PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/3/2017
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2017
Jul. 26, 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
Jun. 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
 
111,624,528 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q2 
 
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
Jun. 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
Q2 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
OPERATING REVENUES
$ 944,587 
$ 915,394 
$ 1,622,315 
$ 1,592,561 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
254,611 
274,848 
467,006 
496,133 
Operations and maintenance
214,013 
242,279 
433,989 
485,474 
Depreciation and amortization
125,739 
123,073 
253,366 
242,549 
Taxes other than income taxes
44,289 
42,117 
88,125 
84,618 
Other expenses
1,706 
1,329 
2,094 
1,877 
Total
640,358 
683,646 
1,244,580 
1,310,651 
OPERATING INCOME
304,229 
231,748 
377,735 
281,910 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
10,456 
10,369 
19,938 
20,885 
Other income (Note 8)
484 
197 
964 
314 
Other expense (Note 8)
(3,822)
(2,842)
(7,502)
(6,880)
Total
7,118 
7,724 
13,400 
14,319 
INTEREST EXPENSE
 
 
 
 
Interest charges
54,969 
52,849 
106,833 
103,593 
Allowance for borrowed funds used during construction
(4,906)
(5,301)
(9,378)
(10,528)
Total
50,063 
47,548 
97,455 
93,065 
INCOME BEFORE INCOME TAXES
261,284 
191,924 
293,680 
203,164 
INCOME TAXES
88,967 
65,742 
93,178 
67,656 
NET INCOME
172,317 
126,182 
200,502 
135,508 
Less: Net income attributable to noncontrolling interests (Note 5)
4,874 
4,874 
9,747 
9,747 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
167,443 
121,308 
190,755 
125,761 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
111,797 
111,368 
111,763 
111,336 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
112,345 
112,004 
112,270 
111,930 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 1.50 
$ 1.09 
$ 1.71 
$ 1.13 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 1.49 
$ 1.08 
$ 1.70 
$ 1.12 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 1.31 
$ 1.25 
$ 1.31 
$ 1.25 
APS
 
 
 
 
ELECTRIC OPERATING REVENUES
942,615 
909,757 
1,619,485 
1,586,389 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
259,892 
274,848 
476,995 
496,133 
Operations and maintenance
208,286 
233,712 
420,505 
472,423 
Depreciation and amortization
125,317 
123,033 
252,524 
242,479 
Income taxes
92,381 
70,444 
103,754 
76,294 
Taxes other than income taxes
43,949 
42,036 
87,447 
84,446 
Total
729,825 
744,073 
1,341,225 
1,371,775 
OPERATING INCOME
212,790 
165,684 
278,260 
214,614 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Income taxes
3,856 
1,721 
6,579 
3,536 
Allowance for equity funds used during construction
10,456 
10,369 
19,938 
20,885 
Other income (Note 8)
1,142 
5,747 
2,204 
6,357 
Other expense (Note 8)
(5,651)
(4,430)
(10,029)
(9,180)
Total
9,803 
13,407 
18,692 
21,598 
INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
49,989 
48,903 
97,480 
95,722 
Interest on short-term borrowings
2,331 
1,930 
4,459 
4,007 
Debt discount, premium and expense
1,197 
1,195 
2,374 
2,334 
Allowance for borrowed funds used during construction
(4,906)
(4,999)
(9,378)
(10,039)
Total
48,611 
47,029 
94,935 
92,024 
NET INCOME
173,982 
132,062 
202,017 
144,188 
Less: Net income attributable to noncontrolling interests (Note 5)
4,874 
4,874 
9,747 
9,747 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 169,108 
$ 127,188 
$ 192,270 
$ 134,441 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
NET INCOME
$ 172,317 
$ 126,182 
$ 200,502 
$ 135,508 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax expense
7 
128 
(763)
(566)
Reclassification of net realized loss, net of tax expense
564 
624 
1,771 
1,766 
Pension and other postretirement benefits activity, net of tax expense
(1,334)
(701)
(812)
(171)
Total other comprehensive income (loss)
(763)
51 
196 
1,029 
COMPREHENSIVE INCOME
171,554 
126,233 
200,698 
136,537 
Less: Comprehensive income attributable to noncontrolling interests
4,874 
4,874 
9,747 
9,747 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
166,680 
121,359 
190,951 
126,790 
APS
 
