PINNACLE WEST CAPITAL CORP, 10-K filed on 2/24/2017
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2016
Feb. 17, 2017
Jun. 30, 2016
Entity Information [Line Items]
 
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
 
Entity Central Index Key
0000764622 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2016 
 
 
Amendment Flag
false 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Public Float
 
 
$ 8,961,361,256 
Entity Common Stock, Shares Outstanding
 
111,340,169 
 
Document Fiscal Year Focus
2016 
 
 
Document Fiscal Period Focus
FY 
 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Entity Information [Line Items]
 
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY 
 
 
Entity Central Index Key
0000007286 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2016 
 
 
Amendment Flag
false 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Non-accelerated Filer 
 
 
Entity Public Float
 
 
$ 0 
Entity Common Stock, Shares Outstanding
 
71,264,947 
 
Document Fiscal Year Focus
2016 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
OPERATING REVENUES
$ 3,498,682 
$ 3,495,443 
$ 3,491,632 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,075,510 
1,101,298 
1,179,829 
Operations and maintenance
911,319 
868,377 
908,025 
Depreciation and amortization
485,829 
494,422 
417,358 
Taxes other than income taxes
166,499 
171,812 
172,295 
Other expenses
3,541 
4,932 
2,883 
Total
2,642,698 
2,640,841 
2,680,390 
OPERATING INCOME
855,984 
854,602 
811,242 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
42,140 
35,215 
30,790 
Other income (Note 17)
901 
621 
9,608 
Other expense (Note 17)
(15,337)
(17,823)
(21,746)
Total
27,704 
18,013 
18,652 
INTEREST EXPENSE
 
 
 
Interest charges
205,720 
194,964 
200,950 
Allowance for borrowed funds used during construction (Note 1)
(19,970)
(16,259)
(15,457)
Total
185,750 
178,705 
185,493 
INCOME BEFORE INCOME TAXES
697,938 
693,910 
644,401 
INCOME TAXES (Note 4)
236,411 
237,720 
220,705 
NET INCOME
461,527 
456,190 
423,696 
Less: Net income attributable to noncontrolling interests (Note 18)
19,493 
18,933 
26,101 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
442,034 
437,257 
397,595 
Weighted Average common shares outstanding — basic (in shares)
111,409 
111,026 
110,626 
Weighted Average common shares outstanding — diluted (in shares)
112,046 
111,552 
111,178 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.97 
$ 3.94 
$ 3.59 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 3.95 
$ 3.92 
$ 3.58 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
ELECTRIC OPERATING REVENUES
3,489,754 
3,492,357 
3,488,946 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,082,625 
1,101,298 
1,179,829 
Operations and maintenance
879,108 
853,135 
882,442 
Depreciation and amortization
484,909 
494,298 
417,264 
Taxes other than income taxes
165,779 
171,499 
171,583 
Income taxes (Note 4)
259,353 
260,143 
245,036 
Total
2,871,774 
2,880,373 
2,896,154 
OPERATING INCOME
617,980 
611,984 
592,792 
OTHER INCOME (DEDUCTIONS)
 
 
 
Income taxes (Note 4)
13,511 
14,302 
7,676 
Allowance for equity funds used during construction (Note 1)
42,140 
35,215 
30,790 
Other income (Note 17)
8,607 
2,834 
11,295 
Other expense (Note 17)
(17,514)
(19,019)
(13,403)
Total
46,744 
33,332 
36,358 
INTEREST EXPENSE
 
 
 
