2017 was $4 million. There were no proceeds from the sale of securities for the twelve months ended December 31, 2016. The proceeds are reinvested in the escrow accounts. 
4CA also has investments restricted for coal mine reclamation funding relating to Four Corners invested in fixed income securities. The 4CA fixed income investments have a fair value of $2 million as of December 31, 2017. The realized and unrealized gains and losses relating to these fixed income securities was immaterial for the twelve months ended December 31, 2017 and 2016.
    
Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2017 is as follows (dollars in thousands):
 
 
Nuclear Decommissioning Trusts
 
Escrow Accounts
 
Total
Less than one year
$
24,668

 
$
455

 
$
25,123

1 year – 5 years
100,289

 
2,494

 
102,783

5 years – 10 years
129,239

 
8,615

 
137,854

Greater than 10 years
192,081

 
20,453

 
212,534

Total
$
446,277

 
$
32,017

 
$
478,294

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, 2017 and 2016 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
Total
Balance December 31, 2015
$
(37,593
)
 

 
$
(7,155
)
 

 
$
(44,748
)
OCI (loss) before reclassifications
(4,509
)
 

 
(538
)
 

 
(5,047
)
Amounts reclassified from accumulated other comprehensive loss
3,032

 
(a)
 
2,941

 
(b)
 
5,973

Balance December 31, 2016
(39,070
)
 

 
(4,752
)
 

 
(43,822
)
OCI (loss) before reclassifications
(6,438
)
 

 
(35
)
 

 
(6,473
)
Amounts reclassified from accumulated other comprehensive loss
3,068

 
(a)
 
2,225

 
(b)
 
5,293

Balance December 31, 2017
$
(42,440
)
 

 
$
(2,562
)
 

 
$
(45,002
)
(a)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
(b)
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.
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, 2017 and 2016 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
Total
Balance December 31, 2015
$
(19,942
)
 

 
$
(7,155
)
 

 
$
(27,097
)
OCI (loss) before reclassifications
(3,821
)
 

 
(538
)
 

 
(4,359
)
Amounts reclassified from accumulated other comprehensive loss
3,092

 
(a)
 
2,941

 
(b)
 
6,033

Balance December 31, 2016
(20,671
)
 

 
(4,752
)
 

 
(25,423
)
OCI (loss) before reclassifications
(6,884
)
 

 
(35
)
 

 
(6,919
)
Amounts reclassified from accumulated other comprehensive loss
3,134

 
(a)
 
2,225

 
(b)
 
5,359

Balance December 31, 2017
$
(24,421
)
 

 
$
(2,562
)
 

 
$
(26,983
)
(a)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
(b)
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.
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,
 
2017
 
2016
 
2015
Operating revenues
$
119

 
$
370

 
$
550

Operating expenses
24,298

 
26,424

 
12,733

Operating loss
(24,179
)
 
(26,054
)
 
(12,183
)
Other
 

 
 

 
 

Equity in earnings of subsidiaries
507,495

 
462,027

 
446,508

Other expense
(2,715
)
 
(1,771
)
 
(3,302
)
Total
504,780

 
460,256

 
443,206

Interest expense
5,633

 
3,151

 
2,672

Income before income taxes
474,968

 
431,051

 
428,351

Income tax benefit
(13,488
)
 
(10,983
)
 
(8,906
)
Net income attributable to common shareholders
488,456

 
442,034

 
437,257

Other comprehensive income (loss) — attributable to common shareholders
(1,180
)
 
926

 
23,393

Total comprehensive income — attributable to common shareholders
$
487,276

 
$
442,960

 
$
460,650


 
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,
 
2017
 
2016
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
41

 
$
41

Accounts receivable
93,554

 
81,751

Income tax receivable
19,124

 
—

Other current assets
267

 
340

Total current assets
112,986

 
82,132

Investments and other assets
 

 
 

Investments in subsidiaries
5,465,137

 
5,084,035

Deferred income taxes
54,352

 
53,805

Other assets
44,613

 
38,500

Total investments and other assets
5,564,102

 
5,176,340

Total Assets
$
5,677,088

 
$
5,258,472

LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
$
7,638

 
$
5,421

Accrued taxes
8,927

 
12,050

Common dividends payable
77,667

 
72,926

Short-term borrowings
95,400

 
41,700

Current maturities of long-term debt
—

 
125,000

Other current liabilities
17,417

 
31,182

Total current liabilities
207,049

 
288,279

 
 
 
 
Long-term debt less current maturities
298,421

 
—

 
 
 
 
Pension liabilities
20,758

 
21,057

Other
15,130

 
13,224

Total deferred credits and other
35,888

 
34,281

Common stock equity
 
 
 
Common stock
2,609,181

 
2,591,897

Accumulated other comprehensive loss
(45,002
)
 
(43,822
)
Retained earnings
2,442,511

 
2,255,547

Total Pinnacle West Shareholders’ equity
5,006,690

 
4,803,622

Noncontrolling interests
129,040

 
132,290

Total Equity
5,135,730

 
4,935,912

Total Liabilities and Equity
$
5,677,088

 
$
5,258,472


 
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,
 
2017
 
2016
 
2015
Cash flows from operating activities
 

 
 

 
 

Net income
$
488,456

 
$
442,034

 
$
437,257

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

Equity in earnings of subsidiaries — net
(507,495
)
 
(462,027
)
 
(446,508
)
Depreciation and amortization
76

 
85

 
92

Deferred income taxes
(264
)
 
(12,402
)
 
12,967

Accounts receivable
(2,106
)
 
15,823

 
11,336

Accounts payable
(11,162
)
 
10,402

 
637

Accrued taxes and income tax receivables — net
(22,247
)
 
20,041

 
(12,882
)
Dividends received from subsidiaries
296,800

 
239,300

 
266,900

Other
15,092

 
5,514

 
(6,995
)
Net cash flow provided by operating activities
257,150

 
258,770

 
262,804

Cash flows from investing activities
 

 
 

 
 

Construction work in progress
—

 
(18,457
)
 
(3,462
)
Investments in subsidiaries
(178,027
)
 
(19,242
)
 
(3,491
)
Repayments of loans from subsidiaries
2,987

 
1,026

 
157

Advances of loans to subsidiaries
(6,388
)
 
(2,092
)
 
(1,010
)
Net cash flow used for investing activities
(181,428
)
 
(38,765
)
 
(7,806
)
Cash flows from financing activities
 

 
 

 
 

Issuance of long-term debt
298,761

 
—

 
—

Short-term debt borrowings under revolving credit facility
58,000

 
40,000

 
—

Short-term debt repayments under revolving credit facility
(32,000
)
 
—

 
—

Commercial paper - net
27,700

 
1,700

 
—

Dividends paid on common stock
(289,793
)
 
(274,229
)
 
(260,027
)
Repayment of long-term debt
(125,000
)
 
—

 
—

Common stock equity issuance - net of purchases
(13,390
)
 
(4,867
)
 
19,373

Net cash flow used for financing activities
(75,722
)
 
(237,396
)
 
(240,654
)
Net increase (decrease) in cash and cash equivalents
—

 
(17,391
)
 
14,344

Cash and cash equivalents at beginning of year
41

 
17,432

 
3,088

Cash and cash equivalents at end of year
$
41

 
$
41

 
$
17,432


     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 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:
 
 

 
 

 
 

 
 

 
 

2017
 
$
3,037

 
$
6,836

 
$
—

 
$
7,360

 
$
2,513

2016
 
3,125

 
4,025

 
—

 
4,113

 
3,037

2015
 
3,094

 
4,073

 
—

 
4,042

 
3,125

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:
 
 

 
 

 
 

 
 

 
 

2017
 
$
3,037

 
$
6,836

 
$
—

 
$
7,360

 
$
2,513

2016
 
3,125

 
4,025

 
—

 
4,113

 
3,037

2015
 
3,094

 
4,073

 
—

 
4,042

 
3,125

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 a more condensed form on the Consolidated Balance Sheets than in the prior year. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on accumulated other comprehensive loss. The following tables show the impacts of the reclassifications of the prior year (previously reported) amounts (dollars in thousands):

Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current year
presentation
Accumulated other comprehensive loss:
 
 
 
 
 
Pension and other postretirement benefits
$
(39,070
)
 
$
39,070

 
$
—

Derivative instruments
(4,752
)
 
4,752

 
—

Total accumulated other comprehensive loss
(43,822
)
 
43,822

 
—

Accumulated other comprehensive loss
—

 
(43,822
)
 
(43,822
)

Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current year
presentation
Accumulated other comprehensive loss:
 
 
 
 
 
Pension and other postretirement benefits
$
(20,671
)
 
$
20,671

 
$
—

Derivative instruments
(4,752
)
 
4,752

 
—

Total accumulated other comprehensive loss
(25,423
)
 
25,423

 
—

Accumulated other comprehensive loss
—

 
(25,423
)
 
(25,423
)
Accounting Records and Use of Estimates 
Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

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 amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to 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 and amortization 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, 2017 were as follows:
 
•Fossil plant — 21 years;
•Nuclear plant — 26 years;
•Other generation — 25 years;
•Transmission — 38 years;
•Distribution — 33 years; and
•General plant — 6 years.
 
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.
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 6.68% for 2017, 7.17% for 2016, and 8.02% for 2015.  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, coal reclamation escrow accounts, 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 reduced the fee to zero.  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 2019.
Income Taxes 
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  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 holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for 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, and coal reclamation escrow, 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 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, became 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 adopted this standard on January 1, 2018 using the modified retrospective transition approach. The adoption of this standard will not have significant impact on our financial statement results. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment the adoption of this guidance does not generally impact the timing of our revenue recognition relating to these customers. The adoption of the new standard will result in expanded revenue related disclosures.

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 became effective for us on January 1, 2018. Certain aspects of the standard require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We adopted this standard on a prospective basis on January 1, 2018. The adoption of this standard will not have a significant impact on our financial statement results, as we did not have significant equity investments impacted by this standard.

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. In January 2018, additional lease guidance was issued specifically relating to land easements and how entities may elect to account for these arrangements at transition. The new standard, and related amendments, 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 plan on adopting this standard, and related amendments, on January 1, 2019, and are evaluating the transition practical expedients we may elect. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. We expect the adoption of the new guidance will impact our Consolidated Balance Sheets as we will be required to reflect lease assets and lease liabilities relating to certain operating lease arrangements. We are currently evaluating the significance of the expected balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures.

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 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. The adoption of this guidance will not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. We do not expect the adoption of this guidance will impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents are generally insignificant.


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 became effective for us on January 1, 2018 using a prospective approach. We adopted this new standard on January 1, 2018, using a prospective approach with no impacts on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard became effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We adopted this standard on January 1, 2018 using a modified retrospective transition approach. The adoption of this guidance did not have a significant impact on our financial statement results.

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance became effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. Beginning in the first quarter of 2018, we will present the non-service cost components of net benefit costs in other income instead of operating income. Prior year non-service cost components will also be reclassified from operating income to other income. Upon adoption, we will no longer capitalize a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income. See note 7 for additional information related to our pension plans and other postretirement benefits.
  
ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as we are currently not applying hedge accounting.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the 2017 Tax Cuts and Jobs Act legislation on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Cuts and Jobs Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Cuts and Jobs Act was recognized. We are currently evaluating this new guidance to determine whether we will elect this reclassification adjustment. The adoption of this guidance will not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Cuts and Jobs Act.
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 year (previously reported) amounts (dollars in thousands):

Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current year
presentation
Accumulated other comprehensive loss:
 
 
 
 
 
Pension and other postretirement benefits
$
(39,070
)
 
$
39,070

 
$
—

Derivative instruments
(4,752
)
 
4,752

 
—

Total accumulated other comprehensive loss
(43,822
)
 
43,822

 
—

Accumulated other comprehensive loss
—

 
(43,822
)
 
(43,822
)

Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016
As previously
reported
 
Reclassifications to
conform to current year
presentation
 
Amount reported after
reclassification to
conform to current year
presentation
Accumulated other comprehensive loss:
 
 
 
 
 
Pension and other postretirement benefits
$
(20,671
)
 
$
20,671

 
$
—

Derivative instruments
(4,752
)
 
4,752

 
—

Total accumulated other comprehensive loss
(25,423
)
 
25,423

 
—

Accumulated other comprehensive loss
—

 
(25,423
)
 
(25,423
)
Schedule of property, plant and equipment 
Pinnacle West’s property, plant and equipment included in the December 31, 2017 and 2016 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2017
 
2016
Generation
$
7,963,998

 
$
7,874,898

Transmission
2,836,578

 
2,746,508

Distribution
6,025,856

 
5,738,801

General plant
971,629

 
981,681

Plant in service and held for future use
17,798,061

 
17,341,888

Accumulated depreciation and amortization
(6,128,535
)
 
(5,970,100
)
Net
11,669,526

 
11,371,788

Construction work in progress
1,291,498

 
1,019,947

Palo Verde sale leaseback, net of accumulated depreciation
109,645

 
113,515

Intangible assets, net of accumulated amortization
257,189

 
90,022

Nuclear fuel, net of accumulated amortization
117,408

 
119,004

Total property, plant and equipment
$
13,445,266

 
$
12,714,276

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,
 
2017
 
2016
 
2015
Cash paid during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
2,186

 
$
9,956

 
$
6,550

Interest, net of amounts capitalized
189,288

 
184,462

 
170,209

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
130,404

 
$
114,855

 
$
83,798

Dividends declared but not paid
77,667

 
72,926

 
69,363


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 2017 and 2016 (dollars in thousands):
 
Twelve Months Ended
December 31,
 
2017
 
2016
Beginning balance
$
12,465

 
$
(9,688
)
Deferred fuel and purchased power costs — current period
48,405

 
60,303

Amounts refunded/(charged) to customers
14,767

 
(38,150
)
Ending balance
$
75,637

 
$
12,465

Schedule of regulatory assets 
The detail of regulatory assets is as follows (dollars in thousands):
S
 
 
December 31, 2017
 
December 31, 2016
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
576,188

 
$
—

 
$
711,059

Retired power plant costs
2033
 
27,402

 
188,843

 
9,913

 
117,591

Income taxes - AFUDC equity
2047
 
3,828

 
142,852

 
6,305

 
152,118

Deferred fuel and purchased power — mark-to-market (Note 16)
2020
 
52,100

 
34,845

 
—

 
42,963

Four Corners cost deferral
2024
 
8,077

 
48,305

 
6,689

 
56,894

Income taxes — investment tax credit basis adjustment
2046
 
1,066

 
26,218

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
59,844

 
—

 
61,307

 
—

Palo Verde VIEs (Note 18)
2046
 
—

 
19,395

 
—

 
18,775

Deferred compensation
2036
 
—

 
36,413

 
—

 
35,595

Deferred property taxes
2027
 
8,569

 
74,926

 
—

 
73,200

Loss on reacquired debt
2038
 
1,637

 
15,305

 
1,637

 
16,942

AG-1 deferral
2022
 
2,654

 
8,472

 
—

 
5,868

Demand side management (b)
2017
 
—

 
—

 
3,744

 
—

Tax expense of Medicare subsidy
2024
 
1,236

 
7,415

 
1,513

 
10,589

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,376

 
332

 
10,708

Deferred fuel and purchased power (b) (c)
2018
 
75,637

 
—

 
12,465

 
—

Coal reclamation
2026
 
1,068

 
12,396

 
418

 
5,182

Other
Various
 
4,638

 
353

 
432

 
1,588

Total regulatory assets (d)
 
 
$
248,088

 
$
1,202,302

 
$
106,875

 
$
1,313,428

(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)
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):
 
 
 
December 31, 2017
 
December 31, 2016
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - Tax Cuts and Jobs Act
(a)
 
$
—

 
$
1,520,274

 
$
—

 
$
—

Asset retirement obligations
2057
 
—

 
332,171

 
—

 
279,976

Removal costs
(b)
 
18,238

 
209,191

 
29,899

 
223,145

Other post retirement benefits
(d)
 
37,642

 
151,985

 
32,662

 
123,913

Income taxes - deferred investment tax credit
2046
 
2,164

 
52,497

 
4,368

 
108,827

Income taxes - change in rates
2046
 
2,573

 
70,537

 
1,771

 
70,898

Spent nuclear fuel
2027
 
6,924

 
62,132

 
—

 
71,726

Renewable energy standard (c)
2018
 
23,155

 
—

 
26,809

 
—

Demand side management (c)
2019
 
3,066

 
4,921

 
—

 
20,472

Sundance maintenance
2030
 
—

 
16,897

 
—

 
15,287

Deferred gains on utility property
2022
 
4,423

 
10,988

 
2,063

 
8,895

Four Corners coal reclamation
2038
 
1,858

 
18,921

 
—

 
18,248

Other
Various
 
43

 
2,022

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
100,086

 
$
2,452,536

 
$
99,899

 
$
948,916

(a)
See Note 4. While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months.
(b)
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).
(c)
See “Cost Recovery Mechanisms” discussion above.
(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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Total unrecognized tax benefits, January 1
$
36,075

 
$
34,447

 
$
44,775

 
$
36,075

 
$
34,447

 
$
44,775

Additions for tax positions of the current year
2,937

 
2,695

 
2,175

 
2,937

 
2,695

 
2,175

Additions for tax positions of prior years
4,783

 
886

 
—

 
4,783

 
886

 
—

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(1,829
)
 
(1,953
)
 
(10,244
)
 
(1,829
)
 
(1,953
)
 
(10,244
)
Settlements with taxing authorities
—

 
—

 
—

 
—

 
—

 
—

Lapses of applicable statute of limitations
—

 
—

 
(2,259
)
 
—

 
—

 
(2,259
)
Total unrecognized tax benefits, December 31
$
41,966

 
$
36,075

 
$
34,447

 
$
41,966

 
$
36,075

 
$
34,447

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Tax positions, that if recognized, would decrease our effective tax rate
$
16,373

 
$
11,313

 
$
9,523

 
$
16,373

 
$
11,313

 
$
9,523

The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 
 
Pinnacle West Consolidated
 
APS Consolidated
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Unrecognized tax benefit interest expense/(benefit) recognized
$
577

 
$
529

 
$
(161
)
 
$
577

 
$
529

 
$
(161
)

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Unrecognized tax benefit interest accrued
$
1,910