 
 
 
NET INCOME
173,982 
132,062 
202,017 
144,188 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax expense
7 
128 
(763)
(566)
Reclassification of net realized loss, net of tax expense
564 
624 
1,771 
1,766 
Pension and other postretirement benefits activity, net of tax expense
(1,308)
(642)
(697)
(31)
Total other comprehensive income (loss)
(737)
110 
311 
1,169 
COMPREHENSIVE INCOME
173,245 
132,172 
202,328 
145,357 
Less: Comprehensive income attributable to noncontrolling interests
4,874 
4,874 
9,747 
9,747 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 168,371 
$ 127,298 
$ 192,581 
$ 135,610 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Net unrealized loss, tax expense
$ 4 
$ 80 
$ 679 
$ 626 
Reclassification of net realized loss, tax expense (benefit)
(348)
(392)
8 
(191)
Pension and other postretirement benefits activity, tax benefit (expense)
823 
439 
119 
(206)
Arizona Public Service Company
 
 
 
 
Net unrealized loss, tax expense
4 
80 
679 
626 
Reclassification of net realized loss, tax expense (benefit)
(348)
(392)
8 
(191)
Pension and other postretirement benefits activity, tax benefit (expense)
$ 808 
$ 403 
$ 218 
$ (156)
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 4,953 
$ 8,881 
Customer and other receivables
293,266 
250,491 
Accrued unbilled revenues
213,703 
107,949 
Allowance for doubtful accounts
(2,151)
(3,037)
Materials and supplies (at average cost)
258,134 
253,979 
Fossil fuel (at average cost)
29,890 
28,608 
Income tax receivable
4,073 
3,751 
Assets from risk management activities (Note 6)
307 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
48,122 
12,465 
Other regulatory assets (Note 3)
172,606 
94,410 
Other current assets
45,301 
45,028 
Total current assets
1,068,204 
822,219 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
55 
1 
Nuclear decommissioning trust (Note 11)
822,244 
779,586 
Other assets
71,121 
69,063 
Total investments and other assets
893,420 
848,650 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,227,444 
17,341,888 
Accumulated depreciation and amortization
(5,951,653)
(5,970,100)
Net
11,275,791 
11,371,788 
Construction work in progress
1,195,076 
1,019,947 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
111,580 
113,515 
Intangible assets, net of accumulated amortization
265,926 
90,022 
Nuclear fuel, net of accumulated amortization
118,909 
119,004 
Total property, plant and equipment
12,967,282 
12,714,276 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,415,091 
1,313,428 
Assets for other postretirement benefits (Note 4)
184,629 
166,206 
Other
141,101 
139,474 
Total deferred debits
1,740,821 
1,619,108 
TOTAL ASSETS
16,669,727 
16,004,253 
CURRENT LIABILITIES
 