Interest on long-term debt
189,828 
180,123 
186,323 
Interest on short-term borrowings
7,983 
7,376 
6,796 
Debt discount, premium and expense
4,760 
4,793 
4,168 
Allowance for borrowed funds used during construction (Note 1)
(19,481)
(16,183)
(15,457)
Total
183,090 
176,109 
181,830 
INCOME TAXES (Note 4)
245,842 
245,841 
237,360 
NET INCOME
481,634 
469,207 
447,320 
Less: Net income attributable to noncontrolling interests (Note 18)
19,493 
18,933 
26,101 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 462,141 
$ 450,274 
$ 421,219 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
NET INCOME
$ 461,527 
$ 456,190 
$ 423,696 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(538)
(957)
(810)
Reclassification of net realized loss, net of tax benefit
2,941 
4,187 
13,483 
Pension and other postretirement benefits activity, net of tax (expense) benefit
(1,477)
20,163 
(2,761)
Total other comprehensive income
926 
23,393 
9,912 
COMPREHENSIVE INCOME
462,453 
479,583 
433,608 
Less: Comprehensive income attributable to noncontrolling interests
19,493 
18,933 
26,101 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
442,960 
460,650 
407,507 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
NET INCOME
481,634 
469,207 
447,320 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(538)
(957)
(809)
Reclassification of net realized loss, net of tax benefit
2,941 
4,187 
13,483 
Pension and other postretirement benefits activity, net of tax (expense) benefit
(729)
18,006 
(7,635)
Total other comprehensive income
1,674 
21,236 
5,039 
COMPREHENSIVE INCOME
483,308 
490,443 
452,359 
Less: Comprehensive income attributable to noncontrolling interests
19,493 
18,933 
26,101 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 463,815 
$ 471,510 
$ 426,258 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Net unrealized loss, tax (expense)
$ (585)
$ (342)
$ (438)
Reclassification of net realized loss, tax benefit
985 
1,801 
7,932 
Pension and other postretirement benefits activity, tax benefit (expense)
633 
(13,302)
1,307 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net unrealized loss, tax (expense)
(585)
(342)
(438)
Reclassification of net realized loss, tax benefit
985 
1,801 
7,932 
Pension and other postretirement benefits activity, tax benefit (expense)
$ 293 
$ (11,776)
$ 4,655 
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 8,881 
$ 39,488 
Customer and other receivables
250,491 
274,691 
Accrued unbilled revenues
107,949 
96,240 
Allowance for doubtful accounts
(3,037)
(3,125)
Materials and supplies (at average cost)
253,979 
234,234 
Fossil fuel (at average cost)
28,608 
45,697 
Income tax receivable (Note 4)
3,751 
589 
Assets from risk management activities (Note 16)
19,694 
15,905 
Deferred fuel and purchased power regulatory asset (Note 3)
12,465 
Other regulatory assets (Note 3)
94,410 
149,555 
Other current assets
45,028 
37,242 
Total current assets
822,219 
890,516 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
12,106 
Nuclear decommissioning trust (Notes 13 and 19)
779,586 
735,196 
Other assets
69,063 
52,518 
Total investments and other assets
848,650 
799,820 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
17,341,888 
16,222,232 
Accumulated depreciation and amortization
(5,970,100)
(5,594,094)
Net
11,371,788 
10,628,138 
Construction work in progress
1,019,947 
816,307 
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)
113,515 
117,385 
Intangible assets, net of accumulated amortization of $603,637 and $546,038
90,022 
123,975 
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228
119,004 
123,139 
Total property, plant and equipment
12,714,276 
11,808,944 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,313,428 
1,214,146 
Assets for other postretirement benefits (Note 7)
166,206 
185,997 
Other
139,474 
128,835 
Total deferred debits
1,619,108 
1,528,978 
Total Assets
16,004,253 
15,028,258 
CURRENT LIABILITIES
 