 
$
1,333

 
$
804

 
$
1,910

 
$
1,333

 
$
804

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,
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Current:
 

 
 

 
 

 
 
 
 
 
 
Federal
$
11,624

 
$
8,630

 
$
(12,335
)
 
$
21,512

 
$
711

 
$
6,485

State
3,052

 
1,259

 
4,763

 
2,778

 
4,276

 
7,813

Total current
14,676

 
9,889

 
(7,572
)
 
24,290

 
4,987

 
14,298

Deferred:
 

 
 

 
 

 
 

 
 

 
 

Federal
223,729

 
201,743

 
221,505

 
221,078

 
215,178

 
208,326

State
19,867

 
24,779

 
23,787

 
23,800

 
25,677

 
23,217

Total deferred
243,596

 
226,522

 
245,292

 
244,878

 
240,855

 
231,543

Income tax expense
$
258,272

 
$
236,411

 
$
237,720

 
$
269,168

 
$
245,842

 
$
245,841

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,
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Federal income tax expense at 35% statutory rate
$
268,177

 
$
244,278

 
$
242,869

 
$
277,540

 
$
254,617

 
$
250,267

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

 
 

 
 

 
 

State income tax net of federal income tax benefit
14,897

 
16,311

 
18,265

 
17,276

 
18,750

 
20,433

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

 
—

 
(2,169
)
 
—

 
—

 
(1,892
)
Medicare Subsidy Part-D
853

 
844

 
837

 
853

 
844

 
837

Stock compensation
(6,659
)
 
(2,951
)
 
—

 
(3,489
)
 
(1,937
)
 
—

Excess Deferred Income Taxes - Tax Cuts and Jobs Act
9,348

 
—

 
—

 
9,431

 
—

 
—

Allowance for equity funds used during construction (see Note 1)
(12,937
)
 
(11,724
)
 
(9,711
)
 
(12,937
)
 
(11,724
)
 
(9,711
)
Palo Verde VIE noncontrolling interest (see Note 18)
(6,823
)
 
(6,823
)
 
(6,626
)
 
(6,823
)
 
(6,823
)
 
(6,626
)
Investment tax credit amortization
(6,715
)
 
(5,887
)
 
(5,527
)
 
(6,715
)
 
(5,887
)
 
(5,527
)
Other
(1,869
)
 
2,363

 
(218
)
 
(5,968
)
 
(1,998
)
 
(1,940
)
Income tax expense
$
258,272

 
$
236,411

 
$
237,720

 
$
269,168

 
$
245,842

 
$
245,841

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,
 
2017
 
2016
 
2017
 
2016
DEFERRED TAX ASSETS
 

 
 

 
 
 
 
Risk management activities
$
25,103

 
$
26,614

 
$
25,103

 
$
26,614

Regulatory liabilities:
 

 
 

 
 

 
 
Excess Deferred Income Taxes - Tax Cuts and Jobs Act
376,906

 
—

 
376,906

 
—

Asset retirement obligation and removal costs
135,847

 
200,140

 
135,847

 
200,140

Unamortized investment tax credits
54,661

 
113,195

 
54,661

 
113,195

Other postretirement benefits
47,021

 
60,375

 
47,021

 
60,375

Other
37,489

 
63,311

 
37,489

 
63,311

Pension liabilities
83,126

 
204,436

 
77,280

 
194,981

Renewable energy incentives
33,546

 
56,379

 
33,546

 
56,379

Credit and loss carryforwards
53,946

 
75,944

 
1,920

 
1,645

Other
102,432

 
158,421

 
108,223

 
187,453

Total deferred tax assets
950,077

 
958,815

 
897,996

 
904,093

DEFERRED TAX LIABILITIES
 

 
 

 
 

 
 
Plant-related
(2,220,886
)
 
(3,297,989
)
 
(2,220,886
)
 
(3,297,989
)
Risk management activities
(491
)
 
(7,594
)
 
(491
)
 
(7,594
)
Other postretirement assets
(66,134
)
 
(63,477
)
 
(65,733
)
 
(62,819
)
Regulatory assets:
 

 
 

 
 
 
 

Allowance for equity funds used during construction
(36,365
)
 
(61,088
)
 
(36,365
)
 
(61,088
)
Deferred fuel and purchased power — mark-to-market
(40,778
)
 
(21,396
)
 
(40,778
)
 
(21,396
)
Pension benefits
(142,848
)
 
(274,184
)
 
(142,848
)
 
(274,184
)
Retired power plant costs (see Note 3)
(53,611
)
 
(49,166
)
 
(53,611
)
 
(49,166
)
Other
(74,423
)
 
(123,987
)
 
(74,423
)
 
(123,987
)
Other
(5,346
)
 
(5,166
)
 
(5,346
)
 
(5,165
)
Total deferred tax liabilities
(2,640,882
)
 
(3,904,047
)
 
(2,640,481
)
 
(3,903,388
)
Deferred income taxes — net
$
(1,690,805
)
 
$
(2,945,232
)
 
$
(1,742,485
)
 
$
(2,999,295
)
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, 2017 and 2016 (dollars in thousands):
 
 
December 31, 2017
 
December 31, 2016
 
Pinnacle West
APS
Total
 
Pinnacle West
APS
Total
Commitments under Credit Facilities
$
325,000

$
1,000,000

$
1,325,000

 
$
275,000

$
1,000,000

$
1,275,000

Outstanding Commercial Paper and Revolving Credit Facility Borrowings
(95,400
)
—

(95,400
)
 
(41,700
)
(135,500
)
(177,200
)
Amount of Credit Facilities Available
$
229,600

$
1,000,000

$
1,229,600

 
$
233,300

$
864,500

$
1,097,800

 
 
 
 
 
 
 
 
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, 2017 and 2016 (dollars in thousands):
 
Maturity
 
Interest
 
December 31,
 
Dates (a)
 
Rates
 
2017
 
2016
APS
 
 
 
 
 

 
 

Pollution control bonds:
 
 
 
 
 

 
 

Variable
2029
 
(b)
 
$
35,975

 
$
35,975

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

 
147,150

Total pollution control bonds
 
 
 
 
183,125

 
183,125

Senior unsecured notes
2019-2046
 
2.20%-8.75%
 
4,275,000

 
3,725,000

Term loans
2018-2019
 
(c)
 
150,000

 
150,000

Unamortized discount
 
 
 
 
(11,288
)
 
(11,816
)
Unamortized premium
 
 
 
 
8,049

 
4,506

Unamortized debt issuance cost
 
 
 
 
(31,594
)
 
(29,030
)
Total APS long-term debt
 
 
 
 
4,573,292

 
4,021,785

Less current maturities

 
 
 
82,000

 
—

Total APS long-term debt less current maturities
 
 
 
 
4,491,292

 
4,021,785

Pinnacle West
 
 
 
 
 

 
 

Term loan
2017
 
(d)
 
—

 
125,000

Senior unsecured notes

2020
 
2.25%
 
300,000

 
—

Unamortized discount
 
 
 
 
(184
)
 
—

Unamortized debt issuance cost
 
 
 
 
(1,395
)
 
—

Total PNW long-term debt
 
 
 
 
298,421

 
125,000

Less current maturities
 
 
 
 
—

 
125,000

Total PNW long-term debt less current maturities
 
 
 
 
298,421

 
—

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
 
 
 
 
$
4,789,713

 
$
4,021,785

(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 1.77% at December 31, 2017 and 0.81% at December 31, 2016.
(c)
The weighted-average interest rate was 2.236% at December 31, 2017, and 1.427% at December 31, 2016.
(d)
The interest rate was 1.520% at December 31, 2016.

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
2018
 
$
82,000

 
$
82,000

2019
 
600,000

 
600,000

2020
 
550,000

 
250,000

2021
 
—

 
—

2022
 
—

 
—

Thereafter
 
3,676,125

 
3,676,125

Total
 
$
4,908,125

 
$
4,608,125

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, 2017
 
As of
December 31, 2016
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
298,421

 
$
298,608

 
$
125,000

 
$
125,000

APS
4,573,292

 
5,006,348

 
4,021,785

 
4,300,789

Total
$
4,871,713

 
$
5,304,956

 
$
4,146,785

 
$
4,425,789

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Service cost-benefits earned during the period
$
54,858

 
$
53,792

 
$
59,627

 
$
17,119

 
$
14,993

 
$
16,827

Interest cost on benefit obligation
129,756

 
131,647

 
123,983

 
29,959

 
29,721

 
28,102

Expected return on plan assets
(174,271
)
 
(173,906
)
 
(179,231
)
 
(53,401
)
 
(36,495
)
 
(36,855
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
81

 
527

 
594

 
(37,842
)
 
(37,883
)
 
(37,968
)
Net actuarial loss
47,900

 
40,717

 
31,056

 
5,118

 
4,589

 
4,881

Net periodic benefit cost
$
58,324

 
$
52,777

 
$
36,029

 
$
(39,047
)
 
$
(25,075
)
 
$
(25,013
)
Portion of cost charged to expense
$
27,295

 
$
26,172

 
$
20,036

 
$
(18,274
)
 
$
(12,435
)
 
$
(10,391
)
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 2017 and 2016 (dollars in thousands):
 
Pension
 
Other Benefits
 
2017
 
2016
 
2017
 
2016
Change in Benefit Obligation
 

 
 

 
 

 
 

Benefit obligation at January 1
$
3,204,462

 
$
3,033,803

 
$
716,445

 
$
647,020

Service cost
54,858

 
53,792

 
17,119

 
14,993

Interest cost
129,756

 
131,647

 
29,959

 
29,721

Benefit payments
(166,342
)
 
(142,247
)
 
(30,144
)
 
(26,231
)
Actuarial loss
171,452

 
127,467

 
20,014

 
50,942

Benefit obligation at December 31
3,394,186

 
3,204,462

 
753,393

 
716,445

Change in Plan Assets
 

 
 

 
 

 
 

Fair value of plan assets at January 1
2,675,357

 
2,542,774

 
882,651

 
833,017

Actual return on plan assets
428,374

 
166,408

 
139,367

 
63,463

Employer contributions
100,000

 
100,000

 
353

 
819

Benefit payments
(146,704
)
 
(133,825
)
 
—

 
(14,648
)
Fair value of plan assets at December 31
3,057,027

 
2,675,357

 
1,022,371

 
882,651

Funded Status at December 31
$
(337,159
)
 
$
(529,105
)
 
$
268,978

 
$
166,206

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, 2017 and 2016 (dollars in thousands):
 
2017
 
2016
Projected benefit obligation
$
3,394,186

 
$
3,204,462

Accumulated benefit obligation
3,227,233

 
3,049,406

Fair value of plan assets
3,057,027

 
2,675,357

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, 2017 and 2016 (dollars in thousands):
 
Pension
 
Other Benefits
 
2017
 
2016
 
2017
 
2016
Noncurrent asset
$
—

 
$
—

 
$
268,978

 
$
166,206

Current liability
(9,859
)
 
(19,795
)
 
—

 
—

Noncurrent liability
(327,300
)
 
(509,310
)
 
—

 
—

Net amount recognized
$
(337,159
)
 
$
(529,105
)
 
$
268,978

 
$
166,206

Schedule of accumulated other comprehensive loss 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2017 and 2016 (dollars in thousands): 
 
Pension
 
Other Benefits
 
2017
 
2016
 
2017
 
2016
Net actuarial loss
$
643,199

 
$
773,750

 
$
75,439

 
$
146,509

Prior service cost (credit)
—

 
81

 
(265,575
)
 
(303,417
)
APS’s portion recorded as a regulatory (asset) liability
(576,188
)
 
(711,059
)
 
189,627

 
156,575

Income tax expense (benefit)
(24,915
)
 
(24,202
)
 
853

 
833

Accumulated other comprehensive loss
$
42,096

 
$
38,570

 
$
344

 
$
500

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 2018 (dollars in thousands):
 
Pension
 
Other
Benefits
Net actuarial loss
$
28,334

 
$
—

Prior service credit
—

 
(37,842
)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018
$
28,334

 
$
(37,842
)

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,
 
2017
 
2016
 
2017
 
2016
 
2015
Discount rate – pension
3.65
%
 
4.08
%
 
4.08
%
 
4.37
%
 
4.02
%
Discount rate – other benefits
3.71
%
 
4.17
%
 
4.17
%
 
4.52
%
 
4.14
%
Rate of compensation increase
4.00
%
 
4.00
%
 
4.00
%
 
4.00
%
 
4.00
%
Expected long-term return on plan assets - pension
N/A

 
N/A

 
6.55
%
 
6.90
%
 
6.90
%
Expected long-term return on plan assets - other benefits
N/A

 
N/A

 
6.05
%
 
4.45
%
 
4.45
%
Initial healthcare cost trend rate (pre-65 participants)
7.00
%
 
7.00
%
 
7.00
%
 
7.00
%
 
7.00
%
Initial healthcare cost trend rate (post-65 participants)
4.75
%
 
5.00
%
 
5.00
%
 
5.00
%
 
5.00
%
Ultimate healthcare cost trend rate
4.75
%
 
5.00
%
 
5.00
%
 
5.00
%
 
5.00
%
Number of years to ultimate trend rate (pre-65 participants)
8

 
4

 
4

 
4

 
4

Schedule of effects of one percentage point change in the assumed initial and ultimate health care cost trend rates 
A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects on our December 31, 2017 amounts (dollars in thousands): 
 
1% Increase
 
1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
$
8,424

 
$
(5,616
)
Effect on service and interest cost components of net periodic other postretirement benefit costs
9,145

 
(7,037
)
Effect on the accumulated other postretirement benefit obligation
128,203

 
(98,143
)
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, 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 U.S. common stock equities.
(d)
These funds invest in U.S. and international common stock equities.
(e)
This category includes plan receivables and payable
The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2017:
 
Other Benefits
 
Actual Allocation
Long-term fixed income assets
67
%
Return-generating assets
33
%
Total
100
%
Based on the IPS, and given the pension plan's funded status at year-end 2017, the target and actual allocation for the pension plan at December 31, 2017 are as follows:
 
Pension
 
Target Allocation
 
Actual Allocation
Long-term fixed income assets
62
%
 
58
%
Return-generating assets
38
%
 
42
%
Total
100
%
 
100
%
The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the Plan's funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:
Asset Class
Target Allocation
Equities in US and other developed markets
18
%
Equities in emerging markets
6
%
Alternative investments
14
%
Total
38
%
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2017, 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, 2017
Pension Plan:
 

 
 

 
 
 
 

Cash and cash equivalents
$
3,830

 
$
—

 
$
—

 
$
3,830

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
1,365,194

 
—

 
1,365,194

U.S. Treasury
221,291

 
—

 
—

 
221,291

Other (b)
—

 
100,599

 
—

 
100,599

Common stock equities (c)
228,088

 
—

 
—

 
228,088

Mutual funds (d)
233,732

 
—

 
—

 
233,732

Common and collective trusts:
 
 
 
 
 
 
 
   Equities
—

 
—

 
408,763

 
408,763

   Real estate
—

 
—

 
171,569

 
171,569

   Fixed Income
—

 
—

 
90,869

 
90,869

Partnerships
—

 
—

 
133,379

 
133,379

Short-term investments and other (e)
—

 
1,208

 
98,505

 
99,713

Total
$
686,941

 
$
1,467,001

 
$
903,085

 
$
3,057,027

Other Benefits:
 

 
 

 
 

 
 

Cash and cash equivalents
$
143

 
$
—

 
$
—

 
$
143

Fixed income securities:
 

 
 

 
 
 
 

Corporate
—

 
306,008

 
—

 
306,008

U.S. Treasury
336,963

 
—

 
—

 
336,963

Other (b)
—

 
32,508

 
—

 
32,508

Common stock equities (c)
196,153

 
—

 
—

 
196,153

Mutual funds (d)
39,269

 
—

 
—

 
39,269

Common and collective trusts:
 

 
 

 
 
 
 

   Equities
—

 
—

 
75,310

 
75,310

   Real estate
—

 
—

 
15,422

 
15,422

Short-term investments and other (e)
11,268

 
149

 
9,178

 
20,595

Total
$
583,796

 
$
338,665

 
$
99,910

 
$
1,022,371

(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 U.S. common stock equities.
(d)
These funds invest in U.S. 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
2018
 
$
175,383

 
$
31,891

2019
 
181,902

 
34,000

2020
 
191,586

 
35,658

2021
 
196,583

 
37,090

2022
 
201,463

 
37,860

Years 2023-2027
 
1,068,568

 
191,207

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
2018
 
$
13,412

 
$
13,110

2019
 
11,054

 
10,802

2020
 
9,641

 
9,392

2021
 
7,105

 
6,858

2022
 
4,609

 
4,510

Thereafter
 
55,940

 
53,605

Total future lease commitments
 
$
101,761

 
$
98,277

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, 2017 (dollars in thousands):

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

 
 
 
 

 
 

 
 

 
Palo Verde Units 1 and 3
 
29.1
%
 

 
$
1,872,104

 
$
1,092,049

 
$
24,257

 
Palo Verde Unit 2 (a)
 
16.8
%
 

 
619,263

 
364,516

 
14,672

 
Palo Verde Common
 
28.0
%
 
(b)
 
726,223

 
262,065

 
46,577

 
Palo Verde Sale Leaseback
 
 

 
(a)
 
351,050

 
241,405

 
—

 
Four Corners Generating Station
 
63.0
%
 

 
1,196,683

 
568,304

 
240,514

 
Cholla common facilities (c)
 
50.5
%
 

 
180,907

 
69,633

 
1,091

 
Transmission facilities:
 
 

 
 
 
 

 
 

 
 

 
ANPP 500kV System
 
34.0
%
 
 (b)
 
130,767

 
46,400

 
684

 
Navajo Southern System
 
27.5
%
 
(b)
 
85,299

 
28,915

 
180

 
Palo Verde — Yuma 500kV System
 
18.1
%
 
(b)
 
14,765

 
6,614

 
486

 
Four Corners Switchyards
 
63.2
%
 
 (b)
 
66,386

 
12,605

 
327

 
Phoenix — Mead System
 
17.1
%
 
(b)
 
39,383

 
17,600

 
41

 
Palo Verde — Rudd 500kV System
 
50.0
%
 

 
97,600

 
23,884

 
245

 
Morgan — Pinnacle Peak System
 
64.6
%
 
 (b)
 
117,721

 
14,569

 
1

 
Round Valley System
 
50.0
%
 

 
515

 
141

 
—

 
Palo Verde — Morgan System
 
90.9
%
 
(b)
 
137,887

 
3,948

 
94,350

 
Hassayampa — North Gila System
 
80.0
%
 

 
142,541

 
6,953

 
—

 
Cholla 500kV Switchyard
 
85.7
%
 

 
5,243

 
1,312

 
190

 
Saguaro 500kV Switchyard
 
60.0
%
 

 
20,473

 
12,574

 
—

 
Kyrene — Knox System
 
50.0
%
 

 
578

 
297

 
—

 
(a)
See Note 18.
(b)
Weighted-average of interests.
(c)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp.  The common facilities at Cholla are jointly-owned.
Commitments and Contingencies (Tables)
Summary of estimated coal take-or-pay commitments 
The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):
 
 
 Years Ended December 31,
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
Coal take-or-pay commitments (a)
$
159,997

 
$
185,365

 
$
186,632

 
$
190,607

 
$
194,678

 
$
1,750,739

 
(a)
Total take-or-pay commitments are approximately $2.7 billion.  The total net present value of these commitments is approximately $1.9 billion.
Summary of actual take-or-pay commitments 
 
 
Year Ended December 31,
 
2017
 
2016
 
2015
Total purchases
$
165,220

 
$
160,066

 
$
211,327

Asset Retirement Obligations (Tables)
Change in asset retirement obligations
The following table shows the change in our asset retirement obligations for 2017 and 2016 (dollars in thousands):

 
2017
 
2016
Asset retirement obligations at the beginning of year
$
624,475

 
$
443,576

Changes attributable to:
 

 
 

Accretion expense
33,104

 
26,656

Settlements
—

 
(15,732
)
Estimated cash flow revisions
21,950

 
151,046

Newly incurred or acquired obligations
—

 
18,929

Asset retirement obligations at the end of year
$
679,529

 
$
624,475

Selected Quarterly Financial Data (Unaudited) (Tables)
Schedule of quarterly financial information 
Consolidated quarterly financial information for 2017 and 2016 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.