 
Accounts payable
270,262 
264,631 
Accrued taxes
150,709 
138,964 
Accrued interest
53,046 
52,835 
Common dividends payable
73,113 
72,926 
Short-term borrowings (Note 2)
482,000 
177,200 
Current maturities of long-term debt (Note 2)
207,000 
125,000 
Customer deposits
72,585 
82,520 
Liabilities from risk management activities (Note 6)
48,613 
25,836 
Liabilities for asset retirements
8,960 
9,135 
Regulatory liabilities (Note 3)
91,173 
99,899 
Other current liabilities
181,133 
244,000 
Total current liabilities
1,638,594 
1,292,946 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
4,192,520 
4,021,785 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
3,048,007 
2,945,232 
Regulatory liabilities (Note 3)
940,106 
948,916 
Liabilities for asset retirements
631,657 
615,340 
Liabilities for pension benefits (Note 4)
460,368 
509,310 
Liabilities from risk management activities (Note 6)
46,586 
47,238 
Customer advances
98,795 
88,672 
Coal mine reclamation
236,811 
221,910 
Deferred investment tax credit
206,969 
210,162 
Unrecognized tax benefits
10,307 
10,046 
Other
168,930 
156,784 
Total deferred credits and other
5,848,536 
5,753,610 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,642,680 and 111,392,053 issued at respective dates
2,604,482 
2,596,030 
Treasury stock at cost; 19,298 and 55,317 shares at respective dates
(1,553)
(4,133)
Total common stock
2,602,929 
2,591,897 
Retained earnings
2,300,109 
2,255,547 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(39,882)
(39,070)
Derivative instruments
(3,744)
(4,752)
Total accumulated other comprehensive loss
(43,626)
(43,822)
Total shareholders’ equity
4,859,412 
4,803,622 
Noncontrolling interests (Note 5)
130,665 
132,290 
Total equity
4,990,077 
4,935,912 
TOTAL LIABILITIES AND EQUITY
16,669,727 
16,004,253 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
4,851 
8,840 
Customer and other receivables
285,482 
262,611 
Accrued unbilled revenues
213,703 
107,949 
Allowance for doubtful accounts
(2,151)
(3,037)
Materials and supplies (at average cost)
256,828 
252,777 
Fossil fuel (at average cost)
29,890 
28,608 
Income tax receivable
0 
11,174 
Assets from risk management activities (Note 6)
307 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
48,122 
12,465 
Other regulatory assets (Note 3)
172,606 
94,410 
Other current assets
38,743 
41,849 
Total current assets
1,048,381 
837,340 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
55 
1 
Nuclear decommissioning trust (Note 11)
822,244 
779,586 
Other assets
49,798 
48,320 
Total investments and other assets
872,097 
827,907 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,112,413 
17,228,787 
Accumulated depreciation and amortization
(5,865,446)
(5,881,941)
Net
11,246,967 
11,346,846 
Construction work in progress
1,157,017 
989,497 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
111,580 
113,515 
Intangible assets, net of accumulated amortization
265,764 
89,868 
Nuclear fuel, net of accumulated amortization
118,909 
119,004 
Total property, plant and equipment
12,900,237 
12,658,730 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,415,091 
1,313,428 
Assets for other postretirement benefits (Note 4)
181,237 
162,911 
Other
129,423 
130,859 
Total deferred debits
1,725,751 
1,607,198 
TOTAL ASSETS
16,546,466 
15,931,175 
CURRENT LIABILITIES
 