 
Accounts payable
264,631 
297,480 
Accrued taxes (Note 4)
138,964 
138,600 
Accrued interest
52,835 
56,305 
Common dividends payable
72,926 
69,363 
Short-term borrowings (Note 5)
177,200 
Current maturities of long-term debt (Note 6)
125,000 
357,580 
Customer deposits
82,520 
73,073 
Liabilities from risk management activities (Note 16)
25,836 
77,716 
Liabilities for asset retirements (Note 11)
9,135 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
Other regulatory liabilities (Note 3)
99,899 
136,078 
Other current liabilities
244,000 
197,861 
Total current liabilities
1,292,946 
1,442,317 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
4,021,785 
3,462,391 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,945,232 
2,723,425 
Regulatory liabilities (Notes 1, 3, 4 and 7)
948,916 
994,152 
Liabilities for asset retirements (Note 11)
615,340 
415,003 
Liabilities for pension benefits (Note 7)
509,310 
480,998 
Liabilities from risk management activities (Note 16)
47,238 
89,973 
Customer advances
88,672 
115,609 
Coal mine reclamation
221,910 
201,984 
Deferred investment tax credit
210,162 
187,080 
Unrecognized tax benefits (Note 4)
10,046 
9,524 
Other
156,784 
186,345 
Total deferred credits and other
5,753,610 
5,404,093 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,392,053 and 111,095,402 issued at respective dates
2,596,030 
2,541,668 
Treasury stock at cost; 55,317 shares at end of 2016 and 115,030 shares at end of 2015
(4,133)
(5,806)
Total common stock
2,591,897 
2,535,862 
Retained earnings
2,255,547 
2,092,803 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(39,070)
(37,593)
Derivative instruments (Note 16)
(4,752)
(7,155)
Total accumulated other comprehensive loss
(43,822)
(44,748)
Total shareholders’ equity
4,803,622 
4,583,917 
Noncontrolling interests (Note 18)
132,290 
135,540 
Total equity
4,935,912 
4,719,457 
Total Liabilities and Equity
16,004,253 
15,028,258 
ARIZONA PUBLIC SERVICE COMPANY
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
8,840 
22,056 
Customer and other receivables
262,611 
274,428 
Accrued unbilled revenues
107,949 
96,240 
Allowance for doubtful accounts
(3,037)
(3,125)
Materials and supplies (at average cost)
252,777 
234,234 
Fossil fuel (at average cost)
28,608 
45,697 
Income tax receivable (Note 4)
11,174 
Assets from risk management activities (Note 16)
19,694 
15,905 
Deferred fuel and purchased power regulatory asset (Note 3)
12,465 
Other regulatory assets (Note 3)
94,410 
149,555 
Other current assets
41,849 
35,765 
Total current assets
837,340 
870,755 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
12,106 
Nuclear decommissioning trust (Notes 13 and 19)
779,586 
735,196 
Other assets
48,320 
34,455 
Total investments and other assets
827,907 
781,757 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
17,228,787 
16,218,724 
Accumulated depreciation and amortization
(5,881,941)
(5,590,937)
Net
11,346,846 
10,627,787 
Construction work in progress
989,497 
812,845 
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)
113,515 
117,385 
Intangible assets, net of accumulated amortization of $603,637 and $546,038
89,868 
123,820 
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228
119,004 
123,139 
Total property, plant and equipment
12,658,730 
11,804,976 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,313,428 
1,214,146 
Assets for other postretirement benefits (Note 7)
162,911 
182,625 
Other
130,859 
127,923 
Total deferred debits
1,607,198 
1,524,694 
Total Assets
15,931,175 
14,982,182 
CURRENT LIABILITIES
 
 
Accounts payable
259,161 
291,574 
Accrued taxes (Note 4)
130,576 
144,488 
Accrued interest
52,525 
56,003 
Common dividends payable
72,900 
69,400 
Short-term borrowings (Note 5)
135,500 
Current maturities of long-term debt (Note 6)
357,580 
Customer deposits
82,520 
73,073 
Liabilities from risk management activities (Note 16)
25,836 
77,716 
Liabilities for asset retirements (Note 11)
8,703 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
Other regulatory liabilities (Note 3)
99,899 
136,078 
Other current liabilities
226,417 
180,535 
Total current liabilities
1,094,037 
1,424,708 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,999,295 
2,764,489 
Regulatory liabilities (Notes 1, 3, 4 and 7)
948,916 
994,152 
Liabilities for asset retirements (Note 11)
607,234 
415,003 
Liabilities for pension benefits (Note 7)
488,253 
459,065 
Liabilities from risk management activities (Note 16)
47,238 
89,973 
Customer advances
88,672 
115,609 
Coal mine reclamation
206,645 
201,984 
Deferred investment tax credit
210,162 
187,080 
Unrecognized tax benefits (Note 4)
37,408 
35,251 
Other
143,560 
142,683 
Total deferred credits and other
5,777,383 
5,405,289 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,421,696 
2,379,696 
Retained earnings
2,331,245 
2,148,493 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(20,671)
(19,942)
Derivative instruments (Note 16)
(4,752)
(7,155)
Total accumulated other comprehensive loss
(25,423)
(27,097)
Total shareholders’ equity
4,905,680 
4,679,254 
Noncontrolling interests (Note 18)
132,290 
135,540 
Total equity
5,037,970 
4,814,794 
Long-term debt less current maturities (Note 6)
4,021,785 
3,337,391 
Total capitalization
9,059,755 
8,152,185 
Total Liabilities and Equity
$ 15,931,175 
$ 14,982,182 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 237,535 
$ 233,665 
Accumulated amortization on intangible assets
603,637 
546,038 
Accumulated amortization on nuclear fuel
147,202 
146,228 
EQUITY
 