 
2017 Quarter Ended
 
2017
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
677,728

 
$
944,587

 
$
1,183,322

 
$
759,659

 
$
3,565,296

Operations and maintenance
219,976

 
214,013

 
224,305

 
266,149

 
924,443

Operating income
73,506

 
304,229

 
466,082

 
90,610

 
934,427

Income taxes
4,211

 
88,967

 
144,319

 
20,775

 
258,272

Net income
28,185

 
172,317

 
280,945

 
26,502

 
507,949

Net income attributable to common shareholders
23,312

 
167,443

 
276,072

 
21,629

 
488,456

 
 
 
 
 
 
 
 
 
 
Earnings Per Share:
 

 
 

 
 

 
 

 
 

Net income attributable to common shareholders — Basic
$
0.21

 
$
1.50

 
$
2.47

 
$
0.19

 
$
4.37

Net income attributable to common shareholders — Diluted
0.21

 
1.49

 
2.46

 
0.19

 
4.35

 
 
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

Schedule of quarterly financial information 
APS's quarterly financial information for 2017 and 2016 is as follows (dollars in thousands):
 
 
2017 Quarter Ended,
 
2017
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total
Operating revenues
$
676,869

 
$
942,615

 
$
1,178,106

 
$
756,549

 
$
3,554,139

Operations and maintenance
212,218

 
208,286

 
215,264

 
255,361

 
891,129

Operating income
65,468

 
212,790

 
322,053

 
79,258

 
679,569

Net income attributable to common shareholder
23,162

 
169,108

 
284,256

 
27,783

 
504,309

 
 
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

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, 2017 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, 2017
Assets
 

 
 

 
 

 
 

 
 
 
 

Cash equivalents
$
10,630

 
$
—

 
$
—

 
$
—

 
 
 
$
10,630

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
5,683

 
1,036

 
(4,737
)
 
(b)
 
1,982

Coal reclamation escrow account (c):
455

 
31,562

 
—

 
525

 
 
 
32,542

Nuclear decommissioning trust:
 

 
 

 
 

 
 
 
 
 
 

Cash and cash equivalents
7,224

 
—

 
—

 
109

 
(d)
 
7,333

U.S. commingled equity funds
—

 
—

 
—

 
417,390

 
(e)
 
417,390

Fixed income securities:
 

 
 

 
 

 
 
 
 
 
 

U.S. Treasury
127,662

 
—

 
—

 
—

 
 
 
127,662

Corporate debt
—

 
114,007

 
—

 
—

 
 
 
114,007

Mortgage-backed securities
—

 
111,874

 
—

 
—

 
 
 
111,874

Municipal bonds
—

 
79,049

 
—

 
—

 
 
 
79,049

Other
—

 
13,685

 
—

 
—

 
 
 
13,685

Subtotal nuclear decommissioning trust
134,886

 
318,615

 
—

 
417,499

 

 
871,000

Total Assets
$
145,971

 
$
355,860

 
$
1,036

 
$
413,287

 

 
$
916,154

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(78,646
)
 
$
(19,292
)
 
$
1,516

 
(b)
 
$
(96,422
)
(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents counterparty netting, margin, and collateral. See Note 16.
(c)
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. Primarily consists of fixed income municipal bonds.
(d)
Represents nuclear decommissioning trust net pending securities sales and purchases.
(e)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.


 
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 (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. Primarily consists of cash equivalents. Presented as Coal reclamation escrow in 2017.
(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.
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments 
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2017 and December 31, 2016:
 
 
December 31, 2017
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Range
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
21

 
$
15,485

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$18.51 - $38.75
 
$
27.89

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
1,015

 
3,807

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.33 - $3.11
 
$
2.71

Total
$
1,036

 
$
19,292

 
 
 
 
 
 
 
 

(a)
Includes swaps and physical and financial contracts.
 
 
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.
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, 2017 and 2016 (dollars in thousands):
 
 
 
Year Ended
December 31,
Commodity Contracts
 
2017
 
2016
Net derivative balance at beginning of period
 
$
(47,406
)
 
$
(32,979
)
Total net gains (losses) realized/unrealized:
 
 

 
 

Included in earnings
 
—

 
—

Included in OCI
 
3

 
88

Deferred as a regulatory asset or liability
 
(13,643
)
 
(37,543
)
Settlements
 
5,834

 
15,146

Transfers into Level 3 from Level 2
 
(10,026
)
 
1,900

Transfers from Level 3 into Level 2
 
46,982

 
5,982

Net derivative balance at end of period
 
$
(18,256
)
 
$
(47,406
)
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, 2017, 2016 and 2015 (in thousands, except per share amounts):
 
2017
 
2016
 
2015
Net income attributable to common shareholders
$
488,456

 
$
442,034

 
$
437,257

Weighted average common shares outstanding — basic
111,839

 
111,409

 
111,026

Net effect of dilutive securities:
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
528

 
637

 
526

Weighted average common shares outstanding — diluted
112,367

 
112,046

 
111,552

Earnings per weighted-average common share outstanding
 
 
 
 
 
Net income attributable to common shareholders - basic
$
4.37

 
$
3.97

 
$
3.94

Net Income attributable to common shareholders - diluted
$
4.35

 
$
3.95

 
$
3.92

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 2017, 2016 and 2015.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Units granted
161,963

 
141,811

 
152,651

 
147,706

 
166,666

 
151,430

Weighted-average grant date fair value
$
72.60

 
$
67.34

 
$
64.12

 
$
78.99

 
$
66.60

 
$
64.97

(a)
Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.
(b)
Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2017 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, 2017
335,259

 
$
62.04

 
312,724

 
$
65.32

Granted
161,963

 
72.60

 
147,706

 
78.99

Change in performance factor
—

 
—

 
18,266

 
64.97

Vested
(202,327
)
 
59.19

 
(164,396
)
 
63.87

Forfeited (c)
(3,607
)
 
69.58

 
(4,798
)
 
69.77

Nonvested at December 31, 2017
291,288

(a)
69.78

 
309,502

 
72.46

Vested Awards Outstanding at December 31, 2017
89,928

 


 
164,396

 


 
(a)
Includes 133,373 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, 2017 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, 2017
335,259

 
$
62.04

 
312,724

 
$
65.32

Granted
161,963

 
72.60

 
147,706

 
78.99

Change in performance factor
—

 
—

 
18,266

 
64.97

Vested
(202,327
)
 
59.19

 
(164,396
)
 
63.87

Forfeited (c)
(3,607
)
 
69.58

 
(4,798
)
 
69.77

Nonvested at December 31, 2017
291,288

(a)
69.78

 
309,502

 
72.46

Vested Awards Outstanding at December 31, 2017
89,928

 


 
164,396

 


 
(a)
Includes 133,373 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 2017, 2016 and 2015.

 
Restricted Stock Units, Stock Grants, and Stock Units (a)
 
Performance Shares (b)
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Units granted
161,963

 
141,811

 
152,651

 
147,706

 
166,666

 
151,430

Weighted-average grant date fair value
$
72.60

 
$
67.34

 
$
64.12

 
$
78.99

 
$
66.60

 
$
64.97

(a)
Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.
(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, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
 
 
 
Quantity
Commodity
 
Unit of Measure
December 31, 2017
 
December 31, 2016
Power
 
GWh
583

 
1,314

Gas
 
Billion cubic feet
240

 
194

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, 2017, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2017
 
2016
 
2015
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(59
)
 
$
47

 
$
(615
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(3,519
)
 
(3,926
)
 
(5,988
)
(a)
During the years ended December 31, 2017, 2016, and 2015, 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, 2017, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement 
 
Year Ended
December 31,
Commodity Contracts
 
Location
 
2017
 
2016
 
2015
Net Gain (Loss) Recognized in Income
 
Operating revenues
 
$
(1,192
)
 
$
771

 
$
574

Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
(87,991
)
 
25,711

 
(108,973
)
Total
 
 
 
$
(89,183
)
 
$
26,482

 
$
(108,399
)
(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, 2017 and 2016.  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, 2017:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
5,427

 
$
(3,796
)
 
$
1,631

 
$
300

 
$
1,931

Investments and other assets
 
1,292

 
(1,241
)
 
51

 
—

 
51

Total assets
 
6,719

 
(5,037
)
 
1,682

 
300

 
1,982

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(59,527
)
 
3,796

 
(55,731
)
 
(3,521
)
 
(59,252
)
Deferred credits and other
 
(38,411
)
 
1,241

 
(37,170
)
 
—

 
(37,170
)
Total liabilities
 
(97,938
)
 
5,037

 
(92,901
)
 
(3,521
)
 
(96,422
)
Total
 
$
(91,219
)
 
$
—

 
$
(91,219
)
 
$
(3,221
)
 
$
(94,440
)
(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 $3,521 and cash margin provided to counterparties of $300.
 
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
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, 2017 and 2016.  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, 2017:
(dollars in thousands)
 
Gross 
Recognized 
Derivatives
 (a)
 
Amounts 
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount 
Reported on 
Balance Sheet
Current assets
 
$
5,427

 
$
(3,796
)
 
$
1,631

 
$
300

 
$
1,931

Investments and other assets
 
1,292

 
(1,241
)
 
51

 
—

 
51

Total assets
 
6,719

 
(5,037
)
 
1,682

 
300

 
1,982

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(59,527
)
 
3,796

 
(55,731
)
 
(3,521
)
 
(59,252
)
Deferred credits and other
 
(38,411
)
 
1,241

 
(37,170
)
 
—

 
(37,170
)
Total liabilities
 
(97,938
)
 
5,037

 
(92,901
)
 
(3,521
)
 
(96,422
)
Total
 
$
(91,219
)
 
$
—

 
$
(91,219
)
 
$
(3,221
)
 
$
(94,440
)
(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 $3,521 and cash margin provided to counterparties of $300.
 
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.

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, 2017 (dollars in thousands):
 
 
December 31, 2017
Aggregate fair value of derivative instruments in a net liability position
$
97,938

Cash collateral posted
—

Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)
91,071

(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 2017, 2016 and 2015 (dollars in thousands):
 
 
2017
 
2016
 
2015
Other income:
 

 
 

 
 

Interest income
$
3,497

 
$
884

 
$
493

Miscellaneous
509

 
17

 
128

Total other income
$
4,006

 
$
901

 
$
621

Other expense:
 

 
 

 
 

Non-operating costs
$
(11,749
)
 
$
(9,235
)
 
$
(11,292
)
Investment losses — net
(4,113
)
 
(1,747
)
 
(2,080
)
Miscellaneous
(5,677
)
 
(4,355
)
 
(4,451
)
Total other expense
$
(21,539
)
 
$
(15,337
)
 
$
(17,823
)
Detail of other income and other expense 
The following table provides detail of APS’s other income and other expense for 2017, 2016 and 2015 (dollars in thousands):
 
 
2017
 
2016
 
2015
Other income:
 

 
 

 
 

Interest income
$
2,858

 
$
261

 
$
163

Gain on disposition of property
2,048

 
5,745

 
716

Miscellaneous
1,620

 
2,601

 
1,955

Total other income
$
6,526

 
$
8,607

 
$
2,834

Other expense:
 

 
 

 
 

Non-operating costs (a)
$
(12,395
)
 
$
(11,034
)
 
$
(11,648
)
Loss on disposition of property
(5,424
)
 
(1,246
)
 
(2,219
)
Miscellaneous
(5,561
)
 
(5,234
)
 
(5,152
)
Total other expense
$
(23,380
)
 
$
(17,514
)
 
$
(19,019
)
(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, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
December 31, 2017
 
December 31, 2016
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation
$
109,645

 
$
113,515

Equity-Noncontrolling interests
129,040

 
132,290

Investments (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, 2017 and December 31, 2016 (dollars in thousands):
 
 
December 31, 2017
 
December 31, 2016
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
 
Fair Value
 
Total 
Unrealized 
Gains
 
Total 
Unrealized 
Losses
Equity securities
$
417,390

 
$
248,623

 
$
—

 
$
353,261

 
$
188,091

 
$
—

Fixed income securities
446,277

 
11,537

 
(2,996
)
 
425,530

 
9,820

 
(4,962
)
Cash and cash equivalents
7,224

 
—

 
—

 
—

 
—

 
—

Net receivables (a)
109

 
—

 
—

 
795

 
—

 
—

Total
$
871,000

 
$
260,160

 
$
(2,996
)
 
$
779,586

 
$
197,911

 
$
(4,962
)
(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):
 
 
Nuclear Decommissioning

 
Year Ended December 31,
 
2017
 
2016
 
2015
Realized gains
$
21,813

 
$
11,213

 
$
5,189

Realized losses
(13,146
)
 
(10,106
)
 
(6,225
)
Proceeds from the sale of securities (a)
542,246

 
633,410

 
478,813

(a)
Proceeds are reinvested in the trust/account.

Fair value of fixed income securities, summarized by contractual maturities 
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2017 is as follows (dollars in thousands):
 
 
Nuclear Decommissioning Trusts
 
Escrow Accounts
 
Total
Less than one year
$
24,668

 
$
455

 
$
25,123

1 year – 5 years
100,289

 
2,494

 
102,783

5 years – 10 years
129,239

 
8,615

 
137,854

Greater than 10 years
192,081

 
20,453

 
212,534

Total
$
446,277

 
$
32,017

 
$
478,294

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, 2017 and 2016 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
Total
Balance December 31, 2015
$
(37,593
)
 

 
$
(7,155
)
 

 
$
(44,748
)
OCI (loss) before reclassifications
(4,509
)
 

 
(538
)
 

 
(5,047
)
Amounts reclassified from accumulated other comprehensive loss
3,032

 
(a)
 
2,941

 
(b)
 
5,973

Balance December 31, 2016
(39,070
)
 

 
(4,752
)
 

 
(43,822
)
OCI (loss) before reclassifications
(6,438
)
 

 
(35
)
 

 
(6,473
)
Amounts reclassified from accumulated other comprehensive loss
3,068

 
(a)
 
2,225

 
(b)
 
5,293

Balance December 31, 2017
$
(42,440
)
 

 
$
(2,562
)
 

 
$
(45,002
)
(a)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
(b)
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.
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, 2017 and 2016 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
Total
Balance December 31, 2015
$
(19,942
)
 

 
$
(7,155
)
 

 
$
(27,097
)
OCI (loss) before reclassifications
(3,821
)
 

 
(538
)
 

 
(4,359
)
Amounts reclassified from accumulated other comprehensive loss
3,092

 
(a)
 
2,941

 
(b)
 
6,033

Balance December 31, 2016
(20,671
)
 

 
(4,752
)
 

 
(25,423
)
OCI (loss) before reclassifications
(6,884
)
 

 
(35
)
 

 
(6,919
)
Amounts reclassified from accumulated other comprehensive loss
3,134

 
(a)
 
2,225

 
(b)
 
5,359

Balance December 31, 2017
$
(24,421
)
 

 
$
(2,562
)
 

 
$
(26,983
)
(a)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.
(b)
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.
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, 2017
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2017
Pinnacle West
May 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Minimum
Dec. 31, 2017
Maximum
Dec. 31, 2017
Maximum
Dec. 31, 2017
Fossil plant
Dec. 31, 2017
Nuclear plant
Dec. 31, 2017
Other generation
Dec. 31, 2017
Transmission
Dec. 31, 2017
Distribution
Dec. 31, 2017
General plant
Dec. 31, 2017
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 (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
7.00% 
Approximate remaining average useful lives of utility property
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average useful life
 
 
 
 
 
 
 
 
 
21 years 
26 years 
25 years 
38 years 
33 years 
6 years 
 
 
Cost of services, depreciation
$ 453 
$ 422 
$ 430 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation rates (as a percent)
2.80% 
2.66% 
2.74% 
 
 
 
0.18% 
 
16.44% 
 
 
 
 
 
 
 
 
Allowance for Funds Used During Construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Composite rate used to calculate AFUDC (as a percent)
6.68% 
7.17% 
8.02% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
72 
58 
58 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated amortization expense on existing intangible assets over the next five years
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
53 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
38 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
28 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2021
22 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2022
$ 17 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
10,000,000 
 
15,535,000 
 
 
 
 
 
 
 