 
Accounts payable
265,291 
259,161 
Accrued taxes
147,335 
130,576 
Accrued interest
52,752 
52,525 
Common dividends payable
73,100 
72,900 
Short-term borrowings (Note 2)
385,700 
135,500 
Current maturities of long-term debt (Note 2)
82,000 
0 
Customer deposits
72,585 
82,520 
Liabilities from risk management activities (Note 6)
48,613 
25,836 
Liabilities for asset retirements
8,499 
8,703 
Regulatory liabilities (Note 3)
91,173 
99,899 
Other current liabilities
180,095 
226,417 
Total current liabilities
1,407,143 
1,094,037 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
3,095,019 
2,999,295 
Regulatory liabilities (Note 3)
940,106 
948,916 
Liabilities for asset retirements
623,437 
607,234 
Liabilities for pension benefits (Note 4)
440,016 
488,253 
Liabilities from risk management activities (Note 6)
46,586 
47,238 
Customer advances
98,795 
88,672 
Coal mine reclamation
221,295 
206,645 
Deferred investment tax credit
206,969 
210,162 
Unrecognized tax benefits
37,669 
37,408 
Other
154,185 
143,560 
Total deferred credits and other
5,864,077 
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
2,377,315 
2,331,245 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(21,368)
(20,671)
Derivative instruments
(3,744)
(4,752)
Total accumulated other comprehensive loss
(25,112)
(25,423)
Total shareholders’ equity
4,952,061 
4,905,680 
Noncontrolling interests (Note 5)
130,665 
132,290 
Total equity
5,082,726 
5,037,970 
Long-term debt less current maturities (Note 2)
4,192,520 
4,021,785 
Total capitalization
9,275,246 
9,059,755 
TOTAL LIABILITIES AND EQUITY
$ 16,546,466 
$ 15,931,175 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Jun. 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)
111,642,680 
111,392,053 
Treasury stock at cost, shares (in shares)
19,298 
55,317 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 200,502 
$ 135,508 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
291,285 
282,291 
Deferred fuel and purchased power
(21,993)
(21,026)
Deferred fuel and purchased power amortization
(13,663)
13,778 
Allowance for equity funds used during construction
(19,938)
(20,885)
Deferred income taxes
94,365 
65,881 
Deferred investment tax credit
(3,194)
(2,083)
Change in derivative instruments fair value
(222)
(237)
Stock compensation
12,891 
25,048 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(62,624)
(19,898)
Accrued unbilled revenues
(105,754)
(101,331)
Materials, supplies and fossil fuel
(5,437)
1,551 
Income tax receivable
(322)
589 
Other current assets
(23,418)
(5,649)
Accounts payable
21,771 
47,621 
Accrued taxes
11,745 
6,567 
Other current liabilities
(44,778)
53,912 
Change in margin and collateral accounts — assets
(71)
(34)
Change in margin and collateral accounts — liabilities
(4,700)
18,010 
Change in other long-term assets
(49,162)
(41,101)
Change in other long-term liabilities
13,279 
(16,037)
Net cash flow provided by operating activities
290,562 
422,475 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(693,626)
(731,609)
Contributions in aid of construction
18,032 
29,127 
Allowance for borrowed funds used during construction
(9,378)
(10,528)
Proceeds from nuclear decommissioning trust sales
275,364 
290,594 
Investment in nuclear decommissioning trust
(276,505)
(291,734)
Other
(2,127)
(1,307)
Net cash flow used for investing activities
(688,240)
(715,457)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
251,635 
445,933 
Repayment of long-term debt
0 
(76,850)
Short-term borrowing and payments — net
287,800 
64,140 
Short-term debt borrowings under revolving credit facility
17,000 
0 
Dividends paid on common stock
(142,520)
(135,335)
Common stock equity issuance - net of purchases
(8,792)
10,017 
Distributions to noncontrolling interests
(11,372)
(11,372)
Other
(1)
1 
Net cash flow provided by financing activities
393,750 
296,534 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(3,928)
3,552 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,881 
39,488 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
4,953 
43,040 
Cash paid during the period for:
 
 
Income taxes, net of refunds
2,062 
2,503 
Interest, net of amounts capitalized
94,870 
89,109 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
80,517 
55,286 
Dividends declared but not yet paid
73,113 
69,484 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
202,017 
144,188 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
290,444 
282,221 
Deferred fuel and purchased power
(21,994)
(21,026)
Deferred fuel and purchased power amortization
(13,663)
13,778 
Allowance for equity funds used during construction
(19,938)
(20,885)
Deferred income taxes
87,412 
60,131 
Deferred investment tax credit
(3,194)
(2,083)
Change in derivative instruments fair value
(222)
(237)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(41,422)
(19,809)
Accrued unbilled revenues
(105,754)
(101,331)
Materials, supplies and fossil fuel
(5,333)
1,551 
Income tax receivable
11,174 
0 
Other current assets
(20,039)
(3,749)
Accounts payable
20,147 
48,593 
Accrued taxes
16,759 
17,141 
Other current liabilities
(33,408)
44,711 
Change in margin and collateral accounts — assets
(71)
(34)
Change in margin and collateral accounts — liabilities
(4,700)
18,010 
Change in other long-term assets
(45,420)
(38,780)
Change in other long-term liabilities
13,061 
3,979 
Net cash flow provided by operating activities
325,856 
426,369 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(680,343)
(717,729)
Contributions in aid of construction
18,032 
29,127 
Allowance for borrowed funds used during construction
(9,378)
(10,039)
Proceeds from nuclear decommissioning trust sales
275,364 
290,594 
Investment in nuclear decommissioning trust
(276,505)
(291,734)
Other
(1,478)
(388)
Net cash flow used for investing activities
(674,308)
(700,169)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
251,635 
445,933 
Repayment of long-term debt
0 
(76,850)
Short-term borrowing and payments — net
250,200 
64,140 
Dividends paid on common stock
(146,000)
(138,900)
Distributions to noncontrolling interests
(11,372)
(11,372)
Net cash flow provided by financing activities
344,463 
282,951 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(3,989)
9,151 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,840 
22,056 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
4,851 
31,207 
Cash paid during the period for:
 
