PINNACLE WEST CAPITAL CORP, 10-Q filed on 11/3/2017
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2017
Oct. 27, 2017
Entity Information [Line Items]
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2017 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
111,729,775 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q3 
 
APS
 
 
Entity Information [Line Items]
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY  
 
Entity Central Index Key
0000007286  
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2017 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
71,264,947 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q3 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
OPERATING REVENUES
$ 1,183,322 
$ 1,166,922 
$ 2,805,637 
$ 2,759,483 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
310,469 
336,120 
777,475 
832,253 
Operations and maintenance
224,305 
217,568 
658,294 
703,042 
Depreciation and amortization
133,912 
120,428 
387,278 
362,977 
Taxes other than income taxes
45,169 
41,284 
133,294 
125,902 
Other expenses
3,385 
264 
5,479 
2,141 
Total
717,240 
715,664 
1,961,820 
2,026,315 
OPERATING INCOME
466,082 
451,258 
843,817 
733,168 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
12,728 
10,194 
32,666 
31,079 
Other income (Note 8)
1,091 
71 
2,055 
385 
Other expense (Note 8)
(4,993)
(5,205)
(12,495)
(12,085)
Total
8,826 
5,060 
22,226 
19,379 
INTEREST EXPENSE
 
 
 
 
Interest charges
55,644 
51,293 
162,477 
154,886 
Allowance for borrowed funds used during construction
(6,000)
(4,321)
(15,378)
(14,849)
Total
49,644 
46,972 
147,099 
140,037 
INCOME BEFORE INCOME TAXES
425,264 
409,346 
718,944 
612,510 
INCOME TAXES
144,319 
141,446 
237,497 
209,102 
NET INCOME
280,945 
267,900 
481,447 
403,408 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,873 
14,620 
14,620 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
276,072 
263,027 
466,827 
388,788 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
111,835 
111,416 
111,787 
111,363 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
112,401 
112,100 
112,314 
111,987 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 2.47 
$ 2.36 
$ 4.18 
$ 3.49 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 2.46 
$ 2.35 
$ 4.16 
$ 3.47 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 0 
$ 0 
$ 1.31 
$ 1.25 
APS
 
 
 
 
ELECTRIC OPERATING REVENUES
1,178,106 
1,166,359 
2,797,590 
2,752,748 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
309,045 
339,510 
786,041 
835,643 
Operations and maintenance
215,264 
209,366 
635,769 
681,789 
Depreciation and amortization
133,486 
120,013 
386,010 
362,492 
Income taxes
153,425 
148,945 
257,182 
225,239 
Taxes other than income taxes
44,833 
40,924 
132,281 
125,370 
Total
856,053 
858,758 
2,197,283 
2,230,533 
OPERATING INCOME
322,053 
307,601 
600,307 
522,215 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Income taxes
6,892 
5,753 
13,474 
9,289 
Allowance for equity funds used during construction
12,728 
10,194 
32,666 
31,079 
Other income (Note 8)
1,478 
567 
3,682 
6,924 
Other expense (Note 8)
(6,262)
(3,776)
(16,290)
(12,956)
Total
14,836 
12,738 
33,532 
34,336 
INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
50,429 
46,970 
147,909 
142,692 
Interest on short-term borrowings
2,140 
2,401 
6,599 
6,408 
Debt discount, premium and expense
1,191 
1,196 
3,566 
3,529 
Allowance for borrowed funds used during construction
(6,000)
(4,321)
(15,378)
(14,359)
Total
47,760 
46,246 
142,696 
138,270 
NET INCOME
289,129 
274,093 
491,143 
418,281 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,873 
14,620 
14,620 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 284,256 
$ 269,220 
$ 476,523 
$ 403,661 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
NET INCOME
$ 280,945 
$ 267,900 
$ 481,447 
$ 403,408 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax expense
9 
(29)
(754)
(595)
Reclassification of net realized loss, net of tax expense
710 
798 
2,480 
2,564 
Pension and other postretirement benefits activity, net of tax expense
790 
804 
(21)
633 
Total other comprehensive income
1,509 
1,573 
1,705 
2,602 
COMPREHENSIVE INCOME
282,454 
269,473 
483,152 
406,010 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,873 
14,620 
14,620 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
277,581 
264,600 
468,532 
391,390 
APS
 
 
 
 
NET INCOME
289,129 
274,093 
491,143 
418,281 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax expense
9 
(29)
(754)
(595)
Reclassification of net realized loss, net of tax expense
710 
798 
2,480 
2,564 
Pension and other postretirement benefits activity, net of tax expense
777 
799 
81 
768 
Total other comprehensive income
1,496 
1,568 
1,807 
2,737 
COMPREHENSIVE INCOME
290,625 
275,661 
492,950 
421,018 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,873 
14,620 
14,620 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 285,752 
$ 270,788 
$ 478,330 
$ 406,398 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Net unrealized loss, tax expense
$ 5 
$ (18)
$ 684 
$ 608 
Reclassification of net realized loss, tax expense (benefit)
438 
500 
430 
691 
Pension and other postretirement benefits activity, tax benefit (expense)
487 
504 
369 
709 
Arizona Public Service Company
 
 
 
 
Net unrealized loss, tax expense
5 
(18)
684 
608 
Reclassification of net realized loss, tax expense (benefit)
438 
500 
430 
691 
Pension and other postretirement benefits activity, tax benefit (expense)
$ 480 
$ 501 
$ 262 
$ 657 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 10,674 
$ 8,881 
Customer and other receivables
425,558 
250,491 
Accrued unbilled revenues
151,976 
107,949 
Allowance for doubtful accounts
(3,051)
(3,037)
Materials and supplies (at average cost)
257,455 
253,979 
Fossil fuel (at average cost)
27,013 
28,608 
Income tax receivable
0 
3,751 
Assets from risk management activities (Note 6)
358 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
73,966 
12,465 
Other regulatory assets (Note 3)
184,351 
94,410 
Other current assets
45,905 
45,028 
Total current assets
1,174,205 
822,219 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
1,692 
1 
Nuclear decommissioning trust (Note 11)
841,980 
779,586 
Other assets
88,818 
69,063 
Total investments and other assets
932,490 
848,650 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,310,294 
17,341,888 
Accumulated depreciation and amortization
(6,037,467)
(5,970,100)
Net
11,272,827 
11,371,788 
Construction work in progress
1,379,501 
1,019,947 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
110,613 
113,515 
Intangible assets, net of accumulated amortization
256,198 
90,022 
Nuclear fuel, net of accumulated amortization
135,460 
119,004 
Total property, plant and equipment
13,154,599 
12,714,276 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,381,179 
1,313,428 
Assets for other postretirement benefits (Note 4)
193,747 
166,206 
Other
141,647 
139,474 
Total deferred debits
1,716,573 
1,619,108 
TOTAL ASSETS
16,977,867 
16,004,253 
CURRENT LIABILITIES
 
 
Accounts payable
236,746 
264,631 
Accrued taxes
228,791 
138,964 
Accrued interest
49,218 
52,835 
Common dividends payable
0 
72,926 
Short-term borrowings (Note 2)
131,400 
177,200 
Current maturities of long-term debt (Note 2)
207,000 
125,000 
Customer deposits
69,690 
82,520 
Liabilities from risk management activities (Note 6)
50,469 
25,836 
Liabilities for asset retirements (Note 14)
1,559 
9,135 
Regulatory liabilities (Note 3)
120,671 
99,899 
Other current liabilities
207,599 
244,000 
Total current liabilities
1,303,143 
1,292,946 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
4,491,048 
4,021,785 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
3,182,400 
2,945,232 
Regulatory liabilities (Note 3)
891,715 
948,916 
Liabilities for asset retirements (Note 14)
669,297 
615,340 
Liabilities for pension benefits (Note 4)
409,871 
509,310 
Liabilities from risk management activities (Note 6)
35,775 
47,238 
Customer advances
101,210 
88,672 
Coal mine reclamation
238,634 
221,910 
Deferred investment tax credit
205,870 
210,162 
Unrecognized tax benefits
12,943 
10,046 
Other
158,354 
156,784 
Total deferred credits and other
5,906,069 
5,753,610 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,666,876 and 111,392,053 issued at respective dates
2,608,825 
2,596,030 
Treasury stock at cost; 9,864 and 55,317 shares at respective dates
(833)
(4,133)
Total common stock
2,607,992 
2,591,897 
Retained earnings
2,576,193 
2,255,547 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(39,091)
(39,070)
Derivative instruments
(3,026)
(4,752)
Total accumulated other comprehensive loss
(42,117)
(43,822)
Total shareholders’ equity
5,142,068 
4,803,622 
Noncontrolling interests (Note 5)
135,539 
132,290 
Total equity
5,277,607 
4,935,912 
TOTAL LIABILITIES AND EQUITY
16,977,867 
16,004,253 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
10,633 
8,840 
Customer and other receivables
417,229 
262,611 
Accrued unbilled revenues
151,976 
107,949 
Allowance for doubtful accounts
(3,051)
(3,037)
Materials and supplies (at average cost)
256,127 
252,777 
Fossil fuel (at average cost)
27,013 
28,608 
Income tax receivable
0 
11,174 
Assets from risk management activities (Note 6)
358 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
73,966 
12,465 
Other regulatory assets (Note 3)
184,351 
94,410 
Other current assets
39,783 
41,849 
Total current assets
1,158,385 
837,340 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
1,692 
1 
Nuclear decommissioning trust (Note 11)
841,980 
779,586 
Other assets
66,418 
48,320 
Total investments and other assets
910,090 
827,907 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,195,555 
17,228,787 
Accumulated depreciation and amortization
(5,951,233)
(5,881,941)
Net
11,244,322 
11,346,846 
Construction work in progress
1,335,398 
989,497 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
110,613 
113,515 
Intangible assets, net of accumulated amortization
256,037 
89,868 
Nuclear fuel, net of accumulated amortization
135,460 
119,004 
Total property, plant and equipment
13,081,830 
12,658,730 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,381,179 
1,313,428 
Assets for other postretirement benefits (Note 4)
190,306 
162,911 
Other
129,999 
130,859 
Total deferred debits
1,701,484 
1,607,198 
TOTAL ASSETS
16,851,789 
15,931,175 
CURRENT LIABILITIES
 
 
Accounts payable
227,507 
259,161 
Accrued taxes
233,214 
130,576 
Accrued interest
48,875 
52,525 
Common dividends payable
0 
72,900 
Short-term borrowings (Note 2)
31,800 
135,500 
Current maturities of long-term debt (Note 2)
82,000 
0 
Customer deposits
69,690 
82,520 
Liabilities from risk management activities (Note 6)
50,469 
25,836 
Liabilities for asset retirements (Note 14)
1,302 
8,703 
Regulatory liabilities (Note 3)
120,671 
99,899 
Other current liabilities
202,524 
226,417 
Total current liabilities
1,068,052 
1,094,037 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
3,223,966 
2,999,295 
Regulatory liabilities (Note 3)
891,715 
948,916 
Liabilities for asset retirements (Note 14)
660,815 
607,234 
Liabilities for pension benefits (Note 4)
389,867 
488,253 
Liabilities from risk management activities (Note 6)
35,775 
47,238 
Customer advances
101,210 
88,672 
Coal mine reclamation
222,993 
206,645 
Deferred investment tax credit
205,870 
210,162 
Unrecognized tax benefits
43,704 
37,408 
Other
143,423 
143,560 
Total deferred credits and other
5,919,338 
5,777,383 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,421,696 
2,421,696 
Retained earnings
2,661,570 
2,331,245 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(20,590)
(20,671)
Derivative instruments
(3,026)
(4,752)
Total accumulated other comprehensive loss
(23,616)
(25,423)
Total shareholders’ equity
5,237,812 
4,905,680 
Noncontrolling interests (Note 5)
135,539 
132,290 
Total equity
5,373,351 
5,037,970 
Long-term debt less current maturities (Note 2)
4,491,048 
4,021,785 
Total capitalization
9,864,399 
9,059,755 
TOTAL LIABILITIES AND EQUITY
$ 16,851,789 
$ 15,931,175 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Sep. 30, 2017
Dec. 31, 2016
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
 
 
Common stock, par value (in dollars per share)
   
   
Common stock, authorized shares (in shares)
150,000,000 
150,000,000 
Common stock, issued shares (in shares)
111,666,876 
111,392,053 
Treasury stock at cost, shares (in shares)
9,864 
55,317 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 481,447 
$ 403,408 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
445,707 
422,851 
Deferred fuel and purchased power
(43,348)
(46,185)
Deferred fuel and purchased power amortization
(18,153)
28,366 
Allowance for equity funds used during construction
(32,666)
(31,079)
Deferred income taxes
211,249 
194,915 
Deferred investment tax credit
(4,293)
(6,342)
Change in derivative instruments fair value
(254)
(278)
Stock compensation
16,553 
27,588 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(206,920)
(77,908)
Accrued unbilled revenues
(44,027)
(54,291)
Materials, supplies and fossil fuel
(1,881)
(4,438)
Income tax receivable
3,751 
589 
Other current assets
(22,043)
(11,665)
Accounts payable
(24,258)
(57,237)
Accrued taxes
89,827 
80,925 
Other current liabilities
3,936 
(12,383)
Change in margin and collateral accounts — assets
(1,826)
517 
Change in margin and collateral accounts — liabilities
(1,625)
18,085 
Change in unrecognized tax benefits
5,891 
1,628 
Change in other long-term assets
(59,963)
(59,589)
Change in other long-term liabilities
(25,180)
(52,427)
Net cash flow provided by operating activities
771,924 
765,050 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(1,027,753)
(1,014,910)
Contributions in aid of construction
24,924 
39,355 
Allowance for borrowed funds used during construction
(15,378)
(14,848)
Proceeds from nuclear decommissioning trust sales
351,860 
447,419 
Investment in nuclear decommissioning trust
(353,001)
(449,129)
Other
(20,291)
(18,353)
Net cash flow used for investing activities
(1,039,639)
(1,010,466)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
549,478 
693,151 
Repayment of long-term debt
0 
(353,560)
Short-term borrowing and payments — net
(68,800)
83,300 
Short-term borrowings under revolving credit facility
23,000 
34,000 
Dividends paid on common stock
(213,927)
(203,115)
Common stock equity issuance - net of purchases
(8,870)
11,790 
Distributions to noncontrolling interests
(11,372)
(11,372)
Other
(1)
1 
Net cash flow provided by financing activities
269,508 
254,195 
NET INCREASE IN CASH AND CASH EQUIVALENTS
1,793 
8,779 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,881 
39,488 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
10,674 
48,267 
Cash paid during the period for:
 