 
 
 
 
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 $)
Dec. 31, 2017
Dec. 31, 2016
Pension and other postretirement benefits
 
$ 0 
Derivative instruments
 
0 
Total accumulated other comprehensive loss
 
0 
Accumulated other comprehensive loss
(45,002,000)
(43,822,000)
As previously reported
 
 
Pension and other postretirement benefits
 
(39,070,000)
Derivative instruments
 
(4,752,000)
Total accumulated other comprehensive loss
 
(43,822,000)
Accumulated other comprehensive loss
 
0 
Reclassifications to conform to current year presentation
 
 
Pension and other postretirement benefits
 
39,070,000 
Derivative instruments
 
4,752,000 
Total accumulated other comprehensive loss
 
43,822,000 
Accumulated other comprehensive loss
 
(43,822,000)
ARIZONA PUBLIC SERVICE COMPANY
 
 
Pension and other postretirement benefits
 
0 
Derivative instruments
 
0 
Total accumulated other comprehensive loss
 
0 
Accumulated other comprehensive loss
(26,983,000)
(25,423,000)
ARIZONA PUBLIC SERVICE COMPANY |
As previously reported
 
 
Pension and other postretirement benefits
 
(20,671,000)
Derivative instruments
 
(4,752,000)
Total accumulated other comprehensive loss
 
(25,423,000)
Accumulated other comprehensive loss
 
0 
ARIZONA PUBLIC SERVICE COMPANY |
Reclassifications to conform to current year presentation
 
 
Pension and other postretirement benefits
 
20,671,000 
Derivative instruments
 
4,752,000 
Total accumulated other comprehensive loss
 
25,423,000 
Accumulated other comprehensive loss
 
$ (25,423,000)
Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Utility Plant and Depreciation [Line Items]
 
 
Net
$ 11,669,526 
$ 11,371,788 
Construction work in progress
1,291,498 
1,019,947 
Palo Verde sale leaseback, net of accumulated depreciation
109,645 
113,515 
Intangible assets, net of accumulated amortization
257,189 
90,022 
Nuclear fuel, net of accumulated amortization
117,408 
119,004 
Total property, plant and equipment
13,445,266 
12,714,276 
Electric Service
 
 
Utility Plant and Depreciation [Line Items]
 
 
Generation
7,963,998 
7,874,898 
Transmission
2,836,578 
2,746,508 
Distribution
6,025,856 
5,738,801 
General plant
971,629 
981,681 
Plant in service and held for future use
17,798,061 
17,341,888 
Accumulated depreciation and amortization
(6,128,535)
(5,970,100)
Net
11,669,526 
11,371,788 
Construction work in progress
1,291,498 
1,019,947 
Palo Verde sale leaseback, net of accumulated depreciation
109,645 
113,515 
Intangible assets, net of accumulated amortization
257,189 
90,022 
Nuclear fuel, net of accumulated amortization
117,408 
119,004 
Total property, plant and equipment
$ 13,445,266 
$ 12,714,276 
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Accounting Policies [Abstract]
 
 
 
Income tax (benefit), net of refunds
$ 2,186 
$ 9,956 
$ 6,550 
Interest, net of amounts capitalized
189,288 
184,462 
170,209 
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
 
 
 
Accrued capital expenditures
130,404 
114,855 
83,798 
Dividends declared but not paid
$ 77,667 
$ 72,926 
$ 69,363 
New Accounting Standards (Details) (Accounting Standards Update 2017-07, Scenario, Forecast, USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2018
Accounting Standards Update 2017-07 |
Scenario, Forecast
 
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
 
Net benefit costs capitalized
$ 15,000 
Regulatory Matters Regulatory Matters - Retail Rate Case Filing (Details) (Retail Rate Case Filing with Arizona Corporation Commission, ACC, ARIZONA PUBLIC SERVICE COMPANY, USD $)
0 Months Ended
Nov. 13, 2017
Mar. 27, 2017
Mar. 26, 2017
Jun. 1, 2016
Dec. 31, 2015
Jun. 1, 2011
Mar. 27, 2017
AZ Sun II Program
Jan. 3, 2018
Subsequent Event
Customer
Public Utilities, General Disclosures [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
 
3.28% 
 
5.74% 
 
 
 
 
Approximate percentage of increase in average residential customer bill
 
4.54% 
 
7.96% 
 
 
 
 
Settlement agreement, net retail base rate increase
 
94,600,000 
 
 
 
 
 
 
Settlement agreement, non-fuel, non-depreciation, base rate increase
 
87,200,000 
 
 
 
 
 
 
Fuel-related base rate decrease
 
53,600,000 
 
 
 
 
 
 
Base rate increase, changes in depreciation schedules
 
61,000,000 
 
 
 
 
 
 
Authorized return on common equity (as a percent)
 
10.00% 
 
 
 
 
 
 
Percentage of debt in capital structure
 
44.20% 
 
 
 
 
 
 
Percentage of common equity in capital structure
 
55.80% 
 
 
 
 
 
 
Minimum annual renewable energy standard and tariff
 
 
 
 
 
 
10,000,000 
 
Maximum annual renewable energy standard and tariff
 
 
 
 
 
 
15,000,000 
 
Environmental surcharge cap rate (in dollars per kWh)
 
0.00050 
0.00016 
 
 
 
 
 
Resource comparison proxy for exported energy (in dollars per kWh)
 
0.129 
 
 
 
 
 
 
Monthly metering infrastructure opt-out fee
$ 5 
 
 
 
 
 
 
 
Number of customers which signed complaint
 
 
 
 
 
 
 
25 
Regulatory Matters - Narrative (Details) (USD $)
12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 1 Months Ended 0 Months Ended 2 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended
Dec. 31, 2017
APS
Jan. 13, 2017
APS
Lost Fixed Cost Recovery Mechanism
Jan. 15, 2016
APS
Lost Fixed Cost Recovery Mechanism
Dec. 31, 2017
APS
Lost Fixed Cost Recovery Mechanism
Dec. 31, 2012
APS
Lost Fixed Cost Recovery Mechanism
Jun. 1, 2016
APS
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Jan. 1, 2016
APS
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Jun. 1, 2011
APS
ACC
Retail Rate Case Filing with Arizona Corporation Commission
Dec. 31, 2017
APS
ACC
Arizona Renewable Energy Standard and Tariff
Jul. 1, 2016
APS
ACC
Arizona Renewable Energy Standard and Tariff 2017
Jun. 30, 2017
APS
ACC
Arizona Renewable Energy Standard and Tariff 2018
Sep. 30, 2016
APS
ACC
Modernization and Expansion of the Renewal Energy Standard
Nov. 25, 2015
APS
ACC
2015 DSMAC
Mar. 20, 2015
APS
ACC
2015 DSMAC
project
Jan. 27, 2017
APS
ACC
2017 DSMAC
Jun. 1, 2016
APS
ACC
2017 DSMAC
Nov. 14, 2017
APS
ACC
Demand Side Management Adjustor Charge 2018
Sep. 1, 2017
APS
ACC
Demand Side Management Adjustor Charge 2018
Nov. 4, 2014
APS
ACC
Electric Energy Efficiency Standard
Apr. 30, 2014
APS
ACC
Electric Energy Efficiency Standard
workshop
Aug. 19, 2017
APS
ACC
Power Supply Adjustor (PSA)
Feb. 1, 2017
APS
ACC
Power Supply Adjustor (PSA)
Dec. 20, 2016
APS
ACC
Net Metering
Jun. 1, 2017
APS
FERC
Transmission rates, transmission cost adjustor and other transmission matters
Jun. 1, 2016
APS
FERC
Transmission rates, transmission cost adjustor and other transmission matters
Feb. 1, 2016
Cost Recovery Mechanisms
APS
ACC
Power Supply Adjustor (PSA)
Feb. 1, 2015
Cost Recovery Mechanisms
APS
ACC
Power Supply Adjustor (PSA)
Feb. 9, 2018
Subsequent Event
Feb. 15, 2018
Subsequent Event
APS
Lost Fixed Cost Recovery Mechanism
Feb. 22, 2018
Subsequent Event
APS
ACC
Jan. 8, 2018
Subsequent Event
APS
ACC
Feb. 1, 2018
Subsequent Event
APS
ACC
Power Supply Adjustor (PSA)
Dec. 31, 2014
Alternative to AZ Sun Program, Phase 1
APS
Arizona Renewable Energy Standard and Tariff 2014
MW
Dec. 31, 2014
Solar Partner Program Phase 2
APS
Arizona Renewable Energy Standard and Tariff 2014
storage_system
penetration_feeder
MW
Nov. 20, 2017
Solar Communities
APS
ACC
Arizona Renewable Energy Standard and Tariff 2018
Nov. 20, 2017
Minimum
Solar Communities
APS
ACC
Arizona Renewable Energy Standard and Tariff 2018
Nov. 20, 2017
Maximum
Solar Communities
APS
ACC
Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net retail rate increase
 
 
 
 
 
$ 165,900,000 
 
$ 95,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter additional capacity from AZ Sun projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8 
2 
 
 
 
Solar storage system, capacity (in MW)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
Number of energy storage systems
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
Number of high solar penetration feeders
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
Amount of approved budget
 
 
 
 
 
 
 
 
 
150,000,000 
 
 
68,900,000 
 
66,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of proposed budget
 
 
 
 
 
 
 
 
 
 
90,000,000 
 
 
 
 
62,600,000 
52,600,000 
52,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Program term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
Required annual capital investment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10,000,000 
15,000,000 
Proposed renewal energy standard, percent of retail sales
 
 
 
 
 
 
 
 
 
 
 
30.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current renewal energy standard, percent of retail sales
 
 
 
 
 
 
 
 
 
 
 
15.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.000555 
(0.001348)
 
 
 
 
 
 
 
 
 
0.004555 
 
 
 
 
 
PSA Rate in Prior Years
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001678 
 
 
 
 
 
 
 
 
 
 
 
Forward component of PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.000876 
(0.001027)
 
 
 
 
 
 
 
 
 
0.002009 
 
 
 
 
 
Historical component of PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.000321)
(0.000321)
 
 
 
 
 
 
 
 
 
0.002546 
 
 
 
 
 
Increase (decrease) in annual wholesale transmission rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
35,100,000 
24,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed costs recoverable per residential power lost (in dollars per kWh)
 
 
 
 
0.031 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed costs recoverable per non-residential power lost (in dollars per kWh)
 
 
 
 
0.023 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed costs recoverable per power lost (in dollars per kWh)
 
 
 
0.025 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter cap percentage of retail revenue
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of adjustment approved representing prorated sales losses
 
63,700,000 
46,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in amount of adjustment representing prorated sales losses
 
17,300,000 
7,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,000,000 
 
 
 
 
 
 
 
 
Amount of adjustment approved representing prorated sales losses pending approval
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
60,700,000 
 
 
 
 
 
 
 
 
Requested rate decrease for tax act
(377,000,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
119,100,000 
 
 
 
 
 
 
Approved rate decrease for tax act
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
119,100,000 
 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Guaranteed export price period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Settlement agreement, energy price for exported energy (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.129 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reduced system benefits charge, amount
 
 
 
 
 
 
$ 14,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plan term
 
 
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter number of resource savings projects
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ballot initiative, proposed required energy supply to be obtained from renewable sources (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
$ 48,405 
$ 60,303 
$ (14,997)
Deferred fuel and purchased power amortization
14,767 
(38,152)
(1,617)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Change in regulatory asset
 
 
 
Deferred fuel and purchased power
48,405 
60,303 
(14,997)
Deferred fuel and purchased power amortization
14,767 
(38,152)
(1,617)
ACC |
ARIZONA PUBLIC SERVICE COMPANY |
Power Supply Adjustor (PSA)
 
 
 
Change in regulatory asset
 
 
 
Beginning balance
12,465 
(9,688)
 
Deferred fuel and purchased power
48,405 
60,303 
 
Deferred fuel and purchased power amortization
14,767 
(38,150)
 
Ending balance
$ 75,637 
$ 12,465 
 
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) (APS, USD $)
In Millions, unless otherwise specified
3 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2017
Retired power plant costs
Dec. 31, 2017
Navajo Plant
Jun. 30, 2016
SCE
Four Corners
Dec. 31, 2015
SCE
Four Corners
Dec. 23, 2014
Four Corners Units 4 and 5
SCE
Dec. 30, 2013
Four Corners Units 4 and 5
SCE
Dec. 30, 2013
Four Corners Units 4 and 5
SCE
Dec. 31, 2017
Four Corners Units 4 and 5
SCE
Four Corners cost deferral
Acquisition
 
 
 
 
 
 
 
 
Ownership interest acquired (as a percent)
 
 
 
 
 
 
48.00% 
 
Settlement agreement, ACC approved rate adjustment, annualized customer impact
 
 
 
 
$ 57.1 
 
 
 
Regulatory assets
 
 
 
12 
 
 
 
56 
Amortization period
 
 
 
 
 
 
 
10 years 
Transmission termination agreement net receipt due to negotiation of alternate arrangement
 
 
 
 
 
40 
 
 
Regulatory assets, write of amount
 
 
12 
 
 
 
 
 
Regulatory asset, net book value
$ 105 
$ 99 
 
 
 
 
 
 
Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Detail of regulatory assets
 
 
Regulatory assets, current
$ 248,088 
$ 106,875 
Regulatory assets, non-current
1,202,302 
1,313,428 
Pension
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
576,188 
711,059 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
27,402 
9,913 
Regulatory assets, non-current
188,843 
117,591 
Income taxes - AFUDC equity
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
3,828 
6,305 
Regulatory assets, non-current
142,852 
152,118 
Deferred fuel and purchased power - mark-to-market
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
52,100 
0 
Regulatory assets, non-current
34,845 
42,963 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,077 
6,689 
Regulatory assets, non-current
48,305 
56,894 
Income taxes — investment tax credit basis adjustment
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,066 
2,120 
Regulatory assets, non-current
26,218 
54,356 
Lost fixed cost recovery
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
59,844 
61,307 
Regulatory assets, non-current
0 
0 
Palo Verde VIE
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
19,395 
18,775 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
36,413 
35,595 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,569 
0 
Regulatory assets, non-current
74,926 
73,200 
Loss on reacquired debt
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,637 
1,637 
Regulatory assets, non-current
15,305 
16,942 
AG-1 deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,654 
0 
Regulatory assets, non-current
8,472 
5,868 
Demand side management
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
3,744 
Regulatory assets, non-current
0 
0 
Tax expense of Medicare subsidy
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,236 
1,513 
Regulatory assets, non-current
7,415 
10,589 
Mead-Phoenix transmission line CIAC
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
332 
332 
Regulatory assets, non-current
10,376 
10,708 
Deferred fuel and purchased power
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
75,637 
12,465 
Regulatory assets, non-current
0 
0 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,068 
418 
Regulatory assets, non-current
12,396 
5,182 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
4,638 
432 
Regulatory assets, non-current
$ 353 
$ 1,588 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 100,086 
$ 99,899 
Regulatory liabilities, non-current
2,452,536 
948,916 
Excess deferred income taxes - Tax Cuts and Jobs Act
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
1,520,274 
0 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
332,171 
279,976 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
18,238 
29,899 
Regulatory liabilities, non-current
209,191 
223,145 
Other post retirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
37,642 
32,662 
Regulatory liabilities, non-current
151,985 
123,913 
Income taxes - deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,164 
4,368 
Regulatory liabilities, non-current
52,497 
108,827 
Income taxes - change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,573 
1,771 
Regulatory liabilities, non-current
70,537 
70,898 
Spent nuclear fuel
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
6,924 
0 
Regulatory liabilities, non-current
62,132 
71,726 
Renewable energy program
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
23,155 
26,809 
Regulatory liabilities, non-current
0 
0 
Demand side management
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
3,066 
0 
Regulatory liabilities, non-current
4,921 
20,472 
Sundance maintenance
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
16,897 
15,287 
Deferred gains on utility property
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
4,423 
2,063 
Regulatory liabilities, non-current
10,988 
8,895 
Four Corners coal reclamation
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
1,858 
0 
Regulatory liabilities, non-current
18,921 
18,248 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
43 
2,327 
Regulatory liabilities, non-current
$ 2,022 
$ 7,529 
Income Taxes (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Income Taxes
 
 
Reduction in net deferred income tax liabilities
$ 1,140,000,000 
 
Regulatory liabilities, non-current
2,452,536,000 
948,916,000 
Income tax expense recognized for tax reform
9,300,000 
 
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less than)
1,000,000 
 
General business tax credit carryforwards that will begin to expire in 2031
79,000,000 
 
Amount of federal and state loss carryforwards which will begin to expire in 2019
6,000,000 
 
increase (decrease) in deferred income taxes due to regulation adoption
31,000,000 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Income Taxes
 
 
Reduction in net deferred income tax liabilities
1,140,000,000 
 
Regulatory liabilities, non-current
2,452,536,000 
948,916,000 
Gross-up for revenue requirement of rate regulation
377,000,000 
 
Palo Verde VIE
 
 
Income Taxes
 
 
Income tax expense benefit attributable to non controlling interests
0 
 
Excess deferred income taxes - Tax Cuts and Jobs Act
 
 
Income Taxes
 
 
Regulatory liabilities, non-current
1,520,274,000 
0 
Excess deferred income taxes - Tax Cuts and Jobs Act |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Income Taxes
 
 
Regulatory liabilities, non-current
$ 1,520,000,000 
 
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
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
$ 36,075 
$ 34,447 
$ 44,775 
Additions for tax positions of the current year
2,937 
2,695 
2,175 
Additions for tax positions of prior years
4,783 
886 
0 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(1,829)
(1,953)
(10,244)
Settlements with taxing authorities
0 
0 
0 
Lapses of applicable statute of limitations
0 
0 
(2,259)
Total unrecognized tax benefits, end of the year
41,966 
36,075 
34,447 
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
36,075 
34,447 
44,775 
Additions for tax positions of the current year
2,937 
2,695 
2,175 
Additions for tax positions of prior years
4,783 
886 
0 
Reductions for tax positions of prior years for:
 
 
 