 
Income taxes, net of refunds
1 
8,772 
Interest, net of amounts capitalized
92,334 
88,066 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
82,621 
55,286 
Dividends declared but not yet paid
$ 73,100 
$ 69,500 
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
135,508 
 
 
125,761 
 
9,747 
144,188 
 
 
134,441 
 
9,747 
Other comprehensive income
1,029 
 
 
 
1,029 
 
1,169 
 
 
 
1,169 
 
Dividends on common stock
(138,947)
 
 
(138,947)
 
 
(139,000)
 
 
(139,000)
 
 
Issuance of common stock (in shares)
 
80,098 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
7,830 
7,830 
 
 
 
 
 
 
 
 
 
 
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
10,558 
 
10,556 
2 
 
0 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(11,372)
 
 
 
 
(11,372)
(11,372)
 
 
 
 
(11,372)
Balance at end of period at Jun. 30, 2016
4,719,183 
2,549,498 
(130)
2,079,619 
(43,719)
133,915 
4,809,779 
178,162 
2,379,696 
2,143,934 
(25,928)
133,915 
Ending balance (in shares) at Jun. 30, 2016
 
111,175,500 
1,900 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Mar. 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
126,182 
 
 
 
 
 
132,062 
 
 
 
 
 
Other comprehensive income
51 
 
 
 
 
 
110 
 
 
 
 
 
Balance at end of period at Jun. 30, 2016
4,719,183 
 
 
 
 
 
4,809,779 
178,162 
2,379,696 
 
 
 
Ending balance (in shares) at Jun. 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
200,502 
 
 
190,755 
 
9,747 
202,017 
 
 
192,270 
 
9,747 
Other comprehensive income
196 
 
 
 
196 
 
311 
 
 
 
311 
 
Dividends on common stock
(146,204)
 
 
(146,204)
 
 
(146,200)
 
 
(146,200)
 
 
Issuance of common stock (in shares)
 
250,627 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
8,452 
8,452 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(156,172)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(12,430)
 
(12,430)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
192,191 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
15,021 
 
15,010 
11 
 
0 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(11,372)
 
 
 
 
(11,372)
(11,372)
 
 
 
 
(11,372)
Balance at end of period at Jun. 30, 2017
4,990,077 
2,604,482 
(1,553)
2,300,109 
(43,626)
130,665 
5,082,726 
178,162 
2,421,696 
2,377,315 
(25,112)
130,665 
Ending balance (in shares) at Jun. 30, 2017
111,642,680 
111,642,680 
19,298 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Mar. 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
172,317 
 
 
 
 
 
173,982 
 
 
 
 
 
Other comprehensive income
(763)
 
 
 
 
 
(737)
 
 
 
 
 
Balance at end of period at Jun. 30, 2017
$ 4,990,077 
 
 
 
 
 
$ 5,082,726 
$ 178,162 
$ 2,421,696 
 
 
 
Ending balance (in shares) at Jun. 30, 2017
111,642,680 
 
 
 
 
 
 
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 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. 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
Six Months Ended June 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
$
—

 
$
25,048

 
$
25,048

Change in other long-term liabilities
9,011

 
(25,048
)
 
(16,037
)

 
 

Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2017
 
2016
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,062

 
$
2,503

Interest, net of amounts capitalized
94,870

 
89,109

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
80,517

 
$
55,286

Dividends accrued but not yet paid
73,113

 
69,484

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 June 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 June 30, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $39.3 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended and restated 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 June 30, 2017, Pinnacle West had $57 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.