 
Common stock, par value
$ 0 
$ 0 
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
111,392,053 
111,095,402 
Treasury stock at cost, shares
55,317 
115,030 
ARIZONA PUBLIC SERVICE COMPANY
 
 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
237,535 
233,665 
Accumulated amortization on intangible assets
603,637 
546,038 
Accumulated amortization on nuclear fuel
$ 147,202 
$ 146,228 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$ 461,527 
$ 456,190 
$ 423,696 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
565,011 
571,664 
496,487 
Deferred fuel and purchased power
(60,303)
14,997 
(26,927)
Deferred fuel and purchased power amortization
38,152 
1,617 
40,757 
Allowance for equity funds used during construction
(42,140)
(35,215)
(30,790)
Deferred income taxes
206,870 
236,819 
159,023 
Deferred investment tax credit
23,082 
8,473 
26,246 
Change in derivative instruments fair value
(403)
(381)
339 
Stock compensation
18,883 
18,756 
33,059 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(2,489)
(22,219)
(52,672)
Accrued unbilled revenues
(11,709)
4,293 
(3,737)
Materials, supplies and fossil fuel
(1,491)
(23,945)
3,724 
Income tax receivable
(3,162)
2,509 
132,419 
Other current assets
(23,324)
3,145 
4,384 
Accounts payable
(66,917)
(34,266)
(353)
Accrued taxes
447 
(2,013)
9,615 
Other current liabilities
29,594 
603 
17,892 
Change in margin and collateral accounts — assets
673 
(324)
(343)
Change in margin and collateral accounts — liabilities
17,735 
22,776 
(24,975)
Change in unrecognized tax benefits
1,628 
(10,328)
2,778 
Change in long-term regulatory liabilities
14,682 
(20,535)
59,618 
Change in other long-term assets
(60,163)
2,426 
(56,561)
Change in other long-term liabilities
(82,793)
(100,715)
(114,052)
Net cash flow provided by operating activities
1,023,390 
1,094,327 
1,099,627 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,275,472)
(1,076,087)
(910,634)
Contributions in aid of construction
64,296 
46,546 
20,325 
Allowance for borrowed funds used during construction
(19,970)
(16,259)
(15,457)
Proceeds from nuclear decommissioning trust sales
633,410 
478,813 
356,195 
Investment in nuclear decommissioning trust
(635,691)
(496,062)
(373,444)
Other
(18,651)
(3,184)
347 
Net cash flow used for investing activities
(1,252,078)
(1,066,233)
(922,668)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
693,151 
842,415 
731,126 
Repayment of long-term debt
(370,430)
(415,570)
(652,578)
Short-term borrowings and payments — net
137,200 
(147,400)
(5,725)
Short-term debt borrowings under revolving credit facility
40,000 
Dividends paid on common stock
(274,229)
(260,027)
(246,671)
Common stock equity issuance and purchases - net
(4,867)
19,373 
15,288 
Distributions to noncontrolling interests
(22,744)
(35,002)
(20,482)
Other
161 
Net cash flow provided by (used for) financing activities
198,081 
3,790 
(178,881)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(30,607)
31,884 
(1,922)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
39,488 
7,604 
9,526 
CASH AND CASH EQUIVALENTS AT END OF YEAR
8,881 
39,488 
7,604 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
9,956 
6,550 
(102,154)
Interest, net of amounts capitalized
184,462 
170,209 
177,074 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
114,855 
83,798 
44,712 
Dividends declared but not paid
72,926 
69,363 
65,790 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