 
Income taxes, net of refunds
2,185 
2,562 
Interest, net of amounts capitalized
147,149 
146,691 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
93,031 
91,315 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
491,143 
418,281 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
444,439 
422,365 
Deferred fuel and purchased power
(43,348)
(46,185)
Deferred fuel and purchased power amortization
(18,153)
28,366 
Allowance for equity funds used during construction
(32,666)
(31,079)
Deferred income taxes
202,256 
171,000 
Deferred investment tax credit
(4,293)
(6,342)
Change in derivative instruments fair value
(254)
(278)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(185,130)
(75,961)
Accrued unbilled revenues
(44,027)
(54,291)
Materials, supplies and fossil fuel
(1,755)
(4,368)
Income tax receivable
11,174 
0 
Other current assets
(19,100)
(9,857)
Accounts payable
(29,784)
(56,349)
Accrued taxes
102,638 
107,955 
Other current liabilities
11,747 
(30,973)
Change in margin and collateral accounts — assets
(1,826)
517 
Change in margin and collateral accounts — liabilities
(1,625)
18,085 
Change in unrecognized tax benefits
5,891 
1,628 
Change in other long-term assets
(56,375)
(54,051)
Change in other long-term liabilities
(26,049)
(32,146)
Net cash flow provided by operating activities
804,903 
766,317 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(1,008,723)
(992,735)
Contributions in aid of construction
24,924 
39,355 
Allowance for borrowed funds used during construction
(15,378)
(14,359)
Proceeds from nuclear decommissioning trust sales
351,860 
447,419 
Investment in nuclear decommissioning trust
(353,001)
(449,129)
Other
(18,098)
(14,016)
Net cash flow used for investing activities
(1,018,416)
(983,465)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
549,478 
693,151 
Repayment of long-term debt
0 
(353,560)
Short-term borrowing and payments — net
(103,700)
83,300 
Dividends paid on common stock
(219,100)
(208,400)
Distributions to noncontrolling interests
(11,372)
(11,372)
Net cash flow provided by financing activities
215,306 
203,119 
NET INCREASE IN CASH AND CASH EQUIVALENTS
1,793 
(14,029)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,840 
22,056 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
10,633 
8,027 
Cash paid during the period for:
 
 
Income taxes, net of refunds
132 
10,533 
Interest, net of amounts capitalized
142,779 
144,984 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 94,769 
$ 90,069 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (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
Balance at beginning of period 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 
Beginning balance (in shares) at Dec. 31, 2015
 
111,095,402 
115,030 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
403,408 
 
 
388,788 
 
14,620 
418,281 
 
 
403,661 
 
14,620 
Other comprehensive income
2,602 
 
 
 
2,602 
 
2,737 
 
 
 
2,737 
 
Dividends on common stock
(138,947)
 
 
(138,947)
 
 
(139,001)
 
 
(139,001)
 
 
Issuance of common stock (in shares)
 
124,968 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
11,311 
11,311 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(71,962)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,880)
 
(4,880)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
185,092 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
10,555 
 
10,556 
(1)
 
0 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(11,371)
 
 
 
 
(11,371)
(11,371)
 
 
 
 
(11,371)
Balance at end of period at Sep. 30, 2016
4,992,135 
2,552,979 
(130)
2,342,643 
(42,146)
138,789 
5,085,440 
178,162 
2,379,696 
2,413,153 
(24,360)
138,789 
Ending balance (in shares) at Sep. 30, 2016
 
111,220,370 
1,900 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Jun. 30, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
267,900 
 
 
 
 
 
274,093 
 
 
 
 
 
Other comprehensive income
1,573 
 
 
 
 
 
1,568 
 
 
 
 
 
Balance at end of period at Sep. 30, 2016
4,992,135 
 
 
 
 
 
5,085,440 
178,162 
2,379,696 
 
 
 
Ending balance (in shares) at Sep. 30, 2016
 
 
 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period 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 
Beginning balance (in shares) at Dec. 31, 2016
111,392,053 
111,392,053 
55,317 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
481,447 
 
 
466,827 
 
14,620 
491,143 
 
 
476,523 
 
14,620 
Other comprehensive income
1,705 
 
 
 
1,705 
 
1,807 
 
 
 
1,807 
 
Other
 
 
 
 
 
 
1 
 
 
0 
 
1 
Dividends on common stock
(146,204)
 
 
(146,204)
 
 
(146,198)
 
 
(146,198)
 
 
Issuance of common stock (in shares)
 
274,823 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
12,795 
12,795 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(162,312)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(12,964)
 
(12,964)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
207,765 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
16,288 
 
16,264 
23 
 
1 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(11,372)
 
 
 
 
(11,372)
(11,372)
 
 
 
 
(11,372)
Balance at end of period at Sep. 30, 2017
5,277,607 
2,608,825 
(833)
2,576,193 
(42,117)
135,539 
5,373,351 
178,162 
2,421,696 
2,661,570 
(23,616)
135,539 
Ending balance (in shares) at Sep. 30, 2017
111,666,876 
111,666,876 
9,864 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Jun. 30, 2017
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
280,945 
 
 
 
 
 
289,129 
 
 
 
 
 
Other comprehensive income
1,509 
 
 
 
 
 
1,496 
 
 
 
 
 
Balance at end of period at Sep. 30, 2017
$ 5,277,607 
 
 
 
 
 
$ 5,373,351 
$ 178,162 
$ 2,421,696 
 
 
 
Ending balance (in shares) at Sep. 30, 2017
111,666,876 
 
 
 
 
 
 
71,264,947 
 
 
 
 
Consolidation and Nature of Operations
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC ("4CA"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado").  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 5 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
 
Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
 
Our condensed 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 information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2016 Form 10-K.

Certain line items are presented in more detail on the company's Condensed 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 or financing activities. The following tables show the impacts of the reclassifications of the prior year's (previously reported) amounts (dollars in thousands):

Statements of Cash Flows for the
Nine Months Ended September 30, 2016
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
$
—

 
$
27,588

 
$
27,588

Change in other long-term liabilities
(24,839
)
 
(27,588
)
 
(52,427
)
Short-term borrowing and payments - net

117,300

 
(34,000
)
 
83,300

Short-term borrowings under revolving credit facility

—

 
34,000

 
34,000



 
 

Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Nine Months Ended 
 September 30,
 
2017
 
2016
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,185

 
$
2,562

Interest, net of amounts capitalized
147,149

 
146,691

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
93,031

 
$
91,315

Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
 
Pinnacle West
 
At September 30, 2017, Pinnacle West had a $200 million facility that matures in May 2021. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At September 30, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $36.6 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018.  Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At September 30, 2017, Pinnacle West had $63 million outstanding under the facility.
 
APS

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

On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022.

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

At September 30, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million facility that matures in May 2021 and the above-mentioned $500 million credit facility. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At September 30, 2017, APS had $31.8 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 7 for a discussion of APS’s other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of September 30, 2017
 
As of December 31, 2016
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,573,048

 
4,938,258

 
4,021,785

 
4,300,789

Total
$
4,698,048

 
$
5,063,258

 
$
4,146,785

 
$
4,425,789

 
Debt Provisions
 
An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At September 30, 2017, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $5.2 billion, and total capitalization was approximately $10.0 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.0 billion, assuming APS’s total capitalization remains the same.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%). The principal provisions of the application are described in detail in Note 3 of our 2016 Form 10-K.

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

Other key provisions of the agreement include the following:

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

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

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

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. APS cannot predict the outcome of this appeal but does not believe it will have a material impact.

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 an agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
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 for fuel and purchased power costs ("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 are described in detail in Note 3 of our 2016 Form 10-K.
  
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 costs for this program have been included in APS's rate base as part of the 2017 rate case decision.

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

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the United States Environmental Protection Agency ("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 ("DSMAC").  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery Mechanism (“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 August 5, 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, APS filed its 2017 DSM Implementation Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM 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 be increased to $66.6 million. On August 15, 2017, the ACC approved the 2017 DSM Plan.

On September 1, 2017, APS filed its 2018 DSM Implementation Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Implementation Plan seeks a reduced budget of $52.6 million and requests a waiver of the energy efficiency standard for 2018.  
 
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 following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):
 
 
Nine Months Ended 
 September 30,
 
2017
 
2016
Beginning balance
$
12,465

 
$
(9,688
)
Deferred fuel and purchased power costs — current period
43,348

 
46,185

Amounts refunded/(charged) to customers
18,153

 
(28,365
)
Ending balance
$
73,966

 
$
8,132


 
The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017 the PSA rate was revised to $0.000555 per kWh. This new rate is comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh.
 
Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters.  In July 2008, the United States Federal Energy Regulatory Commission ("FERC") approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC staff.  Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

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

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2017.

On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans.  A transmission customer intervened and protested certain aspects of APS’s filing.  FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed.  APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. The proceeding is still pending before FERC. At this time, APS is unable to predict the outcome of this proceeding.

 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 filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Tax Expense Adjustor Mechanism (“TEAM”).  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform.  In the event that federal income tax reform legislation is enacted and effective prior to the conclusion of APS’s next general rate case, and such legislation impacts APS’s annual revenue requirement by more than $5 million, the TEAM enables the pass-through of certain income tax effects to customers.  The impact to APS’s annual revenue requirement will be measured as the change in income tax expense resulting from any change to the statutory rate, the annual amortization of any resulting excess deferred income taxes, and/or the tax effects of any permanent income tax adjustments that may be included in the enacted legislation (such as limitations on interest deductibility).

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 Administrative Law Judge issued a recommendation in the docket concerning the value and cost of distributed generation ("DG") solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 rate case decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a 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 APS for exported distributed energy.

In addition, the ACC made the following determinations:

•
Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior August 19, 2017, the date new rates were effective based on APS's 2017 rate case, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

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

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

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

System Benefits Charge

The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016.  Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge.  The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. This adjustment is subsumed within the 2017 Settlement Agreement and its associated revenue requirement.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s then 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 the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself. All defendants have moved to dismiss the complaint. Oral argument at the Superior Court of Arizona for Maricopa County is scheduled for December 19, 2017. APS and Pinnacle West cannot predict the outcome of this matter.

In addition to the Superior Court of Arizona for Maricopa County proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the settlement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

Four Corners 

On December 30, 2013, APS purchased Southern California Edison Company's ("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 $58 million as of September 30, 2017 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 System Improvement Benefits ("SIB") matter. The Arizona Court of Appeals reversed an ACC rate decision involving a water company regarding the ACC’s method of finding fair value in that case, which 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, 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. The Arizona Court of Appeals ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. Supplemental briefing has been completed and the Arizona Court of Appeals heard oral argument on this matter on September 14, 2017. On September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.
 
As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS is currently considering next steps and cannot predict whether or if the enforcement division will take any action.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.
Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($109 million as of September 30, 2017), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset.
Navajo Plant
The co-owners of the Navajo Generating Station (the "Navajo Plant") and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease, at which time a new lease will allow for decommissioning activities to begin after December 2019 instead of later this year. The new lease was approved by the Navajo Nation Tribal Council on June 26, 2017. Certain additional approvals are required for specific co-owners, which are expected to occur by late 2017. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($102 million as of September 30, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.    

Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
September 30, 2017
 
December 31, 2016
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
686,511

 
$
—

 
$
711,059

Retired power plant costs
Various
 
28,647

 
194,639

 
9,913

 
117,591

Income taxes — allowance for funds used during construction ("AFUDC") equity
2047
 
6,202

 
170,622

 
6,305

 
152,118

Deferred fuel and purchased power — mark-to-market (Note 6)
2020
 
45,463

 
33,115

 
—

 
42,963

Deferred fuel and purchased power (b) (d)
2018
 
73,966

 
—

 
12,465

 
—

Four Corners cost deferral
2024
 
8,077

 
50,324

 
6,689

 
56,894

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

 
53,225

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
67,500

 
—

 
61,307

 
—

Palo Verde VIEs (Note 5)
2046
 
—

 
19,240

 
—

 
18,775

Deferred compensation
2036
 
—

 
37,265

 
—

 
35,595

Deferred property taxes
2027
 
8,569

 
77,408

 
—

 
73,200

Loss on reacquired debt
2038
 
1,637

 
15,715

 
1,637

 
16,942

Tax expense of Medicare subsidy
2024
 
1,503

 
9,074

 
1,513

 
10,589

Demand Side Management
2018
 
—

 
—

 
3,744

 
—

AG-1 deferral
2022
 
2,654

 
9,136

 
—

 
5,868

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,459

 
332

 
10,708

Transmission cost adjustor (b)
2018
 
4,345

 
—

 
—

 
1,588

Coal reclamation
2026
 
1,068

 
14,446

 
418

 
5,182

Other
Various
 
6,234

 
—

 
432

 
—

Total regulatory assets (c)
 
 
$
258,317

 
$
1,381,179

 
$
106,875

 
$
1,313,428

(a)
See Note 4 for further discussion.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
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."
(d)
Subject to a carrying charge.