At June 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 June 30, 2017, APS had $385.7 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 June 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
4,274,520

 
4,645,844

 
4,021,785

 
4,300,789

Total
$
4,399,520

 
$
4,770,844

 
$
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 June 30, 2017, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $5.0 billion, and total capitalization was approximately $9.4 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.8 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 excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). The principal provisions of the application are described in detail in Note 3 of our 2016 Form 10-K.

On March 1, 2017, the ACC Staff filed with the ACC a settlement term sheet. The settlement term sheet was agreed to by 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. The settlement term sheet was converted into a definitive settlement agreement (the "2017 Settlement Agreement"), was signed by the supporting parties and was filed with the ACC on March 27, 2017. The 2017 Settlement Agreement was submitted to the administrative law judge ("ALJ"), whose decision regarding whether the settlement should be approved will be reviewed by the ACC. Hearings on the proposed settlement began on April 24, 2017 and the hearings were completed on May 2, 2017. Post-hearing briefing on the proposed settlement was completed on June 1, 2017.

In its original filing, APS requested that the rate increase become effective July 1, 2017.  In July 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months. On January 13, 2017, the ALJ issued a procedural order delaying hearings on the case for approximately one month to allow parties to prepare testimony on the distributed generation ("DG") rate design issues addressed in the value and cost of DG decision. In light of this delay in the start of the hearings on the settlement, we expected a moderate delay in the scheduling of a final ACC vote on the settlement beyond the originally-anticipated July 1, 2017 date.

On July 26, 2017, the ALJ issued a recommended opinion and order in the proceeding.  The order recommends ACC approval of the 2017 Settlement Agreement without material modifications and recommends that the new rates go into effect on September 1, 2017.  Parties to the proceeding may file exceptions to the recommended order on or before August 4, 2017. Following the filing of exceptions, the recommended order will be considered by the ACC for a final decision.

On April 27, 2017, Commissioner Burns filed a motion requesting that the ALJ suspend and continue the rate case proceedings and facilitate an investigation to determine whether certain commissioners should be disqualified from further participation in the matter. The ACC denied the motion on June 20, 2017. See more information below under the heading "Subpoena from Arizona Corporation Commissioner Robert Burns."

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 million due to changes in depreciation schedules.

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 environmental improvement surcharge cumulative per kilowatt-hour (“kWh”) cap rate increase from $0.00016 to a new rate of $0.00050, which includes 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 commit to stand by the settlement agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

APS cannot predict whether the 2017 Settlement Agreement will ultimately be approved by the ACC, or the exact timing of the ACC's consideration of the matter.
 
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 ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC.

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

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which includes the revenue neutral transfer of specific revenue requirements in accordance with the 2017 Settlement Agreement.  The ACC has not yet ruled on APS's 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. 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 anticipates that the ACC will schedule the proceedings once there is a decision in APS's pending rate case. 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 its achievement tier level for its performance incentive, 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 July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program.

On June 1, 2016, APS filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on APS's 2017 DSM Plan.

APS was required to file its 2018 DSM Implementation Plan by June 1, 2017, but the ACC granted APS's request to extend the deadline to file the 2018 DSM Implementation Plan until September 1, 2017.
 
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):
 
 
Six Months Ended 
 June 30,
 
2017
 
2016
Beginning balance
$
12,465

 
$
(9,688
)
Deferred fuel and purchased power costs — current period
21,994

 
21,027

Amounts refunded/(charged) to customers
13,663

 
(13,778
)
Ending balance
$
48,122

 
$
(2,439
)

 
The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh.
 
Transmission Rates, Transmission Cost Adjustor ("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.  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 files for a LFCR adjustment every January. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. 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), to be effective for the first billing cycle of March 2017. On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, to be 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.