481,634 
469,207 
447,320 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
564,091 
571,540 
496,393 
Deferred fuel and purchased power
(60,303)
14,997 
(26,927)
Deferred fuel and purchased power amortization
38,152 
1,617 
40,757 
Allowance for equity funds used during construction
(42,140)
(35,215)
(30,790)
Deferred income taxes
221,167 
223,069 
155,401 
Deferred investment tax credit
23,082 
8,473 
26,246 
Change in derivative instruments fair value
(403)
(381)
339 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(1,601)
(21,040)
(52,466)
Accrued unbilled revenues
(11,709)
4,293 
(3,737)
Materials, supplies and fossil fuel
(1,454)
(23,945)
3,724 
Income tax receivable
(14,567)
135,179 
Other current assets
(21,640)
4,498 
3,766 
Accounts payable
(67,543)
(34,891)
(2,355)
Accrued taxes
(13,912)
13,378 
8,650 
Other current liabilities
5,097 
(3,718)
33,970 
Change in margin and collateral accounts — assets
673 
(324)
(343)
Change in margin and collateral accounts — liabilities
17,735 
22,776 
(24,975)
Change in unrecognized tax benefits
1,628 
(10,328)
2,778 
Change in long-term regulatory liabilities
14,682 
(20,535)
59,618 
Change in other long-term assets
(45,866)
(813)
(62,739)
Change in other long-term liabilities
(76,855)
(82,628)
(85,642)
Net cash flow provided by operating activities
1,009,948 
1,100,030 
1,124,167 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,248,010)
(1,072,053)
(910,084)
Contributions in aid of construction
64,296 
46,546 
20,325 
Allowance for borrowed funds used during construction
(19,481)
(16,183)
(15,457)
Proceeds from nuclear decommissioning trust sales
633,410 
478,813 
356,195 
Investment in nuclear decommissioning trust
(635,691)
(496,062)
(373,444)
Other
(13,865)
(1,093)
347 
Net cash flow used for investing activities
(1,219,341)
(1,060,032)
(922,118)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
693,151 
842,415 
606,126 
Repayment of long-term debt
(370,430)
(415,570)
(527,578)
Short-term borrowings and payments — net
135,500 
(147,400)
(5,725)
Dividends paid on common stock
(281,300)
(266,900)
(253,600)
Equity infusion from Pinnacle West
42,000 
Distributions to noncontrolling interests
(22,744)
(35,002)
(20,482)
Net cash flow provided by (used for) financing activities
196,177 
(22,457)
(201,259)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(13,216)
17,541 
790 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
22,056 
4,515 
3,725 
CASH AND CASH EQUIVALENTS AT END OF YEAR
8,840 
22,056 
4,515 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
26,864 
14,831 
(86,054)
Interest, net of amounts capitalized
181,809 
167,670 
173,436 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
114,874 
83,798 
44,712 
Dividends declared but not paid
$ 72,900 
$ 69,400 
$ 65,800 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
ARIZONA PUBLIC SERVICE COMPANY
ARIZONA PUBLIC SERVICE COMPANY
Common Stock
ARIZONA PUBLIC SERVICE COMPANY
Additional Paid-In Capital
ARIZONA PUBLIC SERVICE COMPANY
Retained Earnings
ARIZONA PUBLIC SERVICE COMPANY
Accumulated Other Comprehensive Income (Loss)
ARIZONA PUBLIC SERVICE COMPANY
Noncontrolling Interests
Beginning balance at Dec. 31, 2013
$ 4,340,460 
$ 2,491,558 
$ (4,308)
$ 1,785,273 
$ (78,053)
$ 145,990 
$ 4,454,874 
$ 178,162 
$ 2,379,696 
$ 1,804,398 
$ (53,372)
$ 145,990 
Beginning Balance (in shares) at Dec. 31, 2013
 