The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
September 30, 2017
 
December 31, 2016
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
313,189

 
$
—

 
$
279,976

Removal costs
(a)
 
37,756

 
184,512

 
29,899

 
223,145

Other postretirement benefits
(b)
 
32,725

 
99,626

 
32,662

 
123,913

Income taxes — deferred investment tax credit
2046
 
4,315

 
106,557

 
4,368

 
108,827

Income taxes — change in rates
2046
 
2,565

 
67,136

 
1,771

 
70,898

Spent nuclear fuel
2027
 
6,562

 
64,504

 
—

 
71,726

Renewable energy standard (c)
2018
 
17,915

 
—

 
26,809

 
—

Demand side management (c)
2019
 
12,175

 
4,921

 
—

 
20,472

Sundance maintenance
2030
 
—

 
16,494

 
—

 
15,287

Deferred gains on utility property
2022
 
4,525

 
11,875

 
2,063

 
8,895

Four Corners coal reclamation
2031
 
1,857

 
19,494

 
—

 
18,248

Other
Various
 
276

 
3,407

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
120,671

 
$
891,715

 
$
99,899

 
$
948,916


(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.
(b)
See Note 4 for further discussion.
(c)
See "Cost Recovery Mechanisms" discussion above.
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates. Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $145 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. While we do not expect to transfer any funds prior to 2018, as of September 30, 2017, such methodology would result in an amount of approximately $145 million being transferred to the new trust account.

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Service cost — benefits earned during the period
$
13,715

 
$
13,448

 
$
41,144

 
$
40,344

 
$
4,280

 
$
3,748

 
$
12,839

 
$
11,245

Interest cost on benefit obligation
32,439

 
32,912

 
97,316

 
98,735

 
7,490

 
7,430

 
22,470

 
22,291

Expected return on plan assets
(43,568
)
 
(43,477
)
 
(130,703
)
 
(130,429
)
 
(13,350
)
 
(9,123
)
 
(40,051
)
 
(27,371
)
Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
20

 
132

 
61

 
395

 
(9,461
)
 
(9,471
)
 
(28,382
)
 
(28,413
)
Net actuarial loss
11,975

 
10,179

 
35,924

 
30,538

 
1,279

 
1,147

 
3,838

 
3,442

Net periodic benefit cost
$
14,581

 
$
13,194

 
$
43,742

 
$
39,583

 
$
(9,762
)
 
$
(6,269
)
 
$
(29,286
)
 
$
(18,806
)
Portion of cost charged to expense
$
7,231

 
$
6,476

 
$
21,692

 
$
19,427

 
$
(4,841
)
 
$
(3,077
)
 
$
(14,523
)
 
$
(9,230
)

 
See ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost in Note 12 for additional information.

Contributions
 
We have made voluntary contributions of $100 million to our pension plan year-to-date in 2017. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2017-2019 period. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans.
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
 
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three and nine months ended September 30, 2017 of $5 million and $15 million, respectively, and for the three and nine months ended September 30, 2016 of $5 million and $15 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
September 30, 2017
 
December 31, 2016
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
110,613

 
$
113,515

Equity — Noncontrolling interests
135,539

 
132,290


 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 million over the lease terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
Derivative Accounting
Derivative Accounting
Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates.  Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value.  See Note 10 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. Cash flow hedge accounting was discontinued for the significant majority of our contracts after May 31, 2012.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of September 30, 2017 and December 31, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
September 30, 2017
 
December 31, 2016
Power
 
GWh
736

 
1,314

Gas
 
Billion cubic feet
205

 
194


 
Gains and Losses from Derivative Instruments
 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
14

 
$
(47
)
 
$
(70
)
 
$
13

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(1,148
)
 
(1,298
)
 
(2,910
)
 
(3,255
)

(a)
During the three and nine months ended September 30, 2017 and 2016, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $2 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Net Gain (Loss) Recognized in Income
 
Operating revenues
 
$
(128
)
 
$
41

 
$
(474
)
 
$
524

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(6,100
)
 
(35,103
)
 
(64,143
)
 
(5,145
)
Total
 
 
 
$
(6,228
)
 
$
(35,062
)
 
$
(64,617
)
 
$
(4,621
)

(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed Consolidated Balance Sheets
 
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
 
We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
 
The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016, include gross liabilities of $0.4 million and $2 million, respectively, of derivative instruments designated as hedging instruments.
 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2017 and December 31, 2016.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2017:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
9,764

 
$
(9,623
)
 
$
141

 
$
217

 
$
358

Investments and other assets
 
2,137

 
(2,053
)
 
84

 
1,608

 
1,692

Total assets
 
11,901

 
(11,676
)
 
225

 
1,825

 
2,050

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(57,663
)
 
9,623

 
(48,040
)
 
(2,429
)
 
(50,469
)
Deferred credits and other
 
(37,828
)
 
2,053

 
(35,775
)
 
—

 
(35,775
)
Total liabilities
 
(95,491
)
 
11,676

 
(83,815
)
 
(2,429
)
 
(86,244
)
Total
 
$
(83,590
)
 
$
—

 
$
(83,590
)
 
$
(604
)
 
$
(84,194
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral, cash margin and option premiums that are not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $2,429, cash margin provided to counterparties of $217 and option premiums of $1,608.
 
As of December 31, 2016:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$
—

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
1

 
—

 
1

Total assets
 
54,798

 
(35,103
)
 
19,695

 
—

 
19,695

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(50,182
)
 
28,400

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

 
(47,238
)
 
—

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

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

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

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,054.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of September 30, 2017, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2017 (dollars in thousands):
 
September 30, 2017
Aggregate fair value of derivative instruments in a net liability position
$
95,491

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
81,866


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
 
We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $118 million if our debt credit ratings were to fall below investment grade.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
 
Palo Verde Nuclear Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 retail rate case settlement, this regulatory liability is being refunded to customers (see Note 3). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement will be submitted to the DOE in the fourth quarter of 2017, and payment is expected in the second quarter of 2018.

Nuclear Insurance
 
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.0 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $19 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million.
 
The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $24 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $64.8 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

For the nine months ended September 30, 2017, our fuel and purchased power commitments decreased approximately $1 billion from amounts reported at December 31, 2016 primarily due to updated estimated renewable energy purchases. The majority of these changes relate to the years 2022 and thereafter.
Other than the items described above, there have been no material changes, as of September 30, 2017, outside the normal course of business in contractual obligations from the information provided in our 2016 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

Superfund-Related Matters
 
The Comprehensive Environmental Response Compensation and Liability Act ("Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties ("PRPs").  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("RI/FS").  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in spring 2018. We estimate that our costs related to this investigation and study will be approximately $2 million.  We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
  
Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs").  These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.  Associated capital expenditures or operating costs could be material.  APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery.  The following proposed and final rules involve material compliance costs to APS.
 
Regional Haze Rules.  APS has received the final rulemaking imposing new pollution control requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. EPA approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required controls for Four Corners Units 4 and 5 would be approximately $400 million.  In addition, APS and El Paso Electric Company ("El Paso") entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs.  See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy. APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP.

On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program.  In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.
 
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.
While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.
On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

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

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether the EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017 the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017 a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings.

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

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by October 12, 2018. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. This motion was granted on April 28, 2017 by an order that held the case in abeyance for 60 days to give the litigation parties an opportunity to brief the Court as to whether to remand the proceedings back to EPA. On August 8, 2017, the Court extended the abeyance period for an additional 60 days, instructed EPA to file status updates with the Court every 30 days thereafter, and reminded EPA that it has an affirmative statutory obligation to regulate greenhouse gas emissions, based on EPA's 2009 endangerment finding as to such emissions.

Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. In its proposal, EPA states that it will issue in the near future an Advanced Notice of Proposed Rulemaking by which EPA will solicit comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act. In accordance with the D.C. Circuit Court's August 8, 2017 order (described above) regarding the ongoing Clean Power Plan litigation, the U.S. Department of Justice notified the Court of EPA's repeal proposal.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to the EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal. The carbon pollution standards for EGUs on state and tribal lands are described in detail in Note 10 of our 2016 Form 10-K.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. The environmental group plaintiffs have until November 13, 2017 to file an appeal of this dismissal order with the Ninth Circuit Court of Appeals. We cannot predict whether the plaintiffs will appeal the order or whether such appeal, if filed, will be successful.
    
Four Corners Coal Supply Agreement

Arbitration

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

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC has the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction.
The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% interest in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. The balance of this amount at September 30, 2017 is approximately $26 million, $10 million of which is due to 4CA at December 31, 2017. 4CA believes NTEC should satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements.
Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of September 30, 2017, standby letters of credit totaled $5 million and will expire in 2018. As of September 30, 2017, surety bonds expiring through 2019 totaled $62 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
 
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
 
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at September 30, 2017. Since July 6, 2016, Pinnacle West has issued four parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.
Other Income and Other Expense
Other Income and Other Expense 
Other Income and Other Expense
 
The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
917

 
$
65

 
$
1,782

 
$
370

Investment gains — net
119

 
—

 
119

 
13

Miscellaneous
55

 
6

 
154

 
2

Total other income
$
1,091

 
$
71

 
$
2,055

 
$
385

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(1,978
)
 
$
(2,502
)
 
$
(7,338
)
 
$
(6,636
)
Investment losses — net
(231
)
 
(450
)
 
(759
)
 
(1,508
)
Miscellaneous
(2,784
)
 
(2,253
)
 
(4,398
)
 
(3,941
)
Total other expense
$
(4,993
)
 
$
(5,205
)
 
$
(12,495
)
 
$
(12,085
)
Other Income and Other Expense 
The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
683

 
$
—

 
$
1,278

 
$
181

Gain on disposition of property
441

 
183

 
1,009

 
5,504

Miscellaneous
354

 
384

 
1,395

 
1,239

Total other income
$
1,478

 
$
567

 
$
3,682

 
$
6,924

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(1,970
)
 
$
(2,714
)
 
$
(7,889
)
 
$
(7,398
)
Loss on disposition of property
(3,214
)
 
36

 
(4,471
)
 
(1,048
)
Miscellaneous
(1,078
)
 
(1,098
)
 
(3,930
)
 
(4,510
)
Total other expense
$
(6,262
)
 
$
(3,776
)
 
$
(16,290
)
 
$
(12,956
)

(a)  As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).
Earnings Per Share
Earnings Per Share
Earnings Per Share
 
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and nine months ended September 30, 2017 and 2016 (in thousands, except per share amounts):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Net income attributable to common shareholders
$
276,072

 
$
263,027

 
$
466,827

 
$
388,788

Weighted average common shares outstanding — basic
111,835

 
111,416

 
111,787

 
111,363

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
566

 
684

 
527

 
624

Weighted average common shares outstanding — diluted
112,401

 
112,100

 
112,314

 
111,987

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
2.47

 
$
2.36

 
$
4.18

 
$
3.49

Net income attributable to common shareholders — diluted
$
2.46

 
$
2.35

 
$
4.16

 
$
3.47

Fair Value Measurements
Fair Value Measurements
Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.  This category includes exchange traded equities, exchange traded derivative instruments, exchange traded mutual funds, cash equivalents, and investments in U.S. Treasury securities.

Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves).  This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities.  
 
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
 
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. Instruments valued using NAV, as a practical expedient, are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to certain cash equivalents, investments held in coal reclamation escrow accounts, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans.  See Note 7 in the 2016 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.
 
Cash Equivalents
 
Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.

Coal Reclamation Escrow Account
    
Coal reclamation escrow account represents investments restricted for coal mine reclamation funding related to Four Corners. The account investments may include fixed income instruments such as municipal bond securities and cash equivalents. Fixed income securities are classified as Level 2 and are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. Cash equivalents are classified as Level 1 and are valued as described above.  
   
Risk Management Activities — Derivative Instruments
 
Exchange traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value.  We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.  These include valuation adjustments for liquidity and credit risks.  The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged.  The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.
 
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions.  Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.  Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions.
 
Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies.  We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures.  The risk control function reports to the chief financial officer’s organization.
 
Investments Held in our Nuclear Decommissioning Trust
 
The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds.  The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds.  We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.  Because the commingled funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.
 
Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper.
 
Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.
 
We price securities using information provided by our trustee for our nuclear decommissioning trust assets. Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 11 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables
 
The following table presents the fair value at September 30, 2017, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at
September 30,
2017
Assets
 

 
 

 
 

 
 

 
 
 
 

Coal reclamation escrow account (b):


 


 


 


 
 
 


Cash equivalents
$
7,175

 
$
—

 
$
—

 
$
510

 
 
 
$
7,685

Municipal bonds
—

 
24,973

 
—

 
—

 
 
 
24,973

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
8,429

 
3,472

 
(9,851
)
 
(c)
 
2,050

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
401,913

 
(d)
 
401,913

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
10,598

 
—

 
—

 
4,378

 
(e)
 
14,976

U.S. Treasury
90,776

 
—

 
—

 
—

 
 
 
90,776

Corporate debt
—

 
124,369

 
—

 
—

 
 
 
124,369

Mortgage-backed securities
—

 
116,237

 
—

 
—

 
 
 
116,237

Municipal bonds
—

 
76,412

 
—

 
—

 
 
 
76,412

Other
—

 
17,297

 
—

 
—

 
 
 
17,297

Subtotal nuclear decommissioning trust
101,374

 
334,315

 
—

 
406,291

 
 
 
841,980

Total
$
108,549

 
$
367,717

 
$
3,472

 
$
396,950

 
 
 
$
876,688

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(53,414
)
 
$
(42,077
)
 
$
9,247

 
(c)
 
$
(86,244
)

(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. Coal reclamation escrow account was presented as Coal reclamation trust in 2016.
(c)
Represents counterparty netting, margin, collateral and option premiums. See Note 6.
(d)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(e)
Represents nuclear decommissioning trust net pending securities sales and purchases.

The following table presents the fair value at December 31, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at
December 31,
2016
Assets
 

 
 

 
 

 
 

 
 
 
 

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

 
$
—

 
$
—

 
$
—

 
 
 
$
14,521

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
—

 
43,722

 
11,076

 
(35,103
)
 
(c)
 
19,695

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
353,261

 
(d)
 
353,261

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
—

 
—

 
—

 
795

 
(e)
 
795

U.S. Treasury
95,441

 
—

 
—

 
—

 
 
 
95,441

Corporate debt
—

 
111,623

 
—

 
—

 
 
 
111,623

Mortgage-backed securities
—

 
115,337

 
—

 
—

 
 
 
115,337

Municipal bonds
—

 
80,997

 
—

 
—

 
 
 
80,997

Other
—

 
22,132

 
—

 
—

 
 
 
22,132

Subtotal nuclear decommissioning trust
95,441

 
330,089

 
—

 
354,056

 
 
 
779,586

Total
$
109,962

 
$
373,811

 
$
11,076

 
$
318,953

 
 
 
$
813,802

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

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

 
(c)
 
$
(73,074
)

(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets.
(c)
Represents counterparty netting, margin, and collateral. See Note 6.
(d)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(e)
Represents nuclear decommissioning trust net pending securities sales and purchases.
 