Changes in judgment
(1,829)
(1,953)
(10,244)
Settlements with taxing authorities
0 
0 
0 
Lapses of applicable statute of limitations
0 
0 
(2,259)
Total unrecognized tax benefits, end of the year
$ 41,966 
$ 36,075 
$ 34,447 
Income Taxes - Summary of Unrecognized Tax Benefits (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Income Tax [Line Items]
 
 
 
Tax positions, that if recognized, would decrease our effective tax rate
$ 16,373,000 
$ 11,313,000 
$ 9,523,000 
Unrecognized tax benefit interest expense/(benefit) recognized
577,000 
529,000 
(161,000)
Unrecognized tax benefit interest accrued
1,910,000 
1,333 
804 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Income Tax [Line Items]
 
 
 
Tax positions, that if recognized, would decrease our effective tax rate
16,373,000 
11,313,000 
9,523,000 
Unrecognized tax benefit interest expense/(benefit) recognized
577,000 
529,000 
(161,000)
Unrecognized tax benefit interest accrued
$ 1,910 
$ 1,333 
$ 804 
Income Taxes - Components of Income Tax Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2017
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
$ 11,624 
$ 8,630 
$ (12,335)
State
 
 
 
 
 
 
 
 
3,052 
1,259 
4,763 
Total current
 
 
 
 
 
 
 
 
14,676 
9,889 
(7,572)
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
223,729 
201,743 
221,505 
State
 
 
 
 
 
 
 
 
19,867 
24,779 
23,787 
Total deferred
 
 
 
 
 
 
 
 
243,596 
226,522 
245,292 
Income tax expense
20,775 
144,319 
88,967 
4,211 
27,309 
141,446 
65,742 
1,914 
258,272 
236,411 
237,720 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
21,512 
711 
6,485 
State
 
 
 
 
 
 
 
 
2,778 
4,276 
7,813 
Total current
 
 
 
 
 
 
 
 
24,290 
4,987 
14,298 
Deferred:
 
 
 
 
 
 
 
 
 
 
 
Federal
 
 
 
 
 
 
 
 
221,078 
215,178 
208,326 
State
 
 
 
 
 
 
 
 
23,800 
25,677 
23,217 
Total deferred
 
 
 
 
 
 
 
 
244,878 
240,855 
231,543 
Income tax expense
 
 
 
 
 
 
 
 
$ 269,168 
$ 245,842 
$ 245,841 
Income Taxes - Effective Tax Rate Reconciliation (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2017
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
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
 
 
 
 
 
 
 
 
$ 268,177 
$ 244,278 
$ 242,869 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
14,897 
16,311 
18,265 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
0 
0 
(2,169)
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
853 
844 
837 
Stock compensation
 
 
 
 
 
 
 
 
(6,659)
(2,951)
0 
Excess Deferred Income Taxes - Tax Cuts and Jobs Act
 
 
 
 
 
 
 
 
9,348 
0 
0 
Allowance for equity funds used during construction (see Note 1)
 
 
 
 
 
 
 
 
(12,937)
(11,724)
(9,711)
Palo Verde VIE noncontrolling interest (see Note 18)
 
 
 
 
 
 
 
 
(6,823)
(6,823)
(6,626)
Investment tax credit amortization
 
 
 
 
 
 
 
 
(6,715)
(5,887)
(5,527)
Other
 
 
 
 
 
 
 
 
(1,869)
2,363 
(218)
Income tax expense
20,775 
144,319 
88,967 
4,211 
27,309 
141,446 
65,742 
1,914 
258,272 
236,411 
237,720 
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
 
 
 
 
 
 
 
 
277,540 
254,617 
250,267 
State income tax net of federal income tax benefit
 
 
 
 
 
 
 
 
17,276 
18,750 
20,433 
Credits and favorable adjustments related to prior years resolved in current year
 
 
 
 
 
 
 
 
0 
0 
(1,892)
Medicare Subsidy Part-D
 
 
 
 
 
 
 
 
853 
844 
837 
Stock compensation
 
 
 
 
 
 
 
 
(3,489)
(1,937)
0 
Excess Deferred Income Taxes - Tax Cuts and Jobs Act
 
 
 
 
 
 
 
 
9,431 
0 
0 
Allowance for equity funds used during construction (see Note 1)
 
 
 
 
 
 
 
 
(12,937)
(11,724)
(9,711)
Palo Verde VIE noncontrolling interest (see Note 18)
 
 
 
 
 
 
 
 
(6,823)
(6,823)
(6,626)
Investment tax credit amortization
 
 
 
 
 
 
 
 
(6,715)
(5,887)
(5,527)
Other
 
 
 
 
 
 
 
 
(5,968)
(1,998)
(1,940)
Income tax expense
 
 
 
 
 
 
 
 
$ 269,168 
$ 245,842 
$ 245,841 
Income Taxes - Components of Deferred Income Tax Liability (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
DEFERRED TAX ASSETS
 
 
Risk management activities
$ 25,103 
$ 26,614 
Regulatory liabilities:
 
 
Excess Deferred Income Taxes - Tax Cuts and Jobs Act
376,906 
0 
Asset retirement obligation and removal costs
135,847 
200,140 
Unamortized investment tax credits
54,661 
113,195 
Other postretirement liabilities
47,021 
60,375 
Other
37,489 
63,311 
Pension liabilities
83,126 
204,436 
Renewable energy incentives
33,546 
56,379 
Credit and loss carryforwards
53,946 
75,944 
Other
102,432 
158,421 
Total deferred tax assets
950,077 
958,815 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(2,220,886)
(3,297,989)
Risk management activities
(491)
(7,594)
Other postretirement assets
(66,134)
(63,477)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(36,365)
(61,088)
Deferred fuel and purchased power — mark-to-market
(40,778)
(21,396)
Pension benefits
(142,848)
(274,184)
Retired power plant costs (see Note 3)
(53,611)
(49,166)
Other
(74,423)
(123,987)
Other
(5,346)
(5,166)
Total deferred tax liabilities
(2,640,882)
(3,904,047)
Deferred income taxes — net
(1,690,805)
(2,945,232)
ARIZONA PUBLIC SERVICE COMPANY
 
 
DEFERRED TAX ASSETS
 
 
Risk management activities
25,103 
26,614 
Regulatory liabilities:
 
 
Excess Deferred Income Taxes - Tax Cuts and Jobs Act
376,906 
0 
Asset retirement obligation and removal costs
135,847 
200,140 
Unamortized investment tax credits
54,661 
113,195 
Other postretirement liabilities
47,021 
60,375 
Other
37,489 
63,311 
Pension liabilities
77,280 
194,981 
Renewable energy incentives
33,546 
56,379 
Credit and loss carryforwards
1,920 
1,645 
Other
108,223 
187,453 
Total deferred tax assets
897,996 
904,093 
DEFERRED TAX LIABILITIES
 
 
Plant-related
(2,220,886)
(3,297,989)
Risk management activities
(491)
(7,594)
Other postretirement assets
(65,733)
(62,819)
Regulatory assets:
 
 
Allowance for equity funds used during construction
(36,365)
(61,088)
Deferred fuel and purchased power — mark-to-market
(40,778)
(21,396)
Pension benefits
(142,848)
(274,184)
Retired power plant costs (see Note 3)
(53,611)
(49,166)
Other
(74,423)
(123,987)
Other
(5,346)
(5,165)
Total deferred tax liabilities
(2,640,481)
(3,903,388)
Deferred income taxes — net
$ (1,742,485)
$ (2,999,295)
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
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
$ 1,325,000,000 
$ 1,275,000,000 
Commercial paper
(95,400,000)
(177,200,000)
Unused amount
1,229,600,000 
1,097,800,000 
Revolving credit facility |
Pinnacle West
 
 
Lines of Credit and Short-Term Borrowings
 
 
Amount committed
325,000,000 
275,000,000 
Commercial paper
(95,400,000)
(41,700,000)
Unused amount
229,600,000 
233,300,000 
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
0 
(135,500,000)
Unused amount
$ 1,000,000,000 
$ 864,500,000 
Lines of Credit and Short-Term Borrowings (Details) (USD $)
12 Months Ended 0 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2017
Pinnacle West
Dec. 31, 2016
Pinnacle West
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 15, 2016
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 5, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 31, 2017
Revolving credit facility
Dec. 31, 2016
Revolving credit facility
Dec. 31, 2017
Revolving credit facility
Pinnacle West
Dec. 31, 2016
Revolving credit facility
Pinnacle West
Aug. 31, 2016
Revolving credit facility
Pinnacle West
Revolving credit facility maturing August 2017
Dec. 31, 2017
Revolving credit facility
Pinnacle West
Revolving credit facility maturing July 2018
Jul. 31, 2017
Revolving credit facility
Pinnacle West
Revolving credit facility maturing July 2018
Dec. 31, 2017
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, 2017
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Jun. 29, 2017
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing September 2020
Dec. 31, 2017
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing June 2022
Jun. 29, 2017
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing June 2022
Dec. 31, 2017
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing in 2021 and 2022
Facility
Dec. 31, 2017
Revolving credit facility
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facility maturing May 2021
Dec. 31, 2017
Letter of credit
Pinnacle West
Revolving credit facility maturing May 2021
Dec. 31, 2017
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Commercial paper
Pinnacle West
Revolving credit facility maturing May 2021
Dec. 31, 2017
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Commercial paper
ARIZONA PUBLIC SERVICE COMPANY
Revolving credit facilities maturing in 2021 and 2022
Jul. 31, 2017
LIBOR
Revolving credit facility
Pinnacle West
Revolving credit facility maturing July 2018
Lines of Credit and Short-Term Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount committed
 
 
 
 
 
 
 
 
 
$ 1,325,000,000 
$ 1,275,000,000 
$ 325,000,000 
$ 275,000,000 
 
 
 
 
$ 200,000,000 
$ 1,000,000,000 
$ 1,000,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
$ 1,000,000,000 
$ 500,000,000 
 
 
 
 
 
 
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders
 
 
 
 
 
 
 
 
 
 
 
 
 
75,000,000 
 
125,000,000 
300,000,000 
 
 
 
 
700,000,000 
 
1,400,000,000 
700,000,000 
 
 
 
 
 
 
Long-term line of credit
 
 
 
 
 
 
 
 
 
95,400,000 
177,200,000 
95,400,000 
41,700,000 
 
 
 
0 
 
0 
135,500,000 
 
 
 
0 
 
 
 
 
 
0 
 
Outstanding letters of credit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
5,000,000 
 
 
 
 
Commercial paper
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
29,400,000 
 
 
 
Debt instrument, term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
364 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, basis spread on variable rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.80% 
Short-term borrowings
95,400,000 
177,200,000 
95,400,000 
41,700,000 
0 
135,500,000 
 
 
 
 
 
 
 
 
66,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum commercial paper support available under credit facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000,000 
 
 
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 authorization
 
 
 
 
 
 
$ 5,100,000,000 
$ 5,100,000,000.0 
$ 4,200,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt and Liquidity Matters (Details) (USD $)
0 Months Ended 12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2017
Maximum
Nov. 30, 2017
Pinnacle West
Dec. 31, 2017
Pinnacle West
Dec. 31, 2016
Pinnacle West
Dec. 31, 2015
Pinnacle West
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 15, 2016
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 6, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Feb. 5, 2013
ARIZONA PUBLIC SERVICE COMPANY
ACC
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Minimum
ACC
Dec. 31, 2017
Senior unsecured notes
Pinnacle West
Nov. 30, 2017
Senior unsecured notes
Pinnacle West
Nov. 30, 2017
Term loans
ARIZONA PUBLIC SERVICE COMPANY
Term loan
May 6, 2016
Unsecured Senior Notes 4.35 Percent Mature on 15 November, 2045
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
Sep. 11, 2017
Unsecured Senior Notes 2.95 Percent Mature on 15 September, 2027
ARIZONA PUBLIC SERVICE COMPANY
Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 300,000,000 
 
$ 250,000,000 
$ 300,000,000 
Interest rate (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.25% 
2.25% 
 
4.35% 
2.95% 
Principal balance repaid
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
125,000,000 
 
 
Contribution to subsidiaries
 
 
 
150,000,000 
178,027,000 
19,242,000 
3,491,000 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
50.00% 
 
 
47.00% 
 
 
 
 
 
 
 
 
 
 
 
Required common equity ratio ordered by ACC (as a percent) (at least)
 
 
 
 
 
 
 
 
 
 
 
 
 
40.00% 
 
 
 
 
 
Total shareholder equity
5,006,690,000 
4,803,622,000 
 
 
5,006,690,000 
4,803,622,000 
 
5,256,829,000 
4,905,680,000 
5,300,000,000 
 
 
 
 
 
 
 
 
 
Total capitalization
 
 
 
 
 
 
 
 
 
10,000,000,000 
 
 
 
 
 
 
 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
 
 
 
 
4,000,000,000 
 
 
 
 
 
 
 
 
 
Long term debt authorization
 
 
 
 
 
 
 
 
 
 
$ 5,100,000,000 
$ 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, 2017
Nov. 30, 2017
Dec. 31, 2016
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Total long-term debt
$ 4,871,713 
 
$ 4,146,785 
Long-term debt less current maturities
4,789,713 
 
4,021,785 
Pinnacle West
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Gross long-term debt
4,908,125 
 
 
Unamortized discount
(184)
 
0 
Unamortized debt issue costs
(1,395)
 
0 
Total long-term debt
298,421 
 
125,000 
Less current maturities
0 
 
125,000 
Total long-term debt less current maturities
298,421 
 
0 
Long-term debt less current maturities
298,421 
 
0 
APS
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Gross long-term debt
4,608,125 
 
 
Unamortized discount
(11,288)
 
(11,816)
Unamortized premium
8,049 
 
4,506 
Unamortized debt issue costs
(31,594)
 
(29,030)
Total long-term debt
4,573,292 
 
4,021,785 
Less current maturities
82,000 
 
0 
Total long-term debt less current maturities
4,491,292 
 
4,021,785 
Pollution Control Bonds - Variable |
APS
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Gross long-term debt
35,975 
 
35,975 
Pollution Control Bonds - Variable |
APS |
Minimum
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Weighted-average interest rate (as a percent)
1.77% 
 
0.81% 
Pollution Control Bonds - Fixed |
APS
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Gross long-term debt
147,150 
 
147,150 
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 
 
183,125 
Senior unsecured notes |
APS
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Gross long-term debt
4,275,000 
 
3,725,000 
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]
 
 
 
Gross long-term debt
0 
 
125,000 
Weighted-average interest rate (as a percent)
 
 
1.52% 
Senior unsecured notes |
Pinnacle West
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Gross long-term debt
300,000 
 
0 
Interest rate (as a percent)
2.25% 
2.25% 
 
Term loan |
APS
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Weighted-average interest rate (as a percent)
2.236% 
 
1.427% 
Term loan |
Term loans |
APS
 
 
 
Long-Term Debt and Liquidity Matters [Line Items]
 
 
 
Term loans
$ 150,000 
 
$ 150,000 
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Pinnacle West
 
Principal payments due on long-term debt
 
2018
$ 82,000 
2019
600,000 
2020
550,000 
2021
0 
2022
0 
Thereafter
3,676,125 
Total
4,908,125 
ARIZONA PUBLIC SERVICE COMPANY
 
Principal payments due on long-term debt
 
2018
82,000 
2019
600,000 
2020
250,000 
2021
0 
2022
0 
Thereafter
3,676,125 
Total
$ 4,608,125 
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
$ 4,871,713 
$ 4,146,785 
Fair Value
5,304,956 
4,425,789 
Pinnacle West
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
298,421 
125,000 
Fair Value
298,608 
125,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
4,573,292 
4,021,785 
Fair Value
$ 5,006,348 
$ 4,300,789 
Retirement Plans and Other Benefits Retirement Plans and Other Benefits (Details) (USD $)
1 Months Ended 12 Months Ended 12 Months Ended
Jul. 31, 2012
Dec. 31, 2017
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2017
Pension Benefits
Dec. 31, 2016
Pension Benefits
Dec. 31, 2015
Pension Benefits
Dec. 31, 2017
Other Benefits
Dec. 31, 2016
Other Benefits
Dec. 31, 2015
Other Benefits
Jan. 1, 2015
Other Benefits
Age
Dec. 31, 2017
Pinnacle West
Dec. 31, 2016
Pinnacle West
Dec. 31, 2015
Pinnacle West
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Pension Benefits
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Other Benefits
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Other Benefits
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Other Benefits
Plan Design Changes [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Age eligible for benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
65 
 
 
 
 
 
 
 
 
 
 
Effect of plan amendment on accumulated benefit obligation
 
 
 
 
 
 
 
 
 
 
 
 
$ 316,000,000 
 
 
 
 
 
 
 
 
 
 
 
Amount of other postretirement benefit trust assets for union employee medical costs
 
186,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
 
 
 
6.05% 
 
 
5.55% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partnership funding commitments, contribution amount (up to)
 
75,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partnership funding commitments, funded amount
 
58,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Employer's contributions under the plan
 
 
 
 
 
 
 
100,000,000 
100,000,000 
100,000,000 
353,000 
1,000,000 
1,000,000 
 
 
 
 
 
100,000,000 
100,000,000 
100,000,000 
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)
 
 
 
 
 
 
 
250,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 
$ 10,000,000 
$ 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, 2017
Dec. 31, 2016
Dec. 31, 2015
Pension Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost-benefits earned during the period
$ 54,858 
$ 53,792 
$ 59,627 
Interest cost on benefit obligation
129,756 
131,647 
123,983 
Expected return on plan assets
(174,271)
(173,906)
(179,231)
Amortization of prior service cost (credit)
81 
527 
594 
Amortization of net actuarial loss
47,900 
40,717 
31,056 
Net periodic benefit cost
58,324 
52,777 
36,029 
Portion of cost charged to expense
27,295 
26,172 
20,036 
Other Benefits
 
 
 
Net periodic benefit costs and the portion of these costs charged to expense
 
 
 
Service cost-benefits earned during the period
17,119 
14,993 
16,827 
Interest cost on benefit obligation
29,959 
29,721 
28,102 
Expected return on plan assets
(53,401)
(36,495)
(36,855)
Amortization of prior service cost (credit)
(37,842)
(37,883)
(37,968)
Amortization of net actuarial loss
5,118 
4,589 
4,881 
Net periodic benefit cost
(39,047)
(25,075)
(25,013)
Portion of cost charged to expense
$ (18,274)
$ (12,435)
$ (10,391)
Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Pension Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
$ 3,204,462 
$ 3,033,803 
 