110,280,703 
98,944 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
423,696 
 
 
397,595 
 
26,101 
447,320 
 
 
421,219 
 
26,101 
Other comprehensive income
9,912 
 
 
 
9,912 
 
5,039 
 
 
 
5,039 
 
Dividends on common stock
(256,803)
 
 
(256,803)
 
 
(256,900)
 
 
(256,900)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
21,412 
21,412 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
369,059 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(7,893)
 
(7,893)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(139,746)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
8,800 
 
8,800 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
160,290 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(20,482)
 
 
 
 
(20,482)
(20,482)
 
 
 
 
(20,482)
Ending balance at Dec. 31, 2014
4,519,102 
2,512,970 
(3,401)
1,926,065 
(68,141)
151,609 
4,629,852 
178,162 
2,379,696 
1,968,718 
(48,333)
151,609 
Ending Balance (in shares) at Dec. 31, 2014
 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
456,190 
 
 
437,257 
 
18,933 
469,207 
 
 
450,274 
 
18,933 
Other comprehensive income
23,393 
 
 
 
23,393 
 
21,236 
 
 
 
21,236 
 
Dividends on common stock
(270,519)
 
 
(270,519)
 
 
(270,500)
 
 
(270,500)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
28,698 
28,698 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
445,640 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(10,136)
 
(10,136)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(154,751)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
7,731 
 
7,731 
 
 
 
 
 
 
 
 
 
Stock compensation cumulative effect adjustments
45,855 
40,380 
 
5,475 
 
 
5,411 
 
 
5,411 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
118,121 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(35,002)
 
 
 
 
(35,002)
(35,002)
 
 
 
 
(35,002)
Ending balance at Dec. 31, 2015
4,719,457 
2,541,668 
(5,806)
2,092,803 
(44,748)
135,540 
4,814,794 
178,162 
2,379,696 
2,148,493 
(27,097)
135,540 
Ending Balance (in shares) at Dec. 31, 2015
111,095,402 
111,095,402 
115,030 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
461,527 
 
 
442,034 
 
19,493 
481,634 
 
 
462,141 
 
19,493 
Other comprehensive income
926 
 
 
 
926 
 
1,674 
 
 
 
1,674 
 
Dividends on common stock
(284,765)
 
 
(284,765)
 
 
(284,800)
 
 
(284,800)
 
 
Issuance of common stock
13,982 
13,982 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
296,651 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(9,087)
 
(9,087)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(128,105)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
10,760 
 
10,760 
 
 
 
 
 
 
 
 
 
Equity infusion from Pinnacle West
 
 
 
 
 
 
42,000 
 
42,000 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
187,818 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(22,743)
 
 
 
 
(22,743)
(22,743)
 
 
 
 
(22,743)
Ending balance at Dec. 31, 2016
$ 4,935,912 
$ 2,596,030 
$ (4,133)
$ 2,255,547 
$ (43,822)
$ 132,290 
$ 5,037,970 
$ 178,162 
$ 2,421,696 
$ 2,331,245 
$ (25,423)
$ 132,290 
Ending Balance (in shares) at Dec. 31, 2016
111,392,053 
111,392,053 
55,317 
 
 
 
 
71,264,947 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.56 
$ 2.44 
$ 2.33 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies

Description of Business and Basis of Presentation
 
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.  El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).
 
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

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

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

 
 

 
 

Stock compensation
$

 
$
18,756

 
$
18,756

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

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

 
 

 
 

Stock compensation
$

 
$
33,059

 
$
33,059

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


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

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

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

Pinnacle West’s property, plant and equipment included in the December 31, 2016 and 2015 consolidated balance sheets is composed of the following (dollars in thousands):

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

 
$
7,336,902

Transmission
2,746,508

 
2,494,744

Distribution
5,738,801

 
5,543,561

General plant
981,681

 
847,025

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

 
16,222,232

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

 
10,628,138

Construction work in progress
1,019,947

 
816,307

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

 
117,385

Intangible assets, net of accumulated amortization
90,022

 
123,975

Nuclear fuel, net of accumulated amortization
119,004

 
123,139

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

 
$
11,808,944



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

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 11.
 
APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations.  APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.
 
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2016 were as follows:
 
Fossil plant — 19 years;
Nuclear plant — 27 years;
Other generation — 26 years;
Transmission — 39 years;
Distribution — 33 years; and
General plant — 7 years.
 
Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS's acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. See Note 3 for further discussion. These costs were deferred and are now being amortized on the depreciation line of the Consolidated Statements of Income.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $422 million in 2016, $430 million in 2015, and $396 million in 2014. For the years 2014 through 2016, the depreciation rates ranged from a low of 0.30% to a high of 14.12%.  The weighted-average depreciation rate was 2.66% in 2016, 2.74% in 2015, and 2.77% in 2014.
 
Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
 
AFUDC was calculated by using a composite rate of 7.17% for 2016, 8.02% for 2015, and 8.47% for 2014.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
 
Materials and Supplies
 
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
 
Fair Value Measurements
 
We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis.  Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).
 
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
 
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
 
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.
 
See Note 13 for additional information about fair value measurements.
 
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  See Note 16 for additional information about our derivative instruments.
 
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
 
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries.  We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.  See Note 7 for additional information on pension and other postretirement benefits.
 
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE suspended the fee.  In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2016. See Note 10 for information on spent nuclear fuel disposal costs.
 
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).
 
Cash and Cash Equivalents
 
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
 
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
 
 
Year ended December 31,
 
2016
 
2015
 
2014
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
9,956

 
$
6,550

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

 
170,209

 
177,074

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
114,855

 
$
83,798

 
$
44,712

Dividends declared but not paid
72,926

 
69,363

 
65,790


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

Preferred Stock

At December 31, 2016, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.
New Accounting Standards
New Accounting Standards
New Accounting Standards
 
ASU 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting

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

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

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

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

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.

We plan on adopting this standard on January 1, 2018, and are currently evaluating the transition method and the effect on our financial statements. As part of our evaluation we continue to actively monitor certain industry issues being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups may impact our application of the standard, specifically in regards to the treatment of contributions in aid of construction.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements.

ASU 2016-02, Leases

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

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

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


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

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

The principal provisions of the application are:

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

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

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

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

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

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

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

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

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

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

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

Prior Rate Case Filing
 
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
Settlement Agreement
 
The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million.
 
Other key provisions of the 2012 Settlement Agreement include the following:
An authorized return on common equity of 10.0%;
A capital structure comprised of 46.1% debt and 53.9% common equity;
A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;
Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows: 
Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and
Deferral of 100% in all years if Arizona property tax rates decrease;
A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);
Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;
Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
Modifications to the PSA, including the elimination of the 90/10 sharing provision;
A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the settlement agreement for the 2009 retail rate case (the "2009 Settlement Agreement");
Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;
Modification of the TCA to streamline the process for future transmission-related rate changes; and
Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.
 
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
 
In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC.

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.

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

In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the EPA.  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  APS cannot predict the outcome of this proceeding.
 
Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. 

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

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program.

On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on the Company’s 2017 DSM Plan.    
 
Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.
 
PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2016 and 2015 (dollars in thousands):
 
 
Year Ended December 31,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,926

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

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

 
$
(9,688
)

 
The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC staff.  Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2015.

Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2016.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies to make changes to their protocols in the future. As a result, APS is evaluating how its formula rate protocols compare with more recently approved formula rate protocols and anticipates that it will make a filing to update its formula rate protocols in the first quarter of 2017.
 
Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units.
 
APS files for a LFCR adjustment every January.  APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two month delay in implementation did not have an adverse effect on APS. APS filed its 2017 LFCR adjustment on January 13, 2017. APS requested an adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective the first billing cycle of March 2017.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, the ALJ issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

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

In addition, the ACC made the following determinations:

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

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

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

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

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

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

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

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.