Fair Value Measurements Classified as Level 3
 
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
 
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
 
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at September 30, 2017 and December 31, 2016:
 
 
September 30, 2017
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
2,925

 
$
19,785

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$19.87 - $38.13
 
$
28.26

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
547

 
22,292

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.13 - $2.83
 
$
2.45

Total
$
3,472

 
$
42,077

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.


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

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
10,648

 
$
32,042

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

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
428

 
26,440

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

Total
$
11,076

 
$
58,482

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
 
The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
2017
 
2016
 
2017
 
2016
Net derivative balance at beginning of period
 
$
(36,245
)
 
$
(32,380
)
 
$
(47,406
)
 
$
(32,979
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 
 
 
Included in OCI
 
(4
)
 
(10
)
 
(10
)
 
94

Deferred as a regulatory asset or liability
 
(3,769
)
 
(13,499
)
 
(11,272
)
 
(21,103
)
Settlements
 
1,733

 
5,424

 
4,855

 
11,691

Transfers into Level 3 from Level 2
 
(5,952
)
 
1,343

 
(10,340
)
 
1,725

Transfers from Level 3 into Level 2
 
5,632

 
(420
)
 
25,568

 
1,030

Net derivative balance at end of period
 
$
(38,605
)
 
$
(39,542
)
 
$
(38,605
)
 
$
(39,542
)
 
 
 
 
 
 
 
 
 
Net unrealized gains included in earnings related to instruments still held at end of period
 
$
—

 
$
—

 
$
—

 
$
—



Amounts included in earnings are recorded in either operating revenues or fuel and purchased power depending on the nature of the underlying contract.
 
Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no significant Level 1 transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.
 
Financial Instruments Not Carried at Fair Value
 
The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value.  Our short-term borrowings are classified within Level 2 of the fair value hierarchy.  See Note 2 for our long-term debt fair values.
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts
 
To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities.  APS classifies investments in decommissioning trust funds as available for sale.  As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets.  See Note 10 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities.  The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2017 and December 31, 2016 (dollars in thousands):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
September 30, 2017
 

 
 

 
 

Equity securities
$
401,913

 
$
232,727

 
$
—

Fixed income securities
435,689

 
12,272

 
(2,177
)
Net receivables (a)
4,378

 
—

 
—

Total
$
841,980

 
$
244,999

 
$
(2,177
)
(a)
Net receivables/payables relate to pending purchases and sales of securities.
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
December 31, 2016
 

 
 

 
 

Equity securities
$
353,261

 
$
188,091

 
$
—

Fixed income securities
425,530

 
9,820

 
(4,962
)
Net receivables (a)
795

 
—

 
—

Total
$
779,586

 
$
197,911

 
$
(4,962
)
(a)
Net receivables/payables relate to pending purchases and sales of securities.

The costs of securities sold are determined on the basis of specific identification.  The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Realized gains
$
598

 
$
4,033

 
$
3,904

 
$
8,753

Realized losses
(1,022
)
 
(3,345
)
 
(4,634
)
 
(6,481
)
Proceeds from the sale of securities (a)
76,496

 
156,825

 
351,860

 
447,419

(a)
Proceeds are reinvested in the trust.
 
The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2017 is as follows (dollars in thousands):
 
Fair Value
Less than one year
$
22,498

1 year – 5 years
103,033

5 years – 10 years
117,044

Greater than 10 years
193,114

Total
$
435,689

New Accounting Standards
New Accounting Standards
New Accounting Standards
    
Accounting Standards Update ("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 will adopt this standard on January 1, 2018, and expect to adopt the guidance using the modified retrospective transition approach. We do not expect the adoption of this standard will have significant impacts on our financial statement results; however, adoption of the new standard will impact our disclosures relating to revenue, and may impact our presentation of revenue. Our evaluation is ongoing, but our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment we do not expect the adoption of this guidance will impact the timing of our revenue recognition relating to these customers.

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. As of September 30, 2017 we do not have significant equity investments that would be impacted by this standard.

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. 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 will 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. At transition we do not expect this standard will have any financial statement impacts; however, the standard may have potential impacts on the accounting for future acquisitions occurring after adoption.

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

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard is effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. Our evaluation is ongoing, but at this time we do not expect the adoption of this guidance, at transition, will have a significant impact on our financial statement results. We are also currently evaluating the transition approach we will apply.
 
ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance is effective for us on January 1, 2018. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. The adoption of this guidance will change our financial statement presentation of net benefit costs and amounts eligible for capitalization; however we do not expect these changes will have a significant impact on our results of operations.

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are currently evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as hedge accounting has been discontinued for the significant majority of our contracts.
Changes in Accumulated Other Comprehensive Loss
Changes in Accumulated Other Comprehensive Loss 
Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2017
 
2016
 
2017
 
2016
Balance at beginning of period
$
(43,626
)
 
$
(43,719
)
 
$
(43,822
)
 
$
(44,748
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
9

  
(29
)
 
(754
)
 
(595
)
Amounts reclassified from accumulated other comprehensive loss (a)
710

 
798

 
2,480

 
2,564

Net current period OCI (loss)
719

 
769

  
1,726

 
1,969

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
—

 
—

 
(2,157
)
 
(1,585
)
Amounts reclassified from accumulated other comprehensive loss (b)
790

 
804

 
2,136

 
2,218

Net current period OCI (loss)
790

 
804

 
(21
)
 
633

Balance at end of period
$
(42,117
)
 
$
(42,146
)
 
$
(42,117
)
 
$
(42,146
)

(a)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 6.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
Changes in Accumulated Other Comprehensive Loss 
The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands): 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2017
 
2016
 
2017
 
2016
Balance at beginning of period
$
(25,112
)
 
$
(25,928
)
 
$
(25,423
)
 
$
(27,097
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
9

  
(29
)
 
(754
)
 
(595
)
Amounts reclassified from accumulated other comprehensive loss (a)
710

 
798

 
2,480

 
2,564

Net current period OCI (loss)
719

 
769

 
1,726

 
1,969

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
—

 
—

 
(2,121
)
 
(1,521
)
Amounts reclassified from accumulated other comprehensive loss (b)
777

 
799

 
2,202

 
2,289

Net current period OCI (loss)
777

 
799

 
81

 
768

Balance at end of period
$
(23,616
)
 
$
(24,360
)
 
$
(23,616
)
 
$
(24,360
)
(a)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 6.
(b)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 4.
Asset Retirement Obligations
Asset Retirement Obligations
Asset Retirement Obligations

In the third quarter of 2017, an updated decommissioning study was completed for the Navajo Generating Station, which resulted in an increase to the asset retirement obligation ("ARO") in the amount of $22 million.

The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2017 (dollars in thousands): 
Asset retirement obligations at January 1, 2017
$
624,475

Changes attributable to:
 

Accretion expense
24,170

Estimated cash flow revisions
22,211

Asset retirement obligations at September 30, 2017
$
670,856



In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 3.
New Accounting Standards (Policies)
New Accounting Standards
Accounting Standards Update ("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 will adopt this standard on January 1, 2018, and expect to adopt the guidance using the modified retrospective transition approach. We do not expect the adoption of this standard will have significant impacts on our financial statement results; however, adoption of the new standard will impact our disclosures relating to revenue, and may impact our presentation of revenue. Our evaluation is ongoing, but our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment we do not expect the adoption of this guidance will impact the timing of our revenue recognition relating to these customers.

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. As of September 30, 2017 we do not have significant equity investments that would be impacted by this standard.

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. 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 will 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. At transition we do not expect this standard will have any financial statement impacts; however, the standard may have potential impacts on the accounting for future acquisitions occurring after adoption.

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

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard is effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. Our evaluation is ongoing, but at this time we do not expect the adoption of this guidance, at transition, will have a significant impact on our financial statement results. We are also currently evaluating the transition approach we will apply.
 
ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance is effective for us on January 1, 2018. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. The adoption of this guidance will change our financial statement presentation of net benefit costs and amounts eligible for capitalization; however we do not expect these changes will have a significant impact on our results of operations.

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

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

Consolidation and Nature of Operations (Tables)
Schedule of reclassifications of the prior year 
The following tables show the impacts of the reclassifications of the prior year's (previously reported) amounts (dollars in thousands):

Statements of Cash Flows for the
Nine Months Ended September 30, 2016
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
$
—

 
$
27,588

 
$
27,588

Change in other long-term liabilities
(24,839
)
 
(27,588
)
 
(52,427
)
Short-term borrowing and payments - net

117,300

 
(34,000
)
 
83,300

Short-term borrowings under revolving credit facility

—

 
34,000

 
34,000

Summary of supplemental cash flow information 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Nine Months Ended 
 September 30,
 
2017
 
2016
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,185

 
$
2,562

Interest, net of amounts capitalized
147,149

 
146,691

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
93,031

 
$
91,315

Long-Term Debt and Liquidity Matters (Tables)
Schedule of estimated fair value of long-term debt, including current maturities
The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of September 30, 2017
 
As of December 31, 2016
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,573,048

 
4,938,258

 
4,021,785

 
4,300,789

Total
$
4,698,048

 
$
5,063,258

 
$
4,146,785

 
$
4,425,789

Regulatory Matters (Tables)
Schedule of changes in the deferred fuel and purchased power regulatory asset 
The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):
 
 
Nine Months Ended 
 September 30,
 
2017
 
2016
Beginning balance
$
12,465

 
$
(9,688
)
Deferred fuel and purchased power costs — current period
43,348

 
46,185

Amounts refunded/(charged) to customers
18,153

 
(28,365
)
Ending balance
$
73,966

 
$
8,132

Schedule of regulatory assets 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
September 30, 2017
 
December 31, 2016
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
686,511

 
$
—

 
$
711,059

Retired power plant costs
Various
 
28,647

 
194,639

 
9,913

 
117,591

Income taxes — allowance for funds used during construction ("AFUDC") equity
2047
 
6,202

 
170,622

 
6,305

 
152,118

Deferred fuel and purchased power — mark-to-market (Note 6)
2020
 
45,463

 
33,115

 
—

 
42,963

Deferred fuel and purchased power (b) (d)
2018
 
73,966

 
—

 
12,465

 
—

Four Corners cost deferral
2024
 
8,077

 
50,324

 
6,689

 
56,894

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

 
53,225

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
67,500

 
—

 
61,307

 
—

Palo Verde VIEs (Note 5)
2046
 
—

 
19,240

 
—

 
18,775

Deferred compensation
2036
 
—

 
37,265

 
—

 
35,595

Deferred property taxes
2027
 
8,569

 
77,408

 
—

 
73,200

Loss on reacquired debt
2038
 
1,637

 
15,715

 
1,637

 
16,942

Tax expense of Medicare subsidy
2024
 
1,503

 
9,074

 
1,513

 
10,589

Demand Side Management
2018
 
—

 
—

 
3,744

 
—

AG-1 deferral
2022
 
2,654

 
9,136

 
—

 
5,868

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,459

 
332

 
10,708

Transmission cost adjustor (b)
2018
 
4,345

 
—

 
—

 
1,588

Coal reclamation
2026
 
1,068

 
14,446

 
418

 
5,182

Other
Various
 
6,234

 
—

 
432

 
—

Total regulatory assets (c)
 
 
$
258,317

 
$
1,381,179

 
$
106,875

 
$
1,313,428

(a)
See Note 4 for further discussion.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
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."
(d)
Subject to a carrying charge.

Schedule of regulatory liabilities 
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
September 30, 2017
 
December 31, 2016
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
313,189

 
$
—

 
$
279,976

Removal costs
(a)
 
37,756

 
184,512

 
29,899

 
223,145

Other postretirement benefits
(b)
 
32,725

 
99,626

 
32,662

 
123,913

Income taxes — deferred investment tax credit
2046
 
4,315

 
106,557

 
4,368

 
108,827

Income taxes — change in rates
2046
 
2,565

 
67,136

 
1,771

 
70,898

Spent nuclear fuel
2027
 
6,562

 
64,504

 
—

 
71,726

Renewable energy standard (c)
2018
 
17,915

 
—

 
26,809

 
—

Demand side management (c)
2019
 
12,175

 
4,921

 
—

 
20,472

Sundance maintenance
2030
 
—

 
16,494

 
—

 
15,287

Deferred gains on utility property
2022
 
4,525

 
11,875

 
2,063

 
8,895

Four Corners coal reclamation
2031
 
1,857

 
19,494

 
—

 
18,248

Other
Various
 
276

 
3,407

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
120,671

 
$
891,715

 
$
99,899

 
$
948,916


(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.
(b)
See Note 4 for further discussion.
(c)
See "Cost Recovery Mechanisms" discussion above.
Retirement Plans and Other Postretirement Benefits (Tables)
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Service cost — benefits earned during the period
$
13,715

 
$
13,448

 
$
41,144

 
$
40,344

 
$
4,280

 
$
3,748

 
$
12,839

 
$
11,245

Interest cost on benefit obligation
32,439

 
32,912

 
97,316

 
98,735

 
7,490

 
7,430

 
22,470

 
22,291

Expected return on plan assets
(43,568
)
 
(43,477
)
 
(130,703
)
 
(130,429
)
 
(13,350
)
 
(9,123
)
 
(40,051
)
 
(27,371
)
Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
20

 
132

 
61

 
395

 
(9,461
)
 
(9,471
)
 
(28,382
)
 
(28,413
)
Net actuarial loss
11,975

 
10,179

 
35,924

 
30,538

 
1,279

 
1,147

 
3,838

 
3,442

Net periodic benefit cost
$
14,581

 
$
13,194

 
$
43,742

 
$
39,583

 
$
(9,762
)
 