Service cost
54,858 
53,792 
59,627 
Interest cost
129,756 
131,647 
123,983 
Benefit payments
(166,342)
(142,247)
 
Actuarial (gain) loss
171,452 
127,467 
 
Benefit obligation at the end of the period
3,394,186 
3,204,462 
3,033,803 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
2,675,357 
2,542,774 
 
Actual return on plan assets
428,374 
166,408 
 
Employer's contributions under the plan
100,000 
100,000 
100,000 
Benefit payments
(146,704)
(133,825)
 
Balance at the end of the period
3,057,027 
2,675,357 
2,542,774 
Funded Status at the end of the period
(337,159)
(529,105)
 
Other Benefits
 
 
 
Change in Benefit Obligation
 
 
 
Benefit obligation at the beginning of the period
716,445 
647,020 
 
Service cost
17,119 
14,993 
16,827 
Interest cost
29,959 
29,721 
28,102 
Benefit payments
(30,144)
(26,231)
 
Actuarial (gain) loss
20,014 
50,942 
 
Benefit obligation at the end of the period
753,393 
716,445 
647,020 
Change in Plan Assets
 
 
 
Balance at the beginning of the period
882,651 
833,017 
 
Actual return on plan assets
139,367 
63,463 
 
Employer's contributions under the plan
353 
1,000 
1,000 
Benefit payments
0 
(14,648)
 
Balance at the end of the period
1,022,371 
882,651 
833,017 
Funded Status at the end of the period
$ 268,978 
$ 166,206 
 
Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) (Pension Benefits, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
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
$ 3,394,186 
$ 3,204,462 
Accumulated benefit obligation
3,227,233 
3,049,406 
Fair value of plan assets
$ 3,057,027 
$ 2,675,357 
Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Amounts recognized on the Consolidated Balance Sheets
 
 
Noncurrent asset
$ 268,978 
$ 166,206 
Pension Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Noncurrent asset
0 
0 
Current liability
(9,859)
(19,795)
Noncurrent liability
(327,300)
(509,310)
Net amount recognized
(337,159)
(529,105)
Other Benefits
 
 
Amounts recognized on the Consolidated Balance Sheets
 
 
Noncurrent asset
268,978 
166,206 
Current liability
0 
0 
Noncurrent liability
0 
0 
Net amount recognized
$ 268,978 
$ 166,206 
Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) (USD $)
Dec. 31, 2017
Dec. 31, 2016
Details related to accumulated other comprehensive loss
 
 
Accumulated other comprehensive loss
 
$ 0 
Pension Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
643,199,000 
773,750,000 
Prior service cost (credit)
0 
81,000 
APS’s portion recorded as a regulatory (asset) liability
(576,188,000)
(711,059,000)
Income tax expense (benefit)
(24,915,000)
(24,202,000)
Accumulated other comprehensive loss
42,096,000 
38,570,000 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
28,334,000 
 
Prior service credit
0 
 
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018
28,334,000 
 
Other Benefits
 
 
Details related to accumulated other comprehensive loss
 
 
Net actuarial loss
75,439,000 
146,509,000 
Prior service cost (credit)
(265,575,000)
(303,417,000)
APS’s portion recorded as a regulatory (asset) liability
189,627,000 
156,575,000 
Income tax expense (benefit)
853,000 
833,000 
Accumulated other comprehensive loss
344,000 
500,000 
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
 
 
Net actuarial loss
0 
 
Prior service credit
(37,842,000)
 
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018
$ (37,842,000)
 
Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
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)
4.75% 
5.00% 
 
Ultimate health care cost trend rate (as a percent)
4.75% 
5.00% 
 
Number of years to ultimate trend rate (pre-65 participants)
8 years 
4 years 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
Initial pre-65 health care cost trend rate (as a percent)
7.00% 
7.00% 
7.00% 
Initial post-65 health care cost trend rate (as a percent)
5.00% 
5.00% 
5.00% 
Ultimate healthcare cost trend rate (as a percent)
5.00% 
5.00% 
5.00% 
Number of years to ultimate trend rate (pre-65 participants)
4 years 
4 years 
4 years 
Pension Benefits
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
Discount rate (as a percent)
3.65% 
4.08% 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
Discount rate (as a percent)
4.08% 
4.37% 
4.02% 
Rate of compensation increase (as a percent)
4.00% 
4.00% 
4.00% 
Expected long-term return on plan assets (as a percent)
6.55% 
6.90% 
6.90% 
Other Benefits
 
 
 
Weighted-average assumptions used to determine benefit obligations
 
 
 
Discount rate (as a percent)
3.71% 
4.17% 
 
Weighted-average assumptions used to determine net periodic benefit costs
 
 
 
Discount rate (as a percent)
4.17% 
4.52% 
4.14% 
Expected long-term return on plan assets (as a percent)
6.05% 
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
$ 8,424 
 
 
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
(5,616)
 
 
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs
9,145 
 
 
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs
(7,037)
 
 
Effect of 1% increase on the accumulated other postretirement benefit obligation
128,203 
 
 
Effect of 1% decrease on the accumulated other postretirement benefit obligation
$ (98,143)
 
 
Retirement Plans and Other Benefits - Asset Allocation (Details)
Dec. 31, 2017
Pension Benefits
 
Defined Benefit Plan Disclosure [Line Items]
 
Target allocation (as a percent)
100.00% 
Actual asset allocation (as a percent)
100.00% 
Pension Benefits |
Fixed income securities
 
Defined Benefit Plan Disclosure [Line Items]
 
Target allocation (as a percent)
62.00% 
Actual asset allocation (as a percent)
58.00% 
Pension Benefits |
Return-generating assets
 
Defined Benefit Plan Disclosure [Line Items]
 
Target allocation (as a percent)
38.00% 
Actual asset allocation (as a percent)
42.00% 
Pension Benefits |
Equities in US and other developed markets
 
Defined Benefit Plan Disclosure [Line Items]
 
Target allocation (as a percent)
18.00% 
Pension Benefits |
Equities in emerging markets
 
Defined Benefit Plan Disclosure [Line Items]
 
Target allocation (as a percent)
6.00% 
Pension Benefits |
Alternative investments
 
Defined Benefit Plan Disclosure [Line Items]
 
Target allocation (as a percent)
14.00% 
Other Benefits
 
Defined Benefit Plan Disclosure [Line Items]
 
Actual asset allocation (as a percent)
100.00% 
Other Benefits |
Fixed income securities
 
Defined Benefit Plan Disclosure [Line Items]
 
Actual asset allocation (as a percent)
67.00% 
Other Benefits |
Return-generating assets
 
Defined Benefit Plan Disclosure [Line Items]
 
Actual asset allocation (as a percent)
33.00% 
Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Pension Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
$ 3,057,027 
$ 2,675,357 
$ 2,542,774 
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
903,085 
749,541 
 
Fair value of plan assets
3,057,027 
2,675,357 
 
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
686,941 
613,193 
 
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
1,467,001 
1,312,623 
 
Other Benefits
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
1,022,371 
882,651 
833,017 
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
99,910 
123,234 
 
Fair value of plan assets
1,022,371 
882,651 
 
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
583,796 
456,718 
 
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
338,665 
302,699 
 
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
3,830 
13,995 
 
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
3,830 
13,995 
 
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
143 
304 
 
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
143 
304 
 
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
1,365,194 
1,210,453 
 
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
1,365,194 
1,210,453 
 
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
306,008 
268,193 
 
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
306,008 
268,193 
 
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
221,291 
112,583 
 
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
221,291 
112,583 
 
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
336,963 
145,255 
 
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
336,963 
145,255 
 
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
100,599 
102,170 
 
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
100,599 
102,170 
 
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
32,508 
34,506 
 
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
32,508 
34,506 
 
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
228,088 
235,109 
 
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
228,088 
235,109 
 
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
196,153 
243,741 
 
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
196,153 
243,741 
 
Mutual funds |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
233,732 
251,506 
 
Mutual funds |
Pension Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
233,732 
251,506 
 
Mutual funds |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Fair value of plan assets
39,269 
67,418 
 
Mutual funds |
Other Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
39,269 
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
408,763 
266,840 
 
Fair value of plan assets
408,763 
266,840 
 
Equities |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
75,310 
95,814 
 
Fair value of plan assets
75,310 
95,814 
 
Real estate |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
171,569 
161,449 
 
Fair value of plan assets
171,569 
161,449 
 
Real estate |
Other Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
15,422 
14,509 
 
Fair value of plan assets
15,422 
14,509 
 
Fixed income securities |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
90,869 
 
 
Fair value of plan assets
90,869 
 
 
Partnerships |
Pension Benefits |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Other
133,379 
208,915 
 
Fair value of plan assets
133,379 
208,915 
 
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
98,505 
112,337 
 
Fair value of plan assets
99,713 
112,337 
 
Short-term investments and other |
Pension Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
1,208 
 
 
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
9,178 
9,851 
 
Fair value of plan assets
20,595 
9,851 
 
Short-term investments and other |
Other Benefits |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
11,268 
 
 
Short-term investments and other |
Other Benefits |
Significant Other Observable Inputs (Level 2) |
Pinnacle West
 
 
 
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
 
 
 
Gross fair value of plan assets
$ 149 
 
 
Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Pension Benefits
 
Estimated Future Benefit Payments
 
2018
$ 175,383 
2019
181,902 
2020
191,586 
2021
196,583 
2022
201,463 
Years 2023-2027
1,068,568 
Other Benefits
 
Estimated Future Benefit Payments
 
2018
31,891 
2019
34,000 
2020
35,658 
2021
37,090 
2022
37,860 
Years 2023-2027
$ 191,207 
Leases (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Trust
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 1986
Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
Lease expense
$ 18,000,000 
$ 16,000,000 
$ 17,000,000 
 
Pinnacle West
 
 
 
 
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
 
 
 
 
2018
13,412,000 
 
 
 
2019
11,054,000 
 
 
 
2020
9,641,000 
 
 
 
2021
7,105,000 
 
 
 
2022
4,609,000 
 
 
 
Thereafter
55,940,000 
 
 
 
Total future lease commitments
101,761,000 
 
 
 
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
 
 
 
 
2018
13,110,000 
 
 
 
2019
10,802,000 
 
 
 
2020
9,392,000 
 
 
 
2021
6,858,000 
 
 
 
2022
4,510,000 
 
 
 
Thereafter
53,605,000 
 
 
 
Total future lease commitments
98,277,000 
 
 
 
Lease expense
$ 17,000,000 
$ 15,000,000 
$ 14,000,000 
 
Number of VIE lessor trusts
3 
 
 
3 
Jointly-Owned Facilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Jul. 6, 2016
4CA
 
 
Interests in jointly-owned facilities
 
 
Plant in Service
$ 141,000 
 
Accumulated Depreciation
83,000 
 
Construction work in progress
25,000 
 
Palo Verde Units 1 and 3 |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
29.10% 
 
Plant in Service
1,872,104 
 
Accumulated Depreciation
1,092,049 
 
Construction work in progress
24,257 
 
Palo Verde Unit 2 |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
16.80% 
 
Plant in Service
619,263 
 
Accumulated Depreciation
364,516 
 
Construction work in progress
14,672 
 
Palo Verde Common |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
28.00% 
 
Plant in Service
726,223 
 
Accumulated Depreciation
262,065 
 
Construction work in progress
46,577 
 
Palo Verde Sale Leaseback |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Plant in Service
351,050 
 
Accumulated Depreciation
241,405 
 
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
1,196,683 
 
Accumulated Depreciation
568,304 
 
Construction work in progress
240,514 
 
Cholla Common Facilities |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
50.50% 
 
Plant in Service
180,907 
 
Accumulated Depreciation
69,633 
 
Construction work in progress
1,091 
 
ANPP 500kV System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
34.00% 
 
Plant in Service
130,767 
 
Accumulated Depreciation
46,400 
 
Construction work in progress
684 
 
Navajo Southern System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
27.50% 
 
Plant in Service
85,299 
 
Accumulated Depreciation
28,915 
 
Construction work in progress
180 
 
Palo Verde — Yuma 500kV System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
18.10% 
 
Plant in Service
14,765 
 
Accumulated Depreciation
6,614 
 
Construction work in progress
486 
 
Four Corners Switchyards |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
63.20% 
 
Plant in Service
66,386 
 
Accumulated Depreciation
12,605 
 
Construction work in progress
327 
 
Phoenix — Mead System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
17.10% 
 
Plant in Service
39,383 
 
Accumulated Depreciation
17,600 
 
Construction work in progress
41 
 
Palo Verde — Rudd 500kV System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
50.00% 
 
Plant in Service
97,600 
 
Accumulated Depreciation
23,884 
 
Construction work in progress
245 
 
Morgan — Pinnacle Peak System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
64.60% 
 
Plant in Service
117,721 
 
Accumulated Depreciation
14,569 
 
Construction work in progress
1 
 
Round Valley System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
50.00% 
 
Plant in Service
515 
 
Accumulated Depreciation
141 
 
Construction work in progress
0 
 
Palo Verde — Morgan System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
90.90% 
 
Plant in Service
137,887 
 
Accumulated Depreciation
3,948 
 
Construction work in progress
94,350 
 
Hassayampa — North Gila System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
80.00% 
 
Plant in Service
142,541 
 
Accumulated Depreciation
6,953 
 
Construction work in progress
0 
 
Cholla 500kV Switchyard |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
85.70% 
 
Plant in Service
5,243 
 
Accumulated Depreciation
1,312 
 
Construction work in progress
190 
 
Saguaro 500kV Switchyard |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
60.00% 
 
Plant in Service
20,473 
 
Accumulated Depreciation
12,574 
 
Construction work in progress
0 
 
Kyrene - Knox System |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Percent Owned
50.00% 
 
Plant in Service
578 
 
Accumulated Depreciation
297 
 
Construction work in progress
$ 0 
 
Navajo Plant |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Interests in jointly-owned facilities
 
 
Ownership interest by noncontrolling owners (as a percent)
14.00% 
 
El Paso's Interest in Four Corners |
4CA
 
 
Interests in jointly-owned facilities
 
 
Ownership interest acquired (as a percent)
7.00% 
7.00% 
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)
12 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended 12 Months Ended
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Coal take-or-pay commitments
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, 2017
ARIZONA PUBLIC SERVICE COMPANY
Renewable energy credits
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Obligations
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Balance Sheet Obligations
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Coal Mine Reclamation Balance Sheet Obligations
Dec. 31, 2017
4CA
Coal Mine Reclamation Obligations
Dec. 31, 2017
4CA
Coal Mine Reclamation Balance Sheet Obligations
Dec. 31, 2016
4CA
Coal Mine Reclamation Balance Sheet Obligations
Aug. 18, 2014
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Dec. 31, 2017
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Dec. 31, 2017
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Aug. 18, 2014
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
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
Palo Verde Nuclear Generating Station [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Settlement amount, awarded to company
 
 
 
 
 
 
 
 
 
 
 
 
$ 57,400,000 
$ 9,000,000 
 
$ 16,700,000 
$ 2,600,000 
 
New claims filed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
Number of settlement agreement time periods
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
Proceeds from legal settlements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
65,200,000 
 
 
19,000,000 
Maximum insurance against public liability per occurrence for a nuclear incident
13,400,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum available nuclear liability insurance
450,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program
13,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum assessment per reactor for each nuclear incident
127,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual limit per incident with respect to maximum assessment
19,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of VIE lessor trusts
3 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum potential retrospective assessment per incident of APS
111,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
24,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Collateral assurance provided based on rating triggers
64,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Period to provide collateral assurance based on rating triggers
20 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
715,000,000 
 
159,997,000 
 
 
40,000,000 
31,000,000 
 
 
1,000,000 
 
 
 
 
 
 
 
 
2019
578,000,000 
 
185,365,000 
 
 
40,000,000 
32,000,000 
 
 
1,000,000 
 
 
 
 
 
 
 
 
2020
548,000,000 
 
186,632,000 
 
 
40,000,000 
21,000,000 
 
 
2,000,000 
 
 
 
 
 
 
 
 
2021
548,000,000 
 
190,607,000 
 
 
40,000,000 
20,000,000 
 
 
2,000,000 
 
 
 
 
 
 
 
 
2022
554,000,000 
 
194,678,000 
 
 
40,000,000 
22,000,000 
 
 
2,000,000 
 
 
 
 
 
 
 
 
Thereafter
6,500,000,000 
 
1,750,739,000 
 
 
370,000,000 
191,000,000 
 
 
16,000,000 
 
 
 
 
 
 
 
 
Total obligation
 
 
2,700,000,000 
 
 
 
 
216,000,000 
207,000,000 
 
16,000,000 
15,000,000 
 
 
 
 
 
 
Present value of commitments
 
 
1,900,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total purchases
 
 
$ 165,220,000 
$ 160,066,000 
$ 211,327,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) (ARIZONA PUBLIC SERVICE COMPANY, Contaminated groundwater wells, USD $)
In Millions, unless otherwise specified
0 Months Ended 12 Months Ended
Dec. 16, 2016
plaintiff
Aug. 6, 2013
Defendant
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY |
Contaminated groundwater wells
 
 
 
Superfund
 
 
 
Costs related to investigation and study under Superfund site
 
 
$ 2 
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit
 
24 
 
Number of plaintiffs
2 
 
 
Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)
0 Months Ended 0 Months Ended 12 Months Ended
Jul. 6, 2016
Payment Guarantee
guarantee
Dec. 31, 2017
Letter of credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Equity Lessors Sale Leaseback Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Jul. 6, 2016
Four Corners
NTEC
Jul. 6, 2016
Four Corners
4CA
Jun. 13, 2017
Four Corners
Coal Supply Agreement Arbitration
Jun. 13, 2017
Four Corners
Coal Supply Agreement Arbitration
ARIZONA PUBLIC SERVICE COMPANY
Jul. 6, 2016
Four Corners
Coal Supply Agreement Arbitration
NTEC
Dec. 31, 2017
Four Corners
Coal Supply Agreement Arbitration
4CA
Dec. 31, 2017
Regional Haze Rules
Navajo Generating Station
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Regional Haze Rules
Four Corners Units 4 and 5
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Regional Haze Rules
Four Corners Units 4 and 5
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Regional Haze Rules
Four Corners Units 4 and 5
Natural Gas Tolling Letter of Credit
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Coal Combustion Waste
Four Corners
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Coal Combustion Waste
Navajo Generating Station
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Coal Combustion Waste
Minimum
Cholla
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
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
 