Net Metering

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

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

In addition, the ACC made the following determinations:

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

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

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

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and will become effective if the ACC approves it. APS cannot predict the outcome of this determination.

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

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. Consistent with Arizona statute, 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. In accordance with the 2017 Settlement Agreement described above, in the event the ACC approves the 2017 Settlement Agreement, these appeals will be withdrawn by TASC. The ACC's decision is expected to remain in effect during any legal challenge.

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.

Subpoena from Arizona Corporation Commissioner Robert Burns

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

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

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. APS did not produce 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 with the ACC. On June 20, 2017, the ACC denied the motion to compel. The manner by which the courts can or should review this decision, as well as the timing and process for that review, is a subject of dispute and has not been decided. APS and Pinnacle West cannot predict the outcome of this matter.

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 $60 million as of June 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 has the matter under review. We cannot predict when or how this matter will be resolved.
 
As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

Cholla

On September 11, 2014, APS announced that it would close 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. The 2017 Settlement Agreement described above contemplates continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($112 million as of June 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. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
Navajo Plant
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.

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

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

 
$
697,184

 
$
—

 
$
711,059

Retired power plant costs
Various
 
19,083

 
205,418

 
9,913

 
117,591

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

 
158,356

 
6,305

 
152,118

Deferred fuel and purchased power — mark-to-market (Note 6)
2020
 
45,993

 
43,354

 
—

 
42,963

Deferred fuel and purchased power (b) (e)
2018
 
48,122

 
—

 
12,465

 
—

Four Corners cost deferral
2024
 
6,689

 
53,549

 
6,689

 
56,894

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

 
53,509

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
75,070

 
—

 
61,307

 
—

Palo Verde VIEs (Note 5)
2046
 
—

 
19,085

 
—

 
18,775

Deferred compensation
2036
 
—

 
37,161

 
—

 
35,595

Deferred property taxes
(c)
 
—

 
85,694

 
—

 
73,200

Loss on reacquired debt
2038
 
1,637

 
16,124

 
1,637

 
16,942

Tax expense of Medicare subsidy
2024
 
1,503

 
9,922

 
1,513

 
10,589

Demand Side Management
2018
 
5,122

 
—

 
3,744

 
—

AG-1 deferral
(f)
 
—

 
10,058

 
—

 
5,868

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,542

 
332

 
10,708

Transmission cost adjustor (b)
2018
 
8,115

 
—

 
—

 
1,588

Coal reclamation
2026
 
418

 
15,135

 
418

 
5,182

Other
Various
 
322

 
—

 
432

 
—

Total regulatory assets (d)
 
 
$
220,728

 
$
1,415,091

 
$
106,875

 
$
1,313,428

(a)
See Note 4 for further discussion.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Per the provision of the 2012 Settlement Agreement.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."
(e)
Subject to a carrying charge.
(f)
Amortization is expected through 2022, but the balance is classified as non-current since the related 2017 Settlement Agreement was not approved as of June 30, 2017.



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

 
$
321,732

 
$
—

 
$
279,976

Removal costs
(a)
 
37,943

 
189,959

 
29,899

 
223,145

Other postretirement benefits
(b)
 
32,725

 
107,764

 
32,662

 
123,913

Income taxes — deferred investment tax credit
2046
 
4,315

 
107,153

 
4,368

 
108,827

Income taxes — change in rates
2046
 
2,565

 
68,583

 
1,771

 
70,898

Spent nuclear fuel
2047
 
—

 
71,996

 
—

 
71,726

Renewable energy standard (c)
2018
 
11,519

 
—

 
26,809

 
—

Demand side management (c)
2019
 
—

 
19,921

 
—

 
20,472

Sundance maintenance
2030
 
—

 
16,092

 
—

 
15,287

Deferred gains on utility property
2019
 
2,063

 
7,851

 
2,063

 
8,895

Four Corners coal reclamation
2031
 
—

 
20,894

 
—

 
18,248

Other
Various
 
43

 
8,161

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
91,173

 
$
940,106

 
$
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 June 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, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Service cost — benefits earned during the period
$
13,669