$
(6,269
)
 
$
(29,286
)
 
$
(18,806
)
Portion of cost charged to expense
$
7,231

 
$
6,476

 
$
21,692

 
$
19,427

 
$
(4,841
)
 
$
(3,077
)
 
$
(14,523
)
 
$
(9,230
)
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Our Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
September 30, 2017
 
December 31, 2016
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
110,613

 
$
113,515

Equity — Noncontrolling interests
135,539

 
132,290

Derivative Accounting (Tables)
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) 
As of September 30, 2017 and December 31, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
September 30, 2017
 
December 31, 2016
Power
 
GWh
736

 
1,314

Gas
 
Billion cubic feet
205

 
194

Gains and losses from derivative instruments in designated cash flow accounting hedges relationships 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
14

 
$
(47
)
 
$
(70
)
 
$
13

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(1,148
)
 
(1,298
)
 
(2,910
)
 
(3,255
)

(a)
During the three and nine months ended September 30, 2017 and 2016, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments 
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Net Gain (Loss) Recognized in Income
 
Operating revenues
 
$
(128
)
 
$
41

 
$
(474
)
 
$
524

Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(6,100
)
 
(35,103
)
 
(64,143
)
 
(5,145
)
Total
 
 
 
$
(6,228
)
 
$
(35,062
)
 
$
(64,617
)
 
$
(4,621
)

(a)
Amounts are before the effect of PSA deferrals.
Schedule of offsetting assets 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2017 and December 31, 2016.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2017:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
9,764

 
$
(9,623
)
 
$
141

 
$
217

 
$
358

Investments and other assets
 
2,137

 
(2,053
)
 
84

 
1,608

 
1,692

Total assets
 
11,901

 
(11,676
)
 
225

 
1,825

 
2,050

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(57,663
)
 
9,623

 
(48,040
)
 
(2,429
)
 
(50,469
)
Deferred credits and other
 
(37,828
)
 
2,053

 
(35,775
)
 
—

 
(35,775
)
Total liabilities
 
(95,491
)
 
11,676

 
(83,815
)
 
(2,429
)
 
(86,244
)
Total
 
$
(83,590
)
 
$
—

 
$
(83,590
)
 
$
(604
)
 
$
(84,194
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral, cash margin and option premiums that are not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $2,429, cash margin provided to counterparties of $217 and option premiums of $1,608.
 
As of December 31, 2016:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$
—

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
1

 
—

 
1

Total assets
 
54,798

 
(35,103
)
 
19,695

 
—

 
19,695

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(50,182
)
 
28,400

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

 
(47,238
)
 
—

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

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

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

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,054.
Schedule of offsetting liabilities 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2017 and December 31, 2016.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2017:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
9,764

 
$
(9,623
)
 
$
141

 
$
217

 
$
358

Investments and other assets
 
2,137

 
(2,053
)
 
84

 
1,608

 
1,692

Total assets
 
11,901

 
(11,676
)
 
225

 
1,825

 
2,050

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(57,663
)
 
9,623

 
(48,040
)
 
(2,429
)
 
(50,469
)
Deferred credits and other
 
(37,828
)
 
2,053

 
(35,775
)
 
—

 
(35,775
)
Total liabilities
 
(95,491
)
 
11,676

 
(83,815
)
 
(2,429
)
 
(86,244
)
Total
 
$
(83,590
)
 
$
—

 
$
(83,590
)
 
$
(604
)
 
$
(84,194
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral, cash margin and option premiums that are not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $2,429, cash margin provided to counterparties of $217 and option premiums of $1,608.
 
As of December 31, 2016:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$
—

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
1

 
—

 
1

Total assets
 
54,798

 
(35,103
)
 
19,695

 
—

 
19,695

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(50,182
)
 
28,400

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

 
(47,238
)
 
—

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

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

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

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,054.
Information about derivative instruments that have credit-risk-related contingent features 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2017 (dollars in thousands):
 
September 30, 2017
Aggregate fair value of derivative instruments in a net liability position
$
95,491

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
81,866


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
Other Income and Other Expense (Tables)
Detail of other income and other expense 
The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
917

 
$
65

 
$
1,782

 
$
370

Investment gains — net
119

 
—

 
119

 
13

Miscellaneous
55

 
6

 
154

 
2

Total other income
$
1,091

 
$
71

 
$
2,055

 
$
385

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(1,978
)
 
$
(2,502
)
 
$
(7,338
)
 
$
(6,636
)
Investment losses — net
(231
)
 
(450
)
 
(759
)
 
(1,508
)
Miscellaneous
(2,784
)
 
(2,253
)
 
(4,398
)
 
(3,941
)
Total other expense
$
(4,993
)
 
$
(5,205
)
 
$
(12,495
)
 
$
(12,085
)
Detail of other income and other expense 
The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
683

 
$
—

 
$
1,278

 
$
181

Gain on disposition of property
441

 
183

 
1,009

 
5,504

Miscellaneous
354

 
384

 
1,395

 
1,239

Total other income
$
1,478

 
$
567

 
$
3,682

 
$
6,924

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(1,970
)
 
$
(2,714
)
 
$
(7,889
)
 
$
(7,398
)
Loss on disposition of property
(3,214
)
 
36

 
(4,471
)
 
(1,048
)
Miscellaneous
(1,078
)
 
(1,098
)
 
(3,930
)
 
(4,510
)
Total other expense
$
(6,262
)
 
$
(3,776
)
 
$
(16,290
)
 
$
(12,956
)

(a)  As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).
Earnings Per Share (Tables)
Schedule of earnings per weighted average common share outstanding
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and nine months ended September 30, 2017 and 2016 (in thousands, except per share amounts):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Net income attributable to common shareholders
$
276,072

 
$
263,027

 
$
466,827

 
$
388,788

Weighted average common shares outstanding — basic
111,835

 
111,416

 
111,787

 
111,363

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
566

 
684

 
527

 
624

Weighted average common shares outstanding — diluted
112,401

 
112,100

 
112,314

 
111,987

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
2.47

 
$
2.36

 
$
4.18

 
$
3.49

Net income attributable to common shareholders — diluted
$
2.46

 
$
2.35

 
$
4.16

 
$
3.47

Fair Value Measurements (Tables)
Fair value of assets and liabilities that are measured at fair value on a recurring basis 
The following table presents the fair value at September 30, 2017, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at
September 30,
2017
Assets
 

 
 

 
 

 
 

 
 
 
 

Coal reclamation escrow account (b):


 


 


 


 
 
 


Cash equivalents
$
7,175

 
$
—

 
$
—

 
$
510

 
 
 
$
7,685

Municipal bonds
—

 
24,973

 
—

 
—

 
 
 
24,973

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
8,429

 
3,472

 
(9,851
)
 
(c)
 
2,050

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
401,913

 
(d)
 
401,913

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
10,598

 
—

 
—

 
4,378

 
(e)
 
14,976

U.S. Treasury
90,776

 
—

 
—

 
—

 
 
 
90,776

Corporate debt
—

 
124,369

 
—

 
—

 
 
 
124,369

Mortgage-backed securities
—

 
116,237

 
—

 
—

 
 
 
116,237

Municipal bonds
—

 
76,412

 
—

 
—

 
 
 
76,412

Other
—

 
17,297

 
—

 
—

 
 
 
17,297

Subtotal nuclear decommissioning trust
101,374

 
334,315

 
—

 
406,291

 
 
 
841,980

Total
$
108,549

 
$
367,717

 
$
3,472

 
$
396,950

 
 
 
$
876,688

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(53,414
)
 
$
(42,077
)
 
$
9,247

 
(c)
 
$
(86,244
)

(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. Coal reclamation escrow account was presented as Coal reclamation trust in 2016.
(c)
Represents counterparty netting, margin, collateral and option premiums. See Note 6.
(d)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(e)
Represents nuclear decommissioning trust net pending securities sales and purchases.

The following table presents the fair value at December 31, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at
December 31,
2016
Assets
 

 
 

 
 

 
 

 
 
 
 

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

 
$
—

 
$
—

 
$
—

 
 
 
$
14,521

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
—

 
43,722

 
11,076

 
(35,103
)
 
(c)
 
19,695

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
353,261

 
(d)
 
353,261

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
—

 
—

 
—

 
795

 
(e)
 
795

U.S. Treasury
95,441

 
—

 
—

 
—

 
 
 
95,441

Corporate debt
—

 
111,623

 
—

 
—

 
 
 
111,623

Mortgage-backed securities
—

 
115,337

 
—

 
—

 
 
 
115,337

Municipal bonds
—

 
80,997

 
—

 
—

 
 
 
80,997

Other
—

 
22,132

 
—

 
—

 
 
 
22,132

Subtotal nuclear decommissioning trust
95,441

 
330,089

 
—

 
354,056

 
 
 
779,586

Total
$
109,962

 
$
373,811

 
$
11,076

 
$
318,953

 
 
 
$
813,802

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

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

 
(c)
 
$
(73,074
)

(a)
Primarily consists of long-dated electricity contracts.
(b)
Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets.
(c)
Represents counterparty netting, margin, and collateral. See Note 6.
(d)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(e)
Represents nuclear decommissioning trust net pending securities sales and purchases.
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments 
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at September 30, 2017 and December 31, 2016:
 
 
September 30, 2017
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
2,925

 
$
19,785

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$19.87 - $38.13
 
$
28.26

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
547

 
22,292

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.13 - $2.83
 
$
2.45

Total
$
3,472

 
$
42,077

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.


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

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
10,648

 
$
32,042

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

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
428

 
26,440

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

Total
$
11,076

 
$
58,482

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs 
The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
2017
 
2016
 
2017
 
2016
Net derivative balance at beginning of period
 
$
(36,245
)
 
$
(32,380
)
 
$
(47,406
)
 
$
(32,979
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 
 
 
Included in OCI
 
(4
)
 
(10
)
 
(10
)
 
94

Deferred as a regulatory asset or liability
 
(3,769
)
 
(13,499
)
 
(11,272
)
 
(21,103
)
Settlements
 
1,733

 
5,424

 
4,855

 
11,691

Transfers into Level 3 from Level 2
 
(5,952
)
 
1,343

 
(10,340
)
 
1,725

Transfers from Level 3 into Level 2
 
5,632

 
(420
)
 
25,568

 
1,030

Net derivative balance at end of period
 
$
(38,605
)
 
$
(39,542
)
 
$
(38,605
)
 
$
(39,542
)
 
 
 
 
 
 
 
 
 
Net unrealized gains included in earnings related to instruments still held at end of period
 
$
—

 
$
—

 
$
—

 
$
—



Nuclear Decommissioning Trusts (Tables)
Fair value of APS's nuclear decommissioning trust fund assets 
The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2017 and December 31, 2016 (dollars in thousands):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
September 30, 2017
 

 
 

 
 

Equity securities
$
401,913

 
$
232,727

 
$
—

Fixed income securities
435,689

 
12,272

 
(2,177
)
Net receivables (a)
4,378

 
—

 
—

Total
$
841,980

 
$
244,999

 
$
(2,177
)
(a)
Net receivables/payables relate to pending purchases and sales of securities.
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
December 31, 2016
 

 
 

 
 

Equity securities
$
353,261

 
$
188,091

 
$
—

Fixed income securities
425,530

 
9,820

 
(4,962
)
Net receivables (a)
795

 
—

 
—

Total
$
779,586

 
$
197,911

 
$
(4,962
)
(a)
Net receivables/payables relate to pending purchases and sales of securities.

Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds 
The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2017
 
2016
 
2017
 
2016
Realized gains
$
598

 
$
4,033

 
$
3,904

 
$
8,753

Realized losses
(1,022
)
 
(3,345
)
 
(4,634
)
 
(6,481
)
Proceeds from the sale of securities (a)
76,496

 
156,825

 
351,860

 
447,419

(a)
Proceeds are reinvested in the trust.
Fair value of fixed income securities, summarized by contractual maturities 
 
The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2017 is as follows (dollars in thousands):
 
Fair Value
Less than one year
$
22,498

1 year – 5 years
103,033

5 years – 10 years
117,044

Greater than 10 years
193,114

Total
$
435,689

Changes in Accumulated Other Comprehensive Loss (Tables)
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component 
The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2017
 
2016
 
2017
 
2016
Balance at beginning of period
$
(43,626
)
 
$
(43,719
)
 
$
(43,822
)
 
$
(44,748
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
9

  
(29
)
 
(754
)
 
(595
)
Amounts reclassified from accumulated other comprehensive loss (a)
710

 
798

 
2,480

 
2,564

Net current period OCI (loss)
719

 
769

  
1,726

 
1,969

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
—

 
—

 
(2,157
)
 
(1,585
)
Amounts reclassified from accumulated other comprehensive loss (b)
790

 
804

 
2,136

 
2,218

Net current period OCI (loss)
790

 
804

 
(21
)
 
633

Balance at end of period
$
(42,117
)
 
$
(42,146
)
 
$
(42,117
)
 
$
(42,146
)

(a)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 6.
(b)
These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component 
The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2017 and 2016 (dollars in thousands): 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2017
 
2016
 
2017
 
2016
Balance at beginning of period
$
(25,112
)
 
$
(25,928
)
 
$
(25,423
)
 
$
(27,097
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
9

  
(29
)
 
(754
)
 
(595
)
Amounts reclassified from accumulated other comprehensive loss (a)
710

 
798

 
2,480

 
2,564

Net current period OCI (loss)
719

 
769

 
1,726

 
1,969

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
—

 
—

 
(2,121
)
 
(1,521
)
Amounts reclassified from accumulated other comprehensive loss (b)
777

 
799

 
2,202

 
2,289

Net current period OCI (loss)
777

 
799

 
81

 
768

Balance at end of period
$
(23,616
)
 
$
(24,360
)
 
$
(23,616
)
 
$
(24,360
)
(a)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 6.
(b)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 4.
Asset Retirement Obligations (Tables)
Change in asset retirement obligations
The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2017 (dollars in thousands): 
Asset retirement obligations at January 1, 2017
$
624,475