 
 
 
7.00% 
 
 
 
 
 
63.00% 
 
 
 
 
 
 
 
Expected environmental cost
 
 
 
 
 
 
 
 
 
$ 200,000,000 
$ 400,000,000 
 
 
 
 
 
 
 
Additional percentage share of cost of control
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
 
 
 
 
 
Additional expected environment cost
 
 
 
 
 
 
 
 
 
 
 
45,000,000 
 
22,000,000 
1,000,000 
20,000,000 
 
 
Damages sought
 
 
 
 
 
30,000,000 
17,000,000 
 
 
 
 
 
 
 
 
 
 
 
Option to purchase, ownership interest (as a percent)
 
 
 
7.00% 
 
 
 
7.00% 
 
 
 
 
 
 
 
 
 
 
Payment received for coal supply agreement
 
 
 
 
 
 
 
 
10,000,000 
 
 
 
 
 
 
 
 
 
Operating and maintenance cost reimbursement receivable
 
 
 
 
 
 
 
 
20,000,000 
 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
$ 5,000,000 
$ 62,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of parental guarantees
4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership interest acquired (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
7.00% 
Asset Retirement Obligations (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
 
 
Change in asset retirement obligations
 
 
Asset retirement obligations at the beginning of year
$ 624,475,000 
$ 443,576,000 
Changes attributable to:
 
 
Accretion expense
33,104,000 
26,656,000 
Settlements
0 
(15,732,000)
Estimated cash flow revisions
21,950,000 
151,046,000 
Newly incurred or acquired obligations
0 
18,929,000 
Asset retirement obligations at the end of year
679,529,000 
624,475,000 
Navajo Generating Station |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Asset Retirement Obligations
 
 
Increase in regulatory asset
2,000,000 
 
Decrease in regulatory liability
20,000,000 
 
Changes attributable to:
 
 
Newly incurred or acquired obligations
22,000,000 
 
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 |
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)
Palo Verde Nuclear Generating Station |
ARIZONA PUBLIC SERVICE COMPANY
 
 
Asset Retirement Obligations
 
 
Decrease in regulatory liability
 
20,000,000 
Increase in plant services
 
131,000,000 
Changes attributable to:
 
 
Estimated cash flow revisions
 
$ 151,000,000 
Selected Quarterly Financial Data (Unaudited) (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2017
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
OPERATING REVENUES
$ 759,659 
$ 1,183,322 
$ 944,587 
$ 677,728 
$ 739,199 
$ 1,166,922 
$ 915,394 
$ 677,167 
$ 3,565,296 
$ 3,498,682 
$ 3,495,443 
Operations and maintenance
266,149 
224,305 
214,013 
219,976 
208,277 
217,568 
242,279 
243,195 
924,443 
911,319 
868,377 
Operating income
90,610 
466,082 
304,229 
73,506 
122,816 
451,258 
231,748 
50,162 
934,427 
855,984 
854,602 
Income taxes
20,775 
144,319 
88,967 
4,211 
27,309 
141,446 
65,742 
1,914 
258,272 
236,411 
237,720 
Net income
26,502 
280,945 
172,317 
28,185 
58,119 
267,900 
126,182 
9,326 
507,949 
461,527 
456,190 
Net income attributable to common shareholders
21,629 
276,072 
167,443 
23,312 
53,246 
263,027 
121,308 
4,453 
488,456 
442,034 
437,257 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.19 
$ 2.47 
$ 1.50 
$ 0.21 
$ 0.48 
$ 2.36 
$ 1.09 
$ 0.04 
$ 4.37 
$ 3.97 
$ 3.94 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 0.19 
$ 2.46 
$ 1.49 
$ 0.21 
$ 0.47 
$ 2.35 
$ 1.08 
$ 0.04 
$ 4.35 
$ 3.95 
$ 3.92 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
 
 
 
 
 
 
 
 
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
756,549 
1,178,106 
942,615 
676,869 
737,006 
1,166,359 
909,757 
676,632 
3,554,139 
3,489,754 
3,492,357 
Operations and maintenance
255,361 
215,264 
208,286 
212,218 
197,319 
209,366 
233,712 
238,711 
891,129 
879,108 
853,135 
Operating income
79,258 
322,053 
212,790 
65,468 
95,765 
307,601 
165,684 
48,930 
679,569 
617,980 
611,984 
Income taxes
 
 
 
 
 
 
 
 
269,168 
245,842 
245,841 
Net income
 
 
 
 
 
 
 
 
523,802 
481,634 
469,207 
Net income attributable to common shareholders
$ 27,783 
$ 284,256 
$ 169,108 
$ 23,162 
$ 58,480 
$ 269,220 
$ 127,188 
$ 7,253 
$ 504,309 
$ 462,141 
$ 450,274 
Fair Value Measurements - Fair Value of Assets and Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Assets
 
 
Nuclear decommissioning trust
$ 871,000 
$ 779,586 
Total assets
1,036 
11,076 
Fair value measurement on a recurring basis
 
 
Assets
 
 
Cash equivalents
10,630 
 
Coal reclamation escrow account
32,542 
14,521 
Coal reclamation escrow account, other
525 
 
Other
(4,737)
(35,103)
Derivative assets
1,982 
19,695 
Other
417,499 
354,056 
Nuclear decommissioning trust
871,000 
779,586 
Other
413,287 
318,953 
Total assets
916,154 
813,802 
Liabilities
 
 
Other
1,516 
31,049 
Derivative Liability
(96,422)
(73,074)
Fair value measurement on a recurring basis |
Cash and cash equivalents
 
 
Assets
 
 
Other
109 
795 
Nuclear decommissioning trust
7,333 
795 
Fair value measurement on a recurring basis |
US commingled equity funds
 
 
Assets
 
 
Other
417,390 
353,261 
Nuclear decommissioning trust
417,390 
353,261 
Fair value measurement on a recurring basis |
U.S. Treasury
 
 
Assets
 
 
Nuclear decommissioning trust
127,662 
95,441 
Fair value measurement on a recurring basis |
Corporate
 
 
Assets
 
 
Nuclear decommissioning trust
114,007 
111,623 
Fair value measurement on a recurring basis |
Mortgage-backed securities
 
 
Assets
 
 
Nuclear decommissioning trust
111,874 
115,337 
Fair value measurement on a recurring basis |
Municipal bonds
 
 
Assets
 
 
Nuclear decommissioning trust
79,049 
80,997 
Fair value measurement on a recurring basis |
Other
 
 
Assets
 
 
Nuclear decommissioning trust
13,685 
22,132 
Fair value measurement on a recurring basis |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Cash equivalents
10,630 
 
Coal reclamation escrow account
455 
14,521 
Decommissioning fund investments, gross fair value
134,886 
95,441 
Gross assets, fair value disclosure
145,971 
109,962 
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
 
0 
Nuclear decommissioning trust
7,224 
 
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
127,662 
95,441 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Gross derivative assets
5,683 
43,722 
Coal reclamation escrow account
31,562 
 
Decommissioning fund investments, gross fair value
318,615 
330,089 
Gross assets, fair value disclosure
355,860 
373,811 
Liabilities
 
 
Gross derivative liability
(78,646)
(45,641)
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Corporate
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
114,007 
111,623 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
111,874 
115,337 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Municipal bonds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
79,049 
80,997 
Fair value measurement on a recurring basis |
Significant Other Observable Inputs (Level 2) |
Other
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
13,685 
22,132 
Fair value measurement on a recurring basis |
Significant Unobservable Inputs (Level 3)
 
 
Assets
 
 
Gross derivative assets
1,036 
11,076 
Gross assets, fair value disclosure
1,036 
11,076 
Liabilities
 
 
Gross derivative liability
$ (19,292)
$ (58,482)
Fair Value Measurements - Level 3 Quantitative Information (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
$ 1,036 
$ 11,076 
Liabilities
19,292 
58,482 
Electricity forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
21 
10,648 
Liabilities
15,485 
32,042 
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)
18.51 
16.43 
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)
38.75 
41.07 
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)
27.89 
29.86 
Natural gas forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
1,015 
428 
Liabilities
$ 3,807 
$ 26,440 
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)
2.33 
2.32 
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)
3.11 
3.60 
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
 
 
Electricity forward price (per MWh)
2.71 
 
Natural gas forward price (per MMbtu)
 
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, 2017
Dec. 31, 2016
Total net gains (losses) realized/unrealized:
 
 
Net derivative beginning balance
$ (47,406,000)
$ (32,979,000)
Included in earnings
0 
0 
Included in OCI
3,000 
88,000 
Deferred as a regulatory asset or liability
(13,643,000)
(37,543,000)
Settlements
5,834,000 
15,146,000 
Transfers into Level 3 from Level 2
(10,026,000)
1,900,000 
Transfers from Level 3 into Level 2
46,982,000 
5,982,000 
Net derivative ending balance
(18,256,000)
(47,406,000)
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, 2017
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Earnings Per Share [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common shareholders
$ 21,629 
$ 276,072 
$ 167,443 
$ 23,312 
$ 53,246 
$ 263,027 
$ 121,308 
$ 4,453 
$ 488,456 
$ 442,034 
$ 437,257 
Weighted Average common shares outstanding — basic (in shares)
 
 
 
 
 
 
 
 
111,839 
111,409 
111,026 
Net effect of dilutive securities:
 
 
 
 
 
 
 
 
 
 
 
Contingently issuable performance shares and restricted stock units
 
 
 
 
 
 
 
 
528 
637 
526 
Weighted average common shares outstanding — diluted (in shares)
 
 
 
 
 
 
 
 
112,367 
112,046 
111,552 
Earnings per average common share attributable to common shareholders — basic (in dollars per share)
$ 0.19 
$ 2.47 
$ 1.50 
$ 0.21 
$ 0.48 
$ 2.36 
$ 1.09 
$ 0.04 
$ 4.37 
$ 3.97 
$ 3.94 
Earnings per average common share attributable to common shareholders — diluted (in dollars per share)
$ 0.19 
$ 2.46 
$ 1.49 
$ 0.21 
$ 0.47 
$ 2.35 
$ 1.08 
$ 0.04 
$ 4.35 
$ 3.95 
$ 3.92 
Stock-Based Compensation (Details) (USD $)
3 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 3 Months Ended
Dec. 31, 2017
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2017
performance_criteria
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2017
Restricted stock unit awards
Dec. 31, 2016
Restricted stock unit awards
Dec. 31, 2015
Restricted stock unit awards
Dec. 31, 2017
Restricted Stock Units, Stock Grants, and Stock Units
Dec. 31, 2017
Performance Shares
Dec. 31, 2015
Performance Shares
Dec. 31, 2017
Performance Shares
Maximum
Dec. 31, 2017
Performance Shares
Minimum
Dec. 31, 2017
Officers and Key Employees
Restricted stock unit awards
Feb. 28, 2017
Chief Executive Officer
Retention units
Dec. 31, 2012
Chief Executive Officer
Retention units
Dec. 31, 2017
Non-Officer Board of Director Member
Restricted stock unit awards
Dec. 31, 2017
2012 Plan
Dec. 31, 2016
Retained Earnings
Dec. 31, 2016
Accounting Standards Update 2016-09
Dec. 31, 2016
Accounting Standards Update 2016-09
Retained Earnings
Stock-Based Compensation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares available for grant (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,600,000 
 
 
 
Common shares available for issuance (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,200,000 
 
 
 
Stock compensation cumulative effect adjustments
 
 
 
 
$ 45,855,000 
 
 
 
 
$ 45,855,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 5,475,000 
 
$ 6,000,000 
Net income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,000,000 
Operations and maintenance
(266,149,000)
(224,305,000)
(214,013,000)
(219,976,000)
(208,277,000)
(217,568,000)
(242,279,000)
(243,195,000)
(924,443,000)
(911,319,000)
(868,377,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,000,000 
 
Compensation cost that has been charged against income
 
 
 
 
 
 
 
 
21,000,000 
19,000,000 
19,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total income tax benefit recognized
 
 
 
 
 
 
 
 
15,000,000 
10,000,000 
7,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted
12,000,000 
 
 
 
 
 
 
 
12,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected weighted-average period of recognition of unrecognized compensation cost
 
 
 
 
 
 
 
 
2 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total fair value of shares vested
 
 
 
 
 
 
 
 
22,000,000 
22,000,000 
21,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-based liabilities paid
 
 
 
 
 
 
 
 
 
 
 
4,000,000 
3,000,000 
10,000,000 
 
 
16,000,000 
 
 
 
 
 
 
 
 
 
 
Cash flow effect, cash used to settle awards
 
 
 
 
 
 
 
 
 
 
 
$ 4,000,000 
$ 3,000,000 
$ 3,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Stock Units, Stock Grants and Stock Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vesting period
 
 
 
 
 
 
 
 
 
 
 
4 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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% 
 
 
 
 
Percentage of fully transferable shares of stock in that participant may receive cash
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
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 stock that the participant may elect as dividend under second option of plan
 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
Granted (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
161,963 
147,706 
 
 
 
 
 
50,617 
 
 
 
 
 
Additional shares to be granted as retention award if performance requirements are met
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
33,745 
 
 
 
 
 
Shares released during period (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,607 
4,798 
 
 
 
 
84,362 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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, 2017
Dec. 31, 2016
Dec. 31, 2015
Restricted Stock Units, Stock Grants, and Stock Units
 
 
 
Stocks granted and the weighted average fair value
 
 
 
Units granted (in shares)
161,963 
141,811 
152,651 
Grant date fair value (in dollars per share)
$ 72.60 
$ 67.34 
$ 64.12 
Number of granted awards to be settled in cash (in shares)
67,599 
43,952 
45,104 
Performance Shares
 
 
 
Stocks granted and the weighted average fair value
 
 
 
Units granted (in shares)
147,706 
166,666 
151,430 
Grant date fair value (in dollars per share)
$ 78.99 
$ 66.60 
$ 64.97 
Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Restricted Stock Units, Stock Grants, and Stock Units
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
335,259 
 
 
Granted (in shares)
161,963 
 
 
Change in performance factor (in shares)
0 
 
 
Vested (in shares)
(202,327)
 
 
Forfeited (in shares)
(3,607)
 
 
Balance at the end of the period (in shares)
291,288 
335,259 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 62.04 
 
 
Granted (in dollars per share)
$ 72.60 
$ 67.34 
$ 64.12 
Change in performance factor (in dollars per share)
$ 0.00 
 
 
Vested (in dollars per share)
$ 59.19 
 
 
Forfeited (in dollars per share)
$ 69.58 
 
 
Balance at the end of the period (in dollars per share)
$ 69.78 
$ 62.04 
 
Vested Awards Outstanding at December 31, 2017
89,928 
 
 
Vested Awards Outstanding at December 31, 2015 (in shares)
   
 
 
Number of nonvested awards to be settled in cash (in shares)
133,373 
 
 
Performance Shares
 
 
 
Nonvested shares
 
 
 
Balance at the beginning of the period (in shares)
312,724 
 
 
Granted (in shares)
147,706 
 
 
Change in performance factor (in shares)
18,266 
 
 
Vested (in shares)
(164,396)
 
 
Forfeited (in shares)
(4,798)
 
 
Balance at the end of the period (in shares)
309,502 
312,724 
 
Weighted-Average Grant-Date Fair Value
 
 
 
Balance at the beginning of the period (in dollars per share)
$ 65.32 
 
 
Granted (in dollars per share)
$ 78.99 
$ 66.60 
$ 64.97 
Change in performance factor (in dollars per share)
$ 64.97 
 
 
Vested (in dollars per share)
$ 63.87 
 
 
Forfeited (in dollars per share)
$ 69.77 
 
 
Balance at the end of the period (in dollars per share)
$ 72.46 
$ 65.32 
 
Vested Awards Outstanding at December 31, 2017
164,396 
 
 
Vested Awards Outstanding at December 31, 2015 (in shares)
   
 
 
Derivative Accounting (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Designated as Hedging Instruments
Dec. 31, 2016
Designated as Hedging Instruments
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
Commodity Contracts
Dec. 31, 2016
Commodity Contracts
Dec. 31, 2017
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
 
 
 
 
 
$ (2,000,000)
Derivative liability
0 
2,000,000 
 
96,422,000 
73,074,000 
 
Additional collateral to counterparties for energy related non-derivative instrument contracts
 
 
 
$ 110,000,000 
 
 
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details)
12 Months Ended
Dec. 31, 2017
Bcf
MWh
Dec. 31, 2016
MWh
Bcf
Outstanding gross notional amount of derivatives
 
 
Power (in MWh)
583,000 
1,314,000 
Gas (in bcf)
240 
194 
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Designated as Hedging Instruments
 
 
 
Derivative Instruments in Designated Cash Flows Hedges
 
 
 
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
$ (59,000)
$ 47,000 
$ (615,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)
(3,519,000)
(3,926,000)
(5,988,000)
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
(89,183,000)
26,482,000 
(108,399,000)
Revenue |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
(1,192,000)
771,000 
574,000 
Fuel and purchased power |
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments Not Designated as Cash Flows Hedges
 
 
 
Net Gain (Loss) Recognized in Income
$ (87,991,000)
$ 25,711,000 
$ (108,973,000)
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Commodity Contracts
 
 
Assets
 
 
Gross Recognized Derivatives
$ 6,719 
$ 54,798 
Amounts Offset
(5,037)
(35,103)
Net Recognized Derivatives
1,682 
19,695 
Other
300 
0 
Amount Reported on Balance Sheet
1,982 
19,695 
Liabilities
 