System Benefits Charge

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

Subpoena from Arizona Corporation Commissioner Robert Burns

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

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

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas.  Commissioner Burns has also scheduled a workshop in this matter for March 17, 2017.  APS and Pinnacle West cannot predict the outcome of this matter.

Four Corners
 
On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $64 million as of December 31, 2016 and is being amortized in rates over a total of 10 years.  On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter will be resolved.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement” that, upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.   On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

Cholla

On September 11, 2014, APS announced that it would close Cholla Unit 2 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. On January 13, 2017, EPA approved a final rule incorporating APS's compromise proposal. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and is seeking recovery of the unit’s decommissioning and other retirement-related costs over the previously estimated remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($116 million as of December 31, 2016), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

Navajo Plant

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


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

 
$
711,059

 
$

 
$
619,223

Retired power plant costs
2033
 
9,913

 
117,591

 
9,913

 
127,518

Income taxes - AFUDC equity
2046
 
6,305

 
152,118

 
5,495

 
133,712

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

 
42,963

 
71,852

 
69,697

Four Corners cost deferral
2024
 
6,689

 
56,894

 
6,689

 
63,582

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

 
54,356

 
1,766

 
48,462

Lost fixed cost recovery
2017
 
61,307

 

 
45,507

 

Palo Verde VIEs (Note 18)
2046
 

 
18,775

 

 
18,143

Deferred compensation
2036
 

 
35,595

 

 
34,751

Deferred property taxes
(d)
 

 
73,200

 

 
50,453

Loss on reacquired debt
2038
 
1,637

 
16,942

 
1,515

 
16,375

AG-1 deferral
2018
 

 
5,868

 

 

Demand side management (b)
2017
 
3,744

 

 

 

Tax expense of Medicare subsidy
2024
 
1,513

 
10,589

 
1,520

 
12,163

Transmission vegetation management
2016
 

 

 
4,543

 

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,708

 
332

 
11,040

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

 

 

 

Coal reclamation
2026
 
418

 
5,182

 
418

 
6,085

Other
Various
 
432

 
1,588

 
5

 
2,942

Total regulatory assets (e)
 
 
$
106,875

 
$
1,313,428

 
$
149,555

 
$
1,214,146


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.  See Note 7 for further discussion.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
Per the provision of the 2012 Settlement Agreement.
(e)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
The detail of regulatory liabilities is as follows (dollars in thousands):
 
Amortization Through
 
December 31, 2016
 
December 31, 2015
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$

 
$
279,976

 
$

 
$
277,554

Removal costs
(a)
 
29,899

 
223,145

 
39,746

 
240,367

Other postretirement benefits
(d)
 
32,662

 
123,913

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2046
 
4,368

 
108,827

 
3,604

 
97,175

Income taxes - change in rates
2045
 
1,771

 
70,898

 
1,113

 
72,454

Spent nuclear fuel
2047
 

 
71,726

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
26,809

 

 
43,773

 
4,365

Demand side management (b)
2019
 

 
20,472

 
6,079

 
19,115

Sundance maintenance
2030
 

 
15,287

 

 
13,678

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

 

 
9,688

 

Deferred gains on utility property
2018
 
2,063

 
8,895

 
2,062

 
6,001

Four Corners coal reclamation
2031
 

 
18,248

 

 
8,920

Other
Various
 
2,327

 
7,529

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
99,899

 
$
948,916

 
$
145,766

 
$
994,152


(a)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal (see Note 11).
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
See Note 7.
Income Taxes
Income Taxes
Income Taxes
 
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates.
 
In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.
 
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18).  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income.
 
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Total unrecognized tax benefits, January 1
$
34,447

 
$
44,775

 
$
41,997

 
$
34,447

 
$
44,775

 
$
41,997

Additions for tax positions of the current year
2,695

 
2,175

 
4,309

 
2,695

 
2,175

 
4,309

Additions for tax positions of prior years
886

 

 
751

 
886

 

 
751

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

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

 

 

 

 

 

Lapses of applicable statute of limitations

 
(2,259
)
 

 

 
(2,259
)
 

Total unrecognized tax benefits, December 31
$
36,075