Changes attributable to:
 

Accretion expense
24,170

Estimated cash flow revisions
22,211

Asset retirement obligations at September 30, 2017
$
670,856

Consolidated and Nature of Operations - Schedule of Reclassification of Prior Period Adjustments (Details) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Stock compensation
$ 16,553 
$ 27,588 
Change in other long-term liabilities
(25,180)
(52,427)
Short-term borrowing and payments — net
(68,800)
83,300 
Short-term borrowings under revolving credit facility
23,000 
34,000 
As previously reported
 
 
Stock compensation
 
0 
Change in other long-term liabilities
 
(24,839)
Short-term borrowing and payments — net
 
117,300 
Short-term borrowings under revolving credit facility
 
0 
Reclassifications to conform to current year presentation
 
 
Stock compensation
 
27,588 
Change in other long-term liabilities
 
(27,588)
Short-term borrowing and payments — net
 
(34,000)
Short-term borrowings under revolving credit facility
 
$ 34,000 
Consolidation and Nature of Operations (Details) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Cash paid during the period for:
 
 
Income taxes, net of refunds
$ 2,185 
$ 2,562 
Interest, net of amounts capitalized
147,149 
146,691 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 93,031 
$ 91,315 
Long-Term Debt and Liquidity Matters - Narrative (Details) (USD $)
9 Months Ended 0 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Sep. 30, 2017
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing July 2018
Jul. 31, 2017
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing July 2018
Sep. 30, 2017
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing May 2021
Sep. 30, 2017
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing in August 2017
Sep. 30, 2017
Pinnacle West
Letter of Credit
Revolving credit facility maturing May 2021
Sep. 30, 2017
Pinnacle West
Commercial paper
Revolving credit facility maturing May 2021
Sep. 30, 2017
APS
Dec. 31, 2016
APS
Sep. 30, 2017
APS
ACC
Sep. 30, 2017
APS
ACC
Minimum
Jun. 29, 2017
APS
Revolving Credit Facility
Revolving Credit Facility Maturing September 2020
Sep. 30, 2017
APS
Revolving Credit Facility
Revolving Credit Facilities Maturing in 2021 and 2022
Facility
Sep. 30, 2017
APS
Revolving Credit Facility
Revolving credit facility maturing May 2021
Sep. 30, 2017
APS
Revolving Credit Facility
Revolving credit facility maturing June 2022
Jun. 29, 2017
APS
Revolving Credit Facility
Revolving credit facility maturing June 2022
Sep. 30, 2017
APS
Letter of Credit
Revolving Credit Facilities Maturing in 2021 and 2022
Sep. 30, 2017
APS
Commercial paper
Sep. 30, 2017
APS
Commercial paper
Revolving Credit Facilities Maturing in 2021 and 2022
Mar. 21, 2017
Senior Notes
APS
Unsecured senior notes maturing November 2045
Sep. 11, 2017
Senior Notes
APS
Unsecured senior notes maturing September 2027
Jul. 31, 2017
LIBOR
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing July 2018
Long-Term Debt and Liquidity Matters
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current borrowing capacity on credit facility
 
 
 
 
$ 200,000,000 
 
 
 
 
 
 
 
$ 500,000,000 
$ 1,000,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
 
 
 
 
 
 
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)
 
 
 
125,000,000 
300,000,000 
75,000,000 
 
 
 
 
 
 
 
1,400,000,000 
700,000,000 
700,000,000 
 
 
 
 
 
 
 
Long-term line of credit
 
 
 
 
0 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
Commercial paper
 
 
 
 
 
 
 
36,600,000 
 
 
 
 
 
 
 
 
 
 
 
31,800,000 
 
 
 
Debt instrument, term
 
 
364 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, basis spread on variable rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.80% 
Shot-term debt
131,400,000 
177,200,000 
63,000,000 
 
 
 
 
 
31,800,000 
135,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250,000,000 
300,000,000 
 
Debt instrument, stated interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.35% 
2.95% 
 
Number of line of credit facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
Maximum commercial paper support available under credit facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000,000 
 
 
 
 
Debt Provisions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Required common equity ratio ordered by ACC (as a percent) (at least)
 
 
 
 
 
 
 
 
 
 
 
40.00% 
 
 
 
 
 
 
 
 
 
 
 
Total shareholder equity
5,142,068,000 
4,803,622,000 
 
 
 
 
 
 
5,237,812,000 
4,905,680,000 
5,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Total capitalization
 
 
 
 
 
 
 
 
 
 
10,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
 
 
 
 
 
$ 4,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
$ 4,698,048 
$ 4,146,785 
Fair Value
5,063,258 
4,425,789 
Pinnacle West
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
125,000 
125,000 
Fair Value
125,000 
125,000 
Arizona Public Service Company
 
 
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
4,573,048 
4,021,785 
Fair Value
$ 4,938,258 
$ 4,300,789 
Regulatory Matters - Retail Rate Case Filing (Details) (Retail Rate Case Filing with Arizona Corporation Commission, ACC, APS, USD $)
In Millions, unless otherwise specified
0 Months Ended
Mar. 27, 2017
Jun. 1, 2016
Dec. 31, 2015
Jun. 1, 2011
Retail Rate Case Filing with Arizona Corporation Commission |
ACC |
APS
 
 
 
 
Public Utilities, General Disclosures [Line Items]
 
 
 
 
Net retail rate increase
 
$ 165.9 
 
$ 95.5 
Adjustor account balance transferred into base rates, amount
 
 
$ 267.6 
 
Approximate percentage of increase in average customer bill
3.28% 
5.74% 
 
 
Approximate percentage of increase in average residential customer bill
4.54% 
7.96% 
 
 
Regulatory Matters - Settlement Agreement, Cost Recovery Mechanism and Net Metering (Details) (USD $)
9 Months Ended 1 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 1 Months Ended 0 Months Ended 2 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 0 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
APS
Sep. 30, 2016
APS
Dec. 31, 2014
RES 2014
APS
Alternative to AZ Sun Program, Phase 1
MW
Dec. 31, 2014
RES 2014
APS
Alternative to AZ Sun Program Phase 2
storage_system
penetration_feeder
MW
Jan. 13, 2017
Lost Fixed Cost Recovery Mechanisms
APS
Jan. 15, 2016
Lost Fixed Cost Recovery Mechanisms
APS
Sep. 30, 2017
Lost Fixed Cost Recovery Mechanisms
APS
Mar. 27, 2017
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Mar. 26, 2017
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Jun. 1, 2016
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Jan. 1, 2016
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Jan. 6, 2012
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Jun. 1, 2011
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Sep. 30, 2017
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Mar. 27, 2017
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
AZ Sun Program Phase 2
Sep. 30, 2017
ACC
RES
APS
Jan. 12, 2016
ACC
RES 2016
APS
Jul. 1, 2016
ACC
RES 2017
APS
Sep. 30, 2017
ACC
RES 2018
APS
Sep. 30, 2016
ACC
Modernization and Expansion of the Renewal Energy Standard
APS
Aug. 5, 2016
ACC
DSMAC 2015
APS
Apr. 1, 2016
ACC
DSMAC 2015
APS
Nov. 25, 2015
ACC
DSMAC 2015
APS
Mar. 20, 2015
ACC
DSMAC 2015
APS
project
Jun. 1, 2015
ACC
DSMC 2016
APS
Nov. 4, 2014
ACC
Electric energy efficiency standard
APS
Apr. 30, 2014
ACC
Electric energy efficiency standard
APS
workshop
Aug. 19, 2017
ACC
Power Supply Adjustor (PSA)
APS
Feb. 1, 2017
ACC
Power Supply Adjustor (PSA)
APS
Sep. 30, 2017
ACC
Power Supply Adjustor (PSA)
APS
Sep. 30, 2016
ACC
Power Supply Adjustor (PSA)
APS
Dec. 20, 2016
ACC
Net Metering
APS
Dec. 5, 2016
ACC
Residential Demand Response, Energy Storage and Load Management Program
APS
Jan. 27, 2017
ACC
Demand Side Management Adjustor Charge 2017
APS
Jun. 1, 2016
ACC
Demand Side Management Adjustor Charge 2017
APS
Sep. 1, 2017
ACC
Demand Side Management Adjustor Charge 2018
APS
Jun. 1, 2017
United States Federal Energy Regulatory Commission
Open Access Transmission Tariff
APS
Jun. 1, 2016
United States Federal Energy Regulatory Commission
Open Access Transmission Tariff
APS
Feb. 1, 2016
Cost Recovery Mechanisms
ACC
Power Supply Adjustor (PSA)
APS
Settlement Agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net retail base rate, increase
 
 
 
 
 
 
 
 
 
$ 94,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-fuel and non-depreciation base rate, increase
 
 
 
 
 
 
 
 
 
87,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel-related base rate decrease
 
 
 
 
 
 
 
 
 
53,600,000 
 
 
 
153,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Base rate increase, changes in depreciation schedules
 
 
 
 
 
 
 
 
 
61,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in average customer bill
 
 
 
 
 
 
 
 
 
3.28% 
 
5.74% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in average residential customer bill
 
 
 
 
 
 
 
 
 
4.54% 
 
7.96% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorized return on common equity (as a percent)
 
 
 
 
 
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of debt in capital structure
 
 
 
 
 
 
 
 
 
44.20% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of common equity in capital structure
 
 
 
 
 
 
 
 
 
55.80% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public utilities, minimum annual renewable energy standard and tariff
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public utilities, maximum annual renewable energy standard and tariff
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter, environmental surcharge cap rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
0.00050 
0.00016 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate matter, resource comparison proxy for exported energy (in dollars per kWh)
 
 
 
 
 
 
 
 
 
0.129 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net retail rate increase
 
 
 
 
 
 
 
 
 
 
 
165,900,000 
 
 
95,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approximate percentage of increase in average retail customer bill
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.60% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net change in base rates
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-fuel base rate increase
 
 
 
 
 
 
 
 
 
 
 
 
 
116,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current base fuel rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
0.03757 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approved base fuel rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
0.03207 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates
 
 
 
 
 
 
 
 
 
 
 
 
 
36,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plan term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Request to build additional utility scale solar, capacity (in MW)
 
 
 
 
8 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of energy storage systems
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Solar storage system, capacity (in MW)
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of high solar penetration feeders
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of approved budget
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
148,000,000 
150,000,000 
 
 
 
68,900,000 
68,900,000 
 
68,900,000 
 
 
 
 
 
 
 
 
66,600,000 
 
 
 
 
 
Amount of proposed budget
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
90,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
62,600,000 
52,600,000 
 
 
 
Proposed renewal energy standard, percent of retail sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current renewal energy standard, percent of retail sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of resource savings projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional budget approved
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,000,000 
 
 
 
 
 
 
 
 
 
 
 
4,000,000 
 
 
 
 
 
 
Number of workshops
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
Number of days to convene a workshop
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
120 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,465,000 
(9,688,000)
 
 
 
 
 
 
 
 
Deferred fuel and purchased power costs — current period
43,348,000 
46,185,000 
43,348,000 
46,185,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
43,348,000 
46,185,000 
 
 
 
 
 
 
 
 
Amounts refunded/(charged) to customers
18,153,000 
(28,366,000)
18,153,000 
(28,366,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18,153,000 
(28,365,000)
 
 
 
 
 
 
 
 
Ending balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
73,966,000 
8,132,000 
 
 
 
 
 
 
 
 
PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.000555 
(0.001348)
 
 
 
 
 
 
 
 
 
 
PSA rate for prior year (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001678 
Forward component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.000876 
(0.001027)
 
 
 
 
 
 
 
 
 
 
Historical component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.000321)
(0.000321)
 
 
 
 
 
 
 
 
 
 
Increase in annual wholesale transmission rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
35,100,000 
24,900,000 
 
Fixed costs recoverable per residential power lost (in dollars per kWh)
 
 
 
 
 
 
 
 
0.031 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed costs recoverable per non-residential power lost (in dollars per kWh)
 
 
 
 
 
 
 
 
0.023 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of retail revenues
 
 
 
 
 
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of adjustment representing prorated sales losses approval
 
 
 
 
 
 
63,700,000 
46,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in amount of adjustment representing prorated sales losses
 
 
 
 
 
 
17,300,000 
7,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual revenue requirement impact to trigger pass-through rate adjustment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of service, resource comparison proxy method, maximum annual percentage decrease
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.00% 
 
 
 
 
 
 
 
Cost of service for interconnected DG system customers, grandfathered period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20 years 
 
 
 
 
 
 
 
Cost of service for new customers, guaranteed export price period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10 years 
 
 
 
 
 
 
 
First-year export energy price (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.129 
 
 
 
 
 
 
 
Reduced system benefits charge, amount
 
 
 
 
 
 
 
 
 
 
 
 
$ 14,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Matters - Four Corners and Cholla (Details) (APS, USD $)
In Millions, unless otherwise specified
0 Months Ended 9 Months Ended 3 Months Ended
Dec. 23, 2014
SCE
Four Corners Units 4 and 5
Dec. 30, 2013
SCE
Four Corners Units 4 and 5
Dec. 30, 2013
SCE
Four Corners Units 4 and 5
Sep. 30, 2017
Four Corners cost deferral
SCE
Four Corners Units 4 and 5
Sep. 30, 2017
Retired power plant costs
Sep. 30, 2017
Navajo Plant
Sep. 30, 2016
Four Corners
SCE
Dec. 31, 2015
Four Corners
SCE
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
Ownership interest acquired
 
 
48.00% 
 
 
 
 
 
Settlement agreement, ACC approved rate adjustment, annualized customer impact
$ 57.1 
 
 
 
 
 
 
 
Regulatory assets, non-current
 
 
 
58 
 
 
 
12 
Regulatory noncurrent asset amortization period
 
 
 
10 years 
 
 
 
 
Net receipt due to negotiation of alternate arrangement
 
40 
 
 
 
 
 
 
Regulatory asset, write off amount
 
 
 
 
 