 
Gross Recognized Derivatives
(97,938)
(104,123)
Amounts Offset
5,037 
35,103 
Net Recognized Derivatives
(92,901)
(69,020)
Other
(3,521)
(4,054)
Amount Reported on Balance Sheet
(96,422)
(73,074)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(91,219)
(49,325)
Amounts Offset
0 
0 
Net Recognized Derivatives
(91,219)
(49,325)
Other
(3,221)
(4,054)
Amount Reported on Balance Sheet
(94,440)
(53,379)
Commodity Contracts |
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
5,427 
48,094 
Amounts Offset
(3,796)
(28,400)
Net Recognized Derivatives
1,631 
19,694 
Other
300 
0 
Amount Reported on Balance Sheet
1,931 
19,694 
Commodity Contracts |
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
1,292 
6,704 
Amounts Offset
(1,241)
(6,703)
Net Recognized Derivatives
51 
1 
Other
0 
0 
Amount Reported on Balance Sheet
51 
1 
Commodity Contracts |
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(59,527)
(50,182)
Amounts Offset
3,796 
28,400 
Net Recognized Derivatives
(55,731)
(21,782)
Other
(3,521)
(4,054)
Amount Reported on Balance Sheet
(59,252)
(25,836)
Commodity Contracts |
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(38,411)
(53,941)
Amounts Offset
1,241 
6,703 
Net Recognized Derivatives
(37,170)
(47,238)
Other
0 
0 
Amount Reported on Balance Sheet
(37,170)
(47,238)
Designated as Hedging Instruments
 
 
Liabilities
 
 
Amount Reported on Balance Sheet
$ 0 
$ (2,000)
Derivative Accounting - Credit Risk and Related Contingent Features (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Commodity Contracts
 
Credit Risk and Credit-Related Contingent Features
 
Aggregate Fair Value of Derivative Instruments in a Net Liability Position
$ 97,938 
Cash Collateral Posted
0 
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered
$ 91,071 
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Other income:
 
 
 
Interest income
$ 3,497 
$ 884 
$ 493 
Miscellaneous
509 
17 
128 
Total other income
4,006 
901 
621 
Other expense:
 
 
 
Non-operating costs
(11,749)
(9,235)
(11,292)
Investment losses — net
(4,113)
(1,747)
(2,080)
Miscellaneous
(5,677)
(4,355)
(4,451)
Total other expense
(21,539)
(15,337)
(17,823)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Other income:
 
 
 
Interest income
2,858 
261 
163 
Gain on disposition of property
2,048 
5,745 
716 
Miscellaneous
1,620 
2,601 
1,955 
Total other income
6,526 
8,607 
2,834 
Other expense:
 
 
 
Non-operating costs
(12,395)
(11,034)
(11,648)
Loss on disposition of property
(5,424)
(1,246)
(2,219)
Miscellaneous
(5,561)
(5,234)
(5,152)
Total other expense
$ (23,380)
$ (17,514)
$ (19,019)
Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)
12 Months Ended 12 Months Ended 0 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 1986
ARIZONA PUBLIC SERVICE COMPANY
Trust
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2017
Period Through 2023
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Lease
Dec. 31, 2017
Period Through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Lease
Dec. 31, 2017
Period 2017 through 2023
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2017
Period 2024 through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Dec. 31, 2017
Maximum
Period 2024 through 2033
ARIZONA PUBLIC SERVICE COMPANY
Consolidation of VIEs
Jan. 1, 2018
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 
19,493,000 
18,933,000 
19,493,000 
19,493,000 
18,933,000 
 
19,000,000 
19,000,000 
19,000,000 
 
 
 
 
 
 
VIE entity initial loss exposure to noncontrolling interests during lease extension period, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
293,000,000 
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, 2017
Dec. 31, 2016
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback, net of accumulated depreciation
$ 109,645 
$ 113,515 
Equity - noncontrolling interests
129,040 
132,290 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback, net of accumulated depreciation
109,645 
113,515 
Equity - noncontrolling interests
129,040 
132,290 
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
109,645 
113,515 
Equity - noncontrolling interests
$ 129,040 
$ 132,290 
Investments (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
$ 871,000 
$ 779,586 
 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
Realized gains
21,813 
11,213 
5,189 
Realized losses
(13,146)
(10,106)
(6,225)
Proceeds from the sale of securities
542,246 
633,410 
478,813 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
871,000 
779,586 
 
Fixed income securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
478,294 
 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Less than one year
25,123 
 
 
1 year - 5 years
102,783 
 
 
5 years - 10 years
137,854 
 
 
Greater than 10 years
212,534 
 
 
Total
478,294 
 
 
Nuclear Decommissioning Trusts
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
446,277 
 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Less than one year
24,668 
 
 
1 year - 5 years
100,289 
 
 
5 years - 10 years
129,239 
 
 
Greater than 10 years
192,081 
 
 
Total
446,277 
 
 
Escrow Accounts
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
32,017 
 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Less than one year
455 
 
 
1 year - 5 years
2,494 
 
 
5 years - 10 years
8,615 
 
 
Greater than 10 years
20,453 
 
 
Total
32,017 
 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
871,000 
779,586 
 
Total Unrealized Gains
260,160 
197,911 
 
Total Unrealized Losses
(2,996)
(4,962)
 
Net receivables for securities purchases
109 
795 
 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
Proceeds from the sale of securities
542,246 
633,410 
478,813 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
871,000 
779,586 
 
ARIZONA PUBLIC SERVICE COMPANY |
Equity securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
417,390 
353,261 
 
Total Unrealized Gains
248,623 
188,091 
 
Total Unrealized Losses
0 
0 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
417,390 
353,261 
 
ARIZONA PUBLIC SERVICE COMPANY |
Fixed income securities
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
446,277 
425,530 
 
Total Unrealized Gains
11,537 
9,820 
 
Total Unrealized Losses
(2,996)
(4,962)
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
446,277 
425,530 
 
ARIZONA PUBLIC SERVICE COMPANY |
Cash and cash equivalents
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
Fair Value
7,224 
0 
 
Total Unrealized Gains
0 
0 
 
Total Unrealized Losses
0 
0 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
Total
$ 7,224 
$ 0 
 
Investments - Narrative (Details) (Fixed income securities, USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
 
 
Schedule of Held-to-maturity Securities [Line Items]
 
 
Coal reclamation escrow account
$ 30,000,000 
 
Proceeds from sale of securities
4,000,000 
0 
4CA
 
 
Schedule of Held-to-maturity Securities [Line Items]
 
 
Coal reclamation escrow account
$ 2,000,000 
 
Changes in Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended 12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2017
Pension and Other Postretirement Benefits
Dec. 31, 2016
Pension and Other Postretirement Benefits
Dec. 31, 2017
Derivative Instruments
Dec. 31, 2016
Derivative Instruments
Dec. 31, 2017
Total
Dec. 31, 2016
Total
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2015
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Pension and Other Postretirement Benefits
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Pension and Other Postretirement Benefits
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Derivative Instruments
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Derivative Instruments
Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Total
Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Total
Changes in accumulated other comprehensive income (loss) by component
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
$ 5,135,730 
$ 4,935,912 
$ 4,719,457 
$ 4,519,102 
$ (39,070)
$ (37,593)
$ (4,752)
$ (7,155)
$ (43,822)
$ (44,748)
$ 5,385,869 
$ 5,037,970 
$ 4,814,794 
$ 4,629,852 
$ (20,671)
$ (19,942)
$ (4,752)
$ (7,155)
$ (25,423)
$ (27,097)
OCI (loss) before reclassifications
 
 
 
 
(6,438)
(4,509)
(35)
(538)
(6,473)
(5,047)
 
 
 
 
(6,884)
(3,821)
(35)
(538)
(6,919)
(4,359)
Amounts reclassified from accumulated other comprehensive loss
 
 
 
 
3,068 
3,032 
2,225 
2,941 
5,293 
5,973 
 
 
 
 
3,134 
3,092 
2,225 
2,941 
5,359 
6,033 
Ending balance
$ 5,135,730 
$ 4,935,912 
$ 4,719,457 
$ 4,519,102 
$ (42,440)
$ (39,070)
$ (2,562)
$ (4,752)
$ (45,002)
$ (43,822)
$ 5,385,869 
$ 5,037,970 
$ 4,814,794 
$ 4,629,852 
$ (24,421)
$ (20,671)
$ (2,562)
$ (4,752)
$ (26,983)
$ (25,423)
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, 2017
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 759,659 
$ 1,183,322 
$ 944,587 
$ 677,728 
$ 739,199 
$ 1,166,922 
$ 915,394 
$ 677,167 
$ 3,565,296 
$ 3,498,682 
$ 3,495,443 
Operating expenses
 
 
 
 
 
 
 
 
2,630,869 
2,642,698 
2,640,841 
OPERATING INCOME
90,610 
466,082 
304,229 
73,506 
122,816 
451,258 
231,748 
50,162 
934,427 
855,984 
854,602 
Other
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
29,478 
27,704 
18,013 
Interest expense
 
 
 
 
 
 
 
 
219,796 
205,720 
194,964 
Income tax benefit
20,775 
144,319 
88,967 
4,211 
27,309 
141,446 
65,742 
1,914 
258,272 
236,411 
237,720 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
21,629 
276,072 
167,443 
23,312 
53,246 
263,027 
121,308 
4,453 
488,456 
442,034 
437,257 
Other comprehensive income
 
 
 
 
 
 
 
 
(1,180)
926 
23,393 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
487,276 
442,960 
460,650 
Pinnacle West
 
 
 
 
 
 
 
 
 
 
 
CONDENSED FINANCIAL STATEMENTS
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
119 
370 
550 
Operating expenses
 
 
 
 
 
 
 
 
24,298 
26,424 
12,733 
OPERATING INCOME
 
 
 
 
 
 
 
 
(24,179)
(26,054)
(12,183)
Other
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
 
 
 
 
 
 
 
 
507,495 
462,027 
446,508 
Other expense
 
 
 
 
 
 
 
 
(2,715)
(1,771)
(3,302)
Total
 
 
 
 
 
 
 
 
504,780 
460,256 
443,206 
Interest expense
 
 
 
 
 
 
 
 
5,633 
3,151 
2,672 
INCOME BEFORE INCOME TAXES
 
 
 
 
 
 
 
 
474,968 
431,051 
428,351 
Income tax benefit
 
 
 
 
 
 
 
 
(13,488)
(10,983)
(8,906)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
488,456 
442,034 
437,257 
Other comprehensive income
 
 
 
 
 
 
 
 
(1,180)
926 
23,393 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
$ 487,276 
$ 442,960 
$ 460,650 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Balance Sheets (Details) (USD $)
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Current assets
 
 
 
 
Cash and cash equivalents
$ 13,892,000 
$ 8,881,000 
$ 39,488,000 
$ 7,604,000 
Accounts receivable
305,147,000 
250,491,000 
 
 
Income tax receivable
0 
3,751,000 
 
 
Other current assets
48,039,000 
45,028,000 
 
 
Total current assets
1,016,288,000 
822,219,000 
 
 
Investments and other assets
 
 
 
 
Other assets
84,531,000 
69,063,000 
 
 
Total investments and other assets
955,582,000 
848,650,000 
 
 
Total Assets
17,019,082,000 
16,004,253,000 
 
 
Current liabilities
 
 
 
 
Accounts payable
256,442,000 
264,631,000 
 
 
Accrued taxes
148,946,000 
138,964,000 
 
 
Common dividends payable
77,667,000 
72,926,000 
 
 
Short-term borrowings
95,400,000 
177,200,000 
 
 
Current maturities of long-term debt
82,000,000 
125,000,000 
 
 
Other current liabilities
246,529,000 
244,000,000 
 
 
Total current liabilities
1,197,852,000 
1,292,946,000 
 
 
Deferred credits and other
 
 
 
 
Long-term debt less current maturities
4,789,713,000 
4,021,785,000 
 
 
Other
148,909,000 
156,784,000 
 
 
Total deferred credits and other
5,895,787,000 
5,753,610,000 
 
 
Common stock equity
 
 
 
 
Common stock
2,614,805,000 
2,596,030,000 
 
 
Accumulated other comprehensive loss
(45,002,000)
(43,822,000)
 
 
Retained earnings
2,442,511,000 
2,255,547,000 
 
 
Total shareholders’ equity
5,006,690,000 
4,803,622,000 
 
 
Noncontrolling interests
129,040,000 
132,290,000 
 
 
Total equity
5,135,730,000 
4,935,912,000 
4,719,457,000 
4,519,102,000 
Total Liabilities and Equity
17,019,082,000 
16,004,253,000 
 
 
Pinnacle West
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
41,000 
41,000 
17,432,000 
3,088,000 
Accounts receivable
93,554,000 
81,751,000 
 
 
Income tax receivable
19,124,000 
0 
 
 
Other current assets
267,000 
340,000 
 
 
Total current assets
112,986,000 
82,132,000 
 
 
Investments and other assets
 
 
 
 
Investments in subsidiaries
5,465,137,000 
5,084,035,000 
 
 
Deferred income taxes
54,352,000 
53,805,000 
 
 
Other assets
44,613,000 
38,500,000 
 
 
Total investments and other assets
5,564,102,000 
5,176,340,000 
 
 
Total Assets
5,677,088,000 
5,258,472,000 
 
 
Current liabilities
 
 
 
 
Accounts payable
7,638,000 
5,421,000 
 
 
Accrued taxes
8,927,000 
12,050,000 
 
 
Common dividends payable
77,667,000 
72,926,000 
 
 
Short-term borrowings
95,400,000 
41,700,000 
 
 
Current maturities of long-term debt
0 
125,000,000 
 
 
Other current liabilities
17,417,000 
31,182,000 
 
 
Total current liabilities
207,049,000 
288,279,000 
 
 
Deferred credits and other
 
 
 
 
Long-term debt less current maturities
298,421,000 
0 
 
 
Pension liabilities
20,758,000 
21,057,000 
 
 
Other
15,130,000 
13,224,000 
 
 
Total deferred credits and other
35,888,000 
34,281,000 
 
 
Common stock equity
 
 
 
 
Common stock
2,609,181,000 
2,591,897,000 
 
 
Accumulated other comprehensive loss
(45,002,000)
(43,822,000)
 
 
Retained earnings
2,442,511,000 
2,255,547,000 
 
 
Total shareholders’ equity
5,006,690,000 
4,803,622,000 
 
 
Noncontrolling interests
129,040,000 
132,290,000 
 
 
Total equity
5,135,730,000 
4,935,912,000 
 
 
Total Liabilities and Equity
$ 5,677,088,000 
$ 5,258,472,000 
 
 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Statements of Cash Flows (Details) (USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2017
Pinnacle West
Dec. 31, 2016
Pinnacle West
Dec. 31, 2015
Pinnacle West
Cash Flows from Operating Activities
 
 
 
 
 
 
Net income
$ 507,949,000 
$ 461,527,000 
$ 456,190,000 
$ 488,456,000 
$ 442,034,000 
$ 437,257,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Equity in earnings of subsidiaries - net
 
 
 
(507,495,000)
(462,027,000)
(446,508,000)
Depreciation and amortization
610,629,000 
565,011,000 
571,664,000 
76,000 
85,000 
92,000 
Deferred income taxes
248,164,000 
206,870,000 
236,819,000 
(264,000)
(12,402,000)
12,967,000 
Accounts receivable
(93,797,000)
(2,489,000)
(22,219,000)
(2,106,000)
15,823,000 
11,336,000 
Accounts payable
(23,769,000)
(66,917,000)
(34,266,000)
(11,162,000)
10,402,000 
637,000 
Accrued taxes and income tax receivable - net
 
 
 
(22,247,000)
20,041,000 
(12,882,000)
Dividends received from subsidiaries
 
 
 
296,800,000 
239,300,000 
266,900,000 
Other
 
 
 
15,092,000 
5,514,000 
(6,995,000)
Net cash flow provided by operating activities
1,118,036,000 
1,023,390,000 
1,094,327,000 
257,150,000 
258,770,000 
262,804,000 
Cash flows from investing activities
 
 
 
 
 
 
Construction work in progress
 
 
 
0 
(18,457,000)
(3,462,000)
Investments in subsidiaries
 
 
 
(178,027,000)
(19,242,000)
(3,491,000)
Repayments of loans from subsidiaries
 
 
 
2,987,000 
1,026,000 
157,000 
Advances of loans to subsidiaries
 
 
 
(6,388,000)
(2,092,000)
(1,010,000)
Net cash flow used for investing activities
(1,428,537,000)
(1,252,078,000)
(1,066,233,000)
(181,428,000)
(38,765,000)
(7,806,000)
Cash flows from financing activities
 
 
 
 
 
 
Issuance of long-term debt
848,239,000 
693,151,000 
842,415,000 
298,761,000 
0 
0 
Short-term debt borrowings under revolving credit facility
58,000,000 
40,000,000 
0 
58,000,000 
40,000,000 
0 
Short-term debt repayments under revolving credit facility
(32,000,000)
0 
0 
(32,000,000)
0 
0 
Commercial Paper - net
 
 
 
27,700,000 
1,700,000 
0 
Dividends paid on common stock
(289,793,000)
(274,229,000)
(260,027,000)
(289,793,000)
(274,229,000)
(260,027,000)
Repayment of long-term debt
(125,000,000)
(370,430,000)
(415,570,000)
(125,000,000)
0 
0 
Common stock equity issuance and purchases - net
(13,390,000)
(4,867,000)
19,373,000 
(13,390,000)
(4,867,000)
19,373,000 
Net cash flow provided by financing activities
315,512,000 
198,081,000 
3,790,000 
(75,722,000)
(237,396,000)
(240,654,000)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
5,011,000 
(30,607,000)
31,884,000 
0 
(17,391,000)
14,344,000 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
8,881,000 
39,488,000 
7,604,000 
41,000 
17,432,000 
3,088,000 
CASH AND CASH EQUIVALENTS AT END OF YEAR
$ 13,892,000 
$ 8,881,000 
$ 39,488,000 
$ 41,000 
$ 41,000 
$ 17,432,000 
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) (Reserve for uncollectibles., USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Pinnacle West
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
$ 3,037 
$ 3,125 
$ 3,094 
Additions, Charged to cost and expenses
6,836 
4,025 
4,073 
Additions, Charged to other accounts
0 
0 
0 
Deductions
7,360 
4,113 
4,042 
Balance at end of period
2,513 
3,037 
3,125 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Changes in reserve for uncollectibles
 
 
 
Balance at beginning of period
3,037 
3,125 
3,094 
Additions, Charged to cost and expenses
6,836 
4,025 
4,073 
Additions, Charged to other accounts
0 
0 
0 
Deductions
7,360 
4,113 
4,042 
Balance at end of period
$ 2,513 
$ 3,037 
$ 3,125