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