 
12 
 
Net book value
 
 
 
 
$ 109 
$ 102 
 
 
Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Detail of regulatory assets
 
 
Regulatory assets, current
$ 258,317 
$ 106,875 
Regulatory assets, non-current
1,381,179 
1,313,428 
Pension
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
686,511 
711,059 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
28,647 
9,913 
Regulatory assets, non-current
194,639 
117,591 
Income taxes — allowance for funds used during construction (AFUDC) equity
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,202 
6,305 
Regulatory assets, non-current
170,622 
152,118 
Deferred fuel and purchased power — mark-to-market (Note 6)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
45,463 
0 
Regulatory assets, non-current
33,115 
42,963 
Deferred fuel and purchased power (b) (d)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
73,966 
12,465 
Regulatory assets, non-current
0 
0 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,077 
6,689 
Regulatory assets, non-current
50,324 
56,894 
Income taxes — investment tax credit basis adjustment
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,120 
2,120 
Regulatory assets, non-current
53,225 
54,356 
Lost fixed cost recovery (b)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
67,500 
61,307 
Regulatory assets, non-current
0 
0 
Palo Verde VIEs (Note 5)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
19,240 
18,775 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
37,265 
35,595 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,569 
0 
Regulatory assets, non-current
77,408 
73,200 
Loss on reacquired debt
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,637 
1,637 
Regulatory assets, non-current
15,715 
16,942 
Tax expense of Medicare subsidy
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,503 
1,513 
Regulatory assets, non-current
9,074 
10,589 
Demand side management (c)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
3,744 
Regulatory assets, non-current
0 
0 
AG-1 deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,654 
0 
Regulatory assets, non-current
9,136 
5,868 
Mead-Phoenix transmission line CIAC
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
332 
332 
Regulatory assets, non-current
10,459 
10,708 
Transmission cost adjustor (b)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
4,345 
0 
Regulatory assets, non-current
0 
1,588 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,068 
418 
Regulatory assets, non-current
14,446 
5,182 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,234 
432 
Regulatory assets, non-current
$ 0 
$ 0 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 120,671 
$ 99,899 
Regulatory liabilities, non-current
891,715 
948,916 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
313,189 
279,976 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
37,756 
29,899 
Regulatory liabilities, non-current
184,512 
223,145 
Other postretirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
32,725 
32,662 
Regulatory liabilities, non-current
99,626 
123,913 
Income taxes — deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
4,315 
4,368 
Regulatory liabilities, non-current
106,557 
108,827 
Income taxes — change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,565 
1,771 
Regulatory liabilities, non-current
67,136 
70,898 
Spent nuclear fuel
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
6,562 
0 
Regulatory liabilities, non-current
64,504 
71,726 
Renewable energy standard (c)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
17,915 
26,809 
Regulatory liabilities, non-current
0 
0 
Demand side management (c)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
12,175 
0 
Regulatory liabilities, non-current
4,921 
20,472 
Sundance maintenance
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
16,494 
15,287 
Deferred gains on utility property
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
4,525 
2,063 
Regulatory liabilities, non-current
11,875 
8,895 
Four Corners coal reclamation
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
1,857 
0 
Regulatory liabilities, non-current
19,494 
18,248 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
276 
2,327 
Regulatory liabilities, non-current
$ 3,407 
$ 7,529 
Retirement Plans and Other Postretirement Benefits - Narrative (Details) (USD $)
9 Months Ended
Sep. 30, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
Amount of other postretirement benefit trust assets for union employee medical costs
$ 145,000,000 
Pension Benefits
 
Contributions
 
Voluntary employer contributions to pension plan
100,000,000 
Minimum employer contributions for the next three years
0 
Maximum employer contributions for the next two years (up to)
300,000,000 
Other Benefits
 
Contributions
 
Estimated future employer contributions in next three years
$ 1,000,000 
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Pension Benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
$ 13,715 
$ 13,448 
$ 41,144 
$ 40,344 
Interest cost on benefit obligation
32,439 
32,912 
97,316 
98,735 
Expected return on plan assets
(43,568)
(43,477)
(130,703)
(130,429)
Amortization of:
 
 
 
 
Prior service cost (credit)
20 
132 
61 
395 
Net actuarial loss
11,975 
10,179 
35,924 
30,538 
Net periodic benefit cost
14,581 
13,194 
43,742 
39,583 
Portion of cost charged to expense
7,231 
6,476 
21,692 
19,427 
Other Benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
4,280 
3,748 
12,839 
11,245 
Interest cost on benefit obligation
7,490 
7,430 
22,470 
22,291 
Expected return on plan assets
(13,350)
(9,123)
(40,051)
(27,371)
Amortization of:
 
 
 
 
Prior service cost (credit)
(9,461)
(9,471)
(28,382)
(28,413)
Net actuarial loss
1,279 
1,147 
3,838 
3,442 
Net periodic benefit cost
(9,762)
(6,269)
(29,286)
(18,806)
Portion of cost charged to expense
$ (4,841)
$ (3,077)
$ (14,523)
$ (9,230)
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2017
power_plant
Sep. 30, 2016
Sep. 30, 2017
power_plant
Sep. 30, 2016
Dec. 31, 1986
Trust
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts
$ 4,873,000 
$ 4,873,000 
$ 14,620,000 
$ 14,620,000 
 
Arizona Public Service Company
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Number of VIE lessor trusts
3 
 
3 
 
3 
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts
4,873,000 
4,873,000 
14,620,000 
14,620,000 
 
Arizona Public Service Company |
Consolidation of VIEs
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts
5,000,000 
5,000,000 
15,000,000 
15,000,000 
 
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period
 
 
291,000,000 
 
 
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period
 
 
456,000,000 
 
 
Arizona Public Service Company |
Consolidation of VIEs |
Through 2023
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Number of leases under which assets are retained
 
 
1 
 
 
Arizona Public Service Company |
Consolidation of VIEs |
Through 2033
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Number of leases under which assets are retained
 
 
2 
 
 
Arizona Public Service Company |
Consolidation of VIEs |
Period 2017 through 2023
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Annual lease payments
 
 
23,000,000 
 
 
Arizona Public Service Company |
Consolidation of VIEs |
Period 2024 through 2033
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Annual lease payments
 
 
$ 16,000,000 
 
 
Arizona Public Service Company |
Consolidation of VIEs |
Period 2024 through 2033 |
Maximum
 
 
 
 
 
Palo Verde Sale Leaseback Variable Interest Entities
 
 
 
 
 
Lease period (up to)
 
 
2 years 
 
 
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$ 110,613 
$ 113,515 
Equity — Noncontrolling interests
135,539 
132,290 
Arizona Public Service Company
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
110,613 
113,515 
Equity — Noncontrolling interests
135,539 
132,290 
Arizona Public Service Company |
Consolidation of VIEs
 
 
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
110,613 
113,515 
Equity — Noncontrolling interests
$ 135,539 
$ 132,290 
Derivative Accounting - Narrative (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2017
Designated as Hedging Instruments
Dec. 31, 2016
Designated as Hedging Instruments
Sep. 30, 2017
Commodity Contracts
Dec. 31, 2016
Commodity Contracts
Sep. 30, 2017
Commodity Contracts
Designated as Hedging Instruments
Sep. 30, 2016
Commodity Contracts
Designated as Hedging Instruments
Sep. 30, 2017
Commodity Contracts
Designated as Hedging Instruments
Sep. 30, 2016
Commodity Contracts
Designated as Hedging Instruments
Sep. 30, 2017
Arizona Public Service Company
Derivative Accounting
 
 
 
 
 
 
 
 
 
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges
 
 
 
 
$ 0 
$ 0 
$ 0 
$ 0 
 
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment
 
 
 
 
 
 
 
 
100.00% 
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income
 
 
 
 
 
 
(2,000,000)
 
 
Gross recognized derivatives
400,000 
2,000,000 
95,491,000 
104,123,000 
 
 
 
 
 
Additional collateral to counterparties for energy related non-derivative instrument contracts
 
 
$ 118,000,000 
 
 
 
 
 
 
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) (Commodity Contracts)
9 Months Ended 12 Months Ended
Sep. 30, 2017
MMcf
MWh
Dec. 31, 2016
MWh
MMcf
Commodity Contracts
 
 
Outstanding gross notional amount of derivatives
 
 
Power
736,000 
1,314,000 
Gas
205,000 
194,000 
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges
$ 0 
$ 0 
$ 0 
$ 0 
Designated as Hedging Instruments |
Fuel and purchased power
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)
(1,148,000)
(1,298,000)
(2,910,000)
(3,255,000)
Not Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net loss recognized in income
(6,228,000)
(35,062,000)
(64,617,000)
(4,621,000)
Not Designated as Hedging Instruments |
Operating revenues
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net loss recognized in income
(128,000)
41,000 
(474,000)
524,000 
Not Designated as Hedging Instruments |
Fuel and purchased power
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net loss recognized in income
(6,100,000)
(35,103,000)
(64,143,000)
(5,145,000)
Other comprehensive income |
Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
$ 14,000 
$ (47,000)
$ (70,000)
$ 13,000 
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) (Commodity Contracts, USD $)
Sep. 30, 2017
Dec. 31, 2016
Assets
 
 
Gross Recognized Derivatives
$ 11,901,000 
$ 54,798,000 
Amounts Offset
(11,676,000)
(35,103,000)
Net Recognized Derivatives
225,000 
19,695,000 
Other
1,825,000 
0 
Derivative assets
2,050,000 
19,695,000 
Liabilities
 
 
Gross Recognized Derivatives
(95,491,000)
(104,123,000)
Amounts Offset
11,676,000 
35,103,000 
Net Recognized Derivatives
(83,815,000)
(69,020,000)
Other
(2,429,000)
(4,054,000)
Amount Reported on Balance Sheet
(86,244,000)
(73,074,000)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(83,590,000)
(49,325,000)
Amounts Offset
0 
0 
Net Recognized Derivatives
(83,590,000)
(49,325,000)
Other
(604,000)
(4,054,000)
Amount Reported on Balance Sheet
(84,194,000)
(53,379,000)
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
9,764,000 
48,094,000 
Amounts Offset
(9,623,000)
(28,400,000)
Net Recognized Derivatives
141,000 
19,694,000 
Other
217,000 
0 
Derivative assets
358,000 
19,694,000 
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
2,137,000 
6,704,000 
Amounts Offset
(2,053,000)
(6,703,000)
Net Recognized Derivatives
84,000 
1,000 
Other
1,608,000 
0 
Derivative assets
1,692,000 
1,000 
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(57,663,000)
(50,182,000)
Amounts Offset
9,623,000 
28,400,000 
Net Recognized Derivatives
(48,040,000)
(21,782,000)
Other
(2,429,000)
(4,054,000)
Amount Reported on Balance Sheet
(50,469,000)
(25,836,000)
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(37,828,000)
(53,941,000)
Amounts Offset
2,053,000 
6,703,000 
Net Recognized Derivatives
(35,775,000)
(47,238,000)
Other
0 
0 
Amount Reported on Balance Sheet
$ (35,775,000)
$ (47,238,000)
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Commodity Contracts
 
Credit Risk and Credit-Related Contingent Features
 
Aggregate fair value of derivative instruments in a net liability position
$ 95,491 
Cash collateral posted
0 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered
$ 81,866 
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)
0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended
Sep. 30, 2017
Aug. 18, 2014
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Sep. 30, 2017
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Sep. 30, 2017
Arizona Public Service Company
power_plant
Dec. 31, 1986
Arizona Public Service Company
Trust
Aug. 18, 2014
Arizona Public Service Company
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Sep. 30, 2017
Arizona Public Service Company
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
time_period
claim
Commitments and Contingencies
 
 
 
 
 
 
 
Litigation settlement amount
 
$ 57,400,000 
 
 
 
$ 16,700,000 
 
Number of claims submitted
 
 
 
 
 
 
3 
Number of settlement agreement time periods
 
 
 
 
 
 
3 
Proceeds from legal settlements
 
 
65,200,000 
 
 
 
19,000,000 
Maximum insurance against public liability per occurrence for a nuclear incident (up to)
 
 
 
13,400,000,000 
 
 
 
Maximum available nuclear liability insurance (up to)
 
 
 
450,000,000 
 
 
 
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program
 
 
 
13,000,000,000 
 
 
 
Maximum retrospective premium assessment per reactor for each nuclear liability incident
 
 
 
127,300,000 
 
 
 
Annual limit per incident with respect to maximum retrospective premium assessment
 
 
 
19,000,000 
 
 
 
Number of VIE lessor trusts
 
 
 
3 
3 
 
 
Maximum potential retrospective assessment per incident of APS
 
 
 
111,100,000 
 
 
 
Annual payment limitation with respect to maximum potential retrospective premium assessment
 
 
 
16,600,000 
 
 
 
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde
 
 
 
2,800,000,000 
 
 
 
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment
 
 
 
24,000,000 
 
 
 
Collateral assurance provided based on rating triggers
 
 
 
64,800,000 
 
 
 
Period to provide collateral assurance based on rating triggers
 
 
 
20 days 
 
 
 
Purchase obligation, increase (decrease) as a result of variable components
$ 1,000,000,000 
 
 
 
 
 
 
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) (Arizona Public Service Company, Contaminated groundwater wells, USD $)
In Millions, unless otherwise specified
0 Months Ended 9 Months Ended
Dec. 16, 2016
plaintiff
Aug. 6, 2013
Defendant
Sep. 30, 2017
Arizona Public Service Company |
Contaminated groundwater wells
 
 
 
Loss Contingencies [Line Items]
 
 
 
Costs related to investigation and study under Superfund site
 
 
$ 2 
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit
 
24 
 
Number of plaintiffs
2 
 
 
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)
0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended
Aug. 8, 2017
Clean Power Plan
Apr. 28, 2017
Clean Power Plan
Sep. 30, 2017
Clean Power Plan
Jun. 13, 2017
Coal Supply Agreement Arbitration
Four Corners
Jun. 13, 2017
Arizona Public Service Company
Coal Supply Agreement Arbitration
Four Corners
Sep. 30, 2017
Arizona Public Service Company
Letter of Credit Expiring in 2016 and 2017
Sep. 30, 2017
Arizona Public Service Company
Letters of Credit Expiring in 2017
Sep. 30, 2017
4C Acquisition, LLC
Four Corners Units 4 and 5
Jul. 6, 2016
4C Acquisition, LLC
Four Corners
Sep. 30, 2017
4C Acquisition, LLC
Coal Supply Agreement Arbitration
Four Corners
Jul. 6, 2016
NTEC
Four Corners
Jul. 6, 2016
NTEC
Coal Supply Agreement Arbitration
Four Corners
Sep. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Four Corners Units 4 and 5
Sep. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Natural gas tolling contract obligations
Four Corners Units 4 and 5
Sep. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Four Corners
Four Corners Units 4 and 5
Sep. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Navajo Plant
Sep. 30, 2017
Coal combustion waste
Arizona Public Service Company
Four Corners
Sep. 30, 2017
Coal combustion waste
Arizona Public Service Company
Navajo Plant
Jun. 24, 2016
Coal combustion waste
Arizona Public Service Company
Navajo Plant
Boron Inclusion on List of Groundwater Constituents
Sep. 30, 2017
Minimum
Coal combustion waste
Arizona Public Service Company
Cholla
Jul. 6, 2016
Payment Guarantee
guarantee
Environmental Matters
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of share of cost of control
 
 
 
 
 
 
 
7.00% 
7.00% 
 
 
 
63.00% 
 
 
 
 
 
 
 
 
Expected environmental cost
 
 
 
 
 
 
 
 
 
 
 
 
$ 400,000,000 
 
 
$ 200,000,000 
 
 
 
 
 
Additional percentage share of cost of control
 
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
 
 
 
 
 
 
 
Site contingency increase in loss exposure not accrued, best estimate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
45,000,000 
 
22,000,000 
1,000,000 
 
20,000,000 
 
Industry litigation, period to complete rulemaking proceeding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 years 
 
 
Litigation abeyance period
60 days 
60 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Periodic update period
 
 
30 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Four Corners Coal Supply Agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Damages sought
 
 
 
30,000,000 
17,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Option to purchase ownership interest (as a percent)
 
 
 
 
 
 
 
 
 
 
7.00% 
7.00% 
 
 
 
 
 
 
 
 
 
Reimbursement payments due to 4CA
 
 
 
 
 
 
 
 
 
26,000,000 
 
 
 
 
 
 
 
 
 
 
 
Reimbursement payments due to 4CA at end of current fiscal year
 
 
 
 
 
 
 
 
 
10,000,000 
 
 
 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds expiring, amount
 
 
 
 
 
 
$ 62,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of parental guarantees
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4 
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Other income:
 
 
 
 
Interest income
$ 917 
$ 65 
$ 1,782 
$ 370 
Investment gains — net
119 
0 
119 
13 
Miscellaneous
55 
6 
154 
2 
Total other income
1,091 
71 
2,055 
385 
Other expense:
 
 
 
 
Non-operating costs
(1,978)
(2,502)
(7,338)
(6,636)
Investment losses — net
(231)
(450)
(759)
(1,508)
Miscellaneous
(2,784)
(2,253)
(4,398)
(3,941)
Total other expense
(4,993)
(5,205)
(12,495)
(12,085)
Arizona Public Service Company
 
 
 
 
Other income:
 
 
 
 
Interest income
683 
0 
1,278 
181 
Gain on disposition of property
441 
183 
1,009 
5,504 
Miscellaneous
354 
384 
1,395 
1,239 
Total other income
1,478 
567 
3,682 
6,924 
Other expense:
 
 
 
 
Non-operating costs
(1,970)
(2,714)
(7,889)
(7,398)
Loss on disposition of property
(3,214)
36 
(4,471)
(1,048)
Miscellaneous
(1,078)
(1,098)
(3,930)
(4,510)
Total other expense
$ (6,262)
$ (3,776)
$ (16,290)
$ (12,956)
Earnings Per Share (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Earnings Per Share [Abstract]
 
 
 
 
Net income attributable to common shareholders
$ 276,072 
$ 263,027 
$ 466,827 
$ 388,788 
Weighted average common shares outstanding - basic (in shares)
111,835 
111,416 
111,787 
111,363 
Net effect of dilutive securities:
 
 
 
 
Contingently issuable performance shares and restricted stock units (in shares)
566 
684 
527 
624 
Weighted average common shares outstanding — diluted (in shares)
112,401 
112,100 
112,314 
111,987 
Earnings per weighted-average common share outstanding
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 2.47 
$ 2.36 
$ 4.18 
$ 3.49 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 2.46 
$ 2.35 
$ 4.16 
$ 3.47 
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Assets
 
 
Total
$ 841,980 
$ 779,586 
Total assets
3,472 
11,076 
Municipal bonds
 
 
Assets
 
 
Coal reclamation escrow amount
24,973 
 
Recurring
 
 
Assets
 
 
Coal reclamation escrow amount
 
14,521 
Derivative instruments, other
(9,851)
(35,103)
Derivative assets
2,050 
19,695 
Nuclear decommissioning trust, other
406,291 
354,056 
Total
841,980 
779,586 
Total, other
396,950 
318,953 
Total assets
876,688 
813,802 
Liabilities
 
 
Total, other
9,247 
31,049 
Amount Reported on Balance Sheet
(86,244)
(73,074)
Recurring |
US commingled equity funds
 
 
Assets
 
 
Nuclear decommissioning trust, other
401,913 
353,261 
Total
401,913 
353,261 
Recurring |
Cash and cash equivalent funds
 
 
Assets
 
 
Nuclear decommissioning trust, other
4,378 
795 
Total
14,976 
795 
Recurring |
U.S. Treasury
 
 
Assets
 
 
Total
90,776 
95,441 
Recurring |
Corporate debt
 
 
Assets
 
 
Total
124,369 
111,623 
Recurring |
Mortgage-backed securities
 
 
Assets
 
 
Total
116,237 
115,337 
Recurring |
Municipal bonds
 
 
Assets
 
 
Total
76,412 
80,997 
Recurring |
Other
 
 
Assets
 
 
Total
17,297 
22,132 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Coal reclamation escrow amount
 
14,521 
Decommissioning fund investments, gross fair value
101,374 
95,441 
Gross assets, fair value disclosure
108,549 
109,962 
Liabilities
 
 
Gross derivative liability
0 
0 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Cash and cash equivalent funds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
10,598 
0 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
U.S. Treasury
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
90,776 
95,441 
Recurring |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Gross derivative assets
8,429 
43,722 
Decommissioning fund investments, gross fair value
334,315 
330,089 
Gross assets, fair value disclosure
367,717 
373,811 
Liabilities
 
 
Gross derivative liability
(53,414)
(45,641)
Recurring |
Significant Other Observable Inputs (Level 2) |
Corporate debt
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
124,369 
111,623 
Recurring |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
116,237 
115,337 
Recurring |
Significant Other Observable Inputs (Level 2) |
Municipal bonds
 
 
Assets
 
 
Coal reclamation escrow amount
24,973 
 
Decommissioning fund investments, gross fair value
76,412 
80,997 
Recurring |
Significant Other Observable Inputs (Level 2) |
Other
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
17,297 
22,132 
Recurring |
Significant Unobservable Inputs (Level 3)
 
 
Assets
 
 
Gross derivative assets
3,472 
11,076 
Gross assets, fair value disclosure
3,472 
11,076 
Liabilities
 
 
Gross derivative liability
(42,077)
(58,482)
Cash equivalents |
Recurring
 
 
Assets
 
 
Coal reclamation escrow amount
7,685 
 
Coal reclamation escrow amount, other
510 
 
Cash equivalents |
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Coal reclamation escrow amount
$ 7,175 
 
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) (USD $)
In Thousands, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
$ 3,472 
$ 11,076 
Liabilities
42,077 
58,482 
Electricity forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
2,925 
10,648 
Liabilities
19,785 
32,042 
Electricity forward contracts |
Minimum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
19.87 
16.43 
Electricity forward contracts |
Maximum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
38.13 
41.07 
Electricity forward contracts |
Weighted Average |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
28.26 
29.86 
Natural gas forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
547 
428 
Liabilities
$ 22,292 
$ 26,440 
Natural gas forward contracts |
Minimum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Natural gas forward price (per MMbtu)
2.13 
2.32 
Natural gas forward contracts |
Maximum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Natural gas forward price (per MMbtu)
2.83 
3.60 
Natural gas forward contracts |
Weighted Average |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Natural gas forward price (per MMbtu)
2.45 
2.81 
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
 
 
 
 
Net derivative balance at beginning of period
$ (36,245)
$ (32,380)
$ (47,406)
$ (32,979)
Included in OCI
(4)
(10)
(10)
94 
Deferred as a regulatory asset or liability
(3,769)
(13,499)
(11,272)
(21,103)
Settlements
1,733 
5,424 
4,855 
11,691 
Transfers into Level 3 from Level 2
(5,952)
1,343 
(10,340)
1,725 
Transfers from Level 3 into Level 2
5,632 
(420)
25,568 
1,030 
Net derivative balance at end of period
(38,605)
(39,542)
(38,605)
(39,542)
Net unrealized gains included in earnings related to instruments still held at end of period
$ 0 
$ 0 
$ 0 
$ 0 
Nuclear Decommissioning Trusts (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Dec. 31, 2016
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
$ 841,980 
 
$ 841,980 
 
$ 779,586 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
 
 
Proceeds from the sale of securities
 
 
351,860 
447,419 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
841,980 
 
841,980 
 
779,586 
Arizona Public Service Company
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
841,980 
 
841,980 
 
779,586 
Unrealized Gains
244,999 
 
244,999 
 
197,911 
Unrealized Losses
(2,177)
 
(2,177)
 
(4,962)
Net receivables for securities purchases
4,378 
 
4,378 
 
795 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
 
 
Realized gains
598 
4,033 
3,904 
8,753 
 
Realized losses
(1,022)
(3,345)
(4,634)
(6,481)
 
Proceeds from the sale of securities
76,496 
156,825 
351,860 
447,419 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
841,980 
 
841,980 
 
779,586 
Arizona Public Service Company |
Equity Securities
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
401,913 
 
401,913 
 
353,261 
Unrealized Gains
232,727 
 
232,727 
 
188,091 
Unrealized Losses
0 
 
0 
 
0 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
401,913 
 
401,913 
 
353,261 
Arizona Public Service Company |
Fixed income securities.
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
435,689 
 
435,689 
 
425,530 
Unrealized Gains
12,272 
 
12,272 
 
9,820 
Unrealized Losses
(2,177)
 
(2,177)
 
(4,962)
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Less than one year
22,498 
 
22,498 
 
 
1 year – 5 years
103,033 
 
103,033 
 
 
5 years – 10 years
117,044 
 
117,044 
 
 
Greater than 10 years
193,114 
 
193,114 
 
 
Total
$ 435,689 
 
$ 435,689 
 
$ 425,530 
Changes in Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2016
AOCI Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2015
AOCI Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Arizona Public Service Company
Sep. 30, 2016
Arizona Public Service Company
Sep. 30, 2017
Arizona Public Service Company
Sep. 30, 2016
Arizona Public Service Company
Sep. 30, 2017
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2016
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2015
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Arizona Public Service Company
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Arizona Public Service Company
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2017
Arizona Public Service Company
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Sep. 30, 2016
Arizona Public Service Company
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of period
 
 
$ 4,935,912 
$ 4,719,457 
$ (42,117)
$ (43,626)
$ (43,822)
$ (42,146)
$ (43,719)
$ (44,748)
 
 
 
 
 
 
 
 
 
 
$ 5,037,970 
$ 4,814,794 
$ (23,616)
$ (25,112)
$ (25,423)
$ (24,360)
$ (25,928)
$ (27,097)
 
 
 
 
 
 
 
 
OCI (loss) before reclassifications
 
 
 
 
 
 
 
 
 
 
9 
(29)
(754)
(595)
0 
0 
(2,157)
(1,585)
 
 
 
 
 
 
 
 
 
 
9 
(29)
(754)
(595)
0 
0 
(2,121)
(1,521)
Amounts reclassified from accumulated other comprehensive loss
 
 
 
 
 
 
 
 
 
 
710 
798 
2,480 
2,564 
790 
804 
2,136 
2,218 
 
 
 
 
 
 
 
 
 
 
710 
798 
2,480 
2,564 
777 
799 
2,202 
2,289 
Total other comprehensive income
1,509 
1,573 
1,705 
2,602 
 
 
 
 
 
 
719 
769 
1,726 
1,969 
790 
804 
(21)
633 
1,496 
1,568 
1,807 
2,737 
 
 
 
 
 
 
719 
769 
1,726 
1,969 
777 
799 
81 
768 
Balance at end of period
$ 5,277,607 
$ 4,992,135 
$ 5,277,607 
$ 4,992,135 
$ (42,117)
$ (43,626)
$ (43,822)
$ (42,146)
$ (43,719)
$ (44,748)
 
 
 
 
 
 
 
 
$ 5,373,351 
$ 5,085,440 
$ 5,373,351 
$ 5,085,440 
$ (23,616)
$ (25,112)
$ (25,423)
$ (24,360)
$ (25,928)
$ (27,097)
 
 
 
 
 
 
 
 
Asset Retirement Obligations - Roll-Forward (Details) (Arizona Public Service Company, USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Arizona Public Service Company
 
Change in asset retirement obligations
 
Asset retirement obligations at the beginning of year
$ 624,475 
Changes attributable to:
 
Accretion expense
24,170 
Newly incurred liabilities
22,211 
Asset retirement obligations at the end of year
$ 670,856 
Asset Retirement Obligations - Narrative (Details) (Arizona Public Service Company, USD $)
In Thousands, unless otherwise specified
9 Months Ended 3 Months Ended
Sep. 30, 2017
Sep. 30, 2017
Navajo Generating Station
Asset Retirement Obligations
 
 
Newly incurred liabilities
$ 22,211 
$ 22,000