 
$
12,630

 
$
27,429

 
$
26,896

 
$
4,201

 
$
3,560

 
$
8,559

 
$
7,497

Interest cost on benefit obligation
32,177

 
32,878

 
64,878

 
65,823

 
7,415

 
7,519

 
14,980

 
14,860

Expected return on plan assets
(43,425
)
 
(43,161
)
 
(87,135
)
 
(86,953
)
 
(13,350
)
 
(9,125
)
 
(26,701
)
 
(18,247
)
Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
20

 
132

 
41

 
263

 
(9,461
)
 
(9,471
)
 
(18,921
)
 
(18,942
)
Net actuarial loss
11,460

 
10,627

 
23,950

 
20,358

 
1,104

 
1,349

 
2,559

 
2,295

Net periodic benefit cost
$
13,901

 
$
13,106

 
$
29,163

 
$
26,387

 
$
(10,091
)
 
$
(6,168
)
 
$
(19,524
)
 
$
(12,537
)
Portion of cost charged to expense
$
6,894

 
$
6,433

 
$
14,461

 
$
12,951

 
$
(5,004
)
 
$
(3,027
)
 
$
(9,682
)
 
$
(6,153
)

 
Contributions
 
We have made voluntary contributions of $80 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 six months ended June 30, 2017 of $5 million and $10 million respectively, and for the three and six months ended June 30, 2016 of $5 million and $10 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 June 30, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
June 30, 2017
 
December 31, 2016
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
111,580

 
$
113,515

Equity — Noncontrolling interests
130,665

 
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
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our 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 June 30, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
908

 
GWh
Gas
 
247

 
Billion cubic feet

 
Gains and Losses from Derivative Instruments
 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
11

 
$
208

 
$
(84
)
 
$
60

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(912
)
 
(1,016
)
 
(1,763
)
 
(1,957
)

(a)
During the three and six months ended June 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 $3 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Net Gain (Loss) Recognized in Income
 
Operating revenues
 
$
(58
)
 
$
585

 
$
(346
)
 
$
483

Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
(5,416
)
 
60,894

 
(58,043
)
 
29,958

Total
 
 
 
$
(5,474
)
 
$
61,479

 
$
(58,389
)
 
$
30,441


(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 June 30, 2017 and December 31, 2016, include gross liabilities of $1 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 June 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 June 30, 2017:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
15,624

 
$
(15,387
)
 
$
237

 
$
70

 
$
307

Investments and other assets
 
1,620

 
(1,565
)
 
55

 
—

 
55

Total assets
 
17,244

 
(16,952
)
 
292

 
70

 
362

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(64,646
)
 
18,587

 
(46,059
)
 
(2,554
)
 
(48,613
)
Deferred credits and other
 
(48,151
)
 
1,565

 
(46,586
)
 
—

 
(46,586
)
Total liabilities
 
(112,797
)
 
20,152

 
(92,645
)
 
(2,554
)
 
(95,199
)
Total
 
$
(95,553
)
 
$
3,200

 
$
(92,353
)
 
$
(2,484
)
 
$
(94,837
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $3,200.
(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 $2,554, and cash margin provided to counterparties of $70.
 
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 June 30, 2017, Pinnacle West has no material 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 June 30, 2017 (dollars in thousands):
 
June 30, 2017
Aggregate fair value of derivative instruments in a net liability position
$
112,797

Cash collateral posted
3,200

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
89,336


(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 $126 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. 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 six months ended June 30, 2017, our fuel and purchased power commitments decreased approximately $670 million 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 June 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 work plan ("RI/FS").  The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by November 2017. We estimate that our costs related to this investigation and study will be approximately $2 million.  We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, 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. The court's order for partial summary judgment on this issue is interlocutory, as it only relates to one element of the lawsuit. 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 recently approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the recent Cholla 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.  In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. On March 20, 2017, the Court denied this petition for review and upheld the legality of EPA's final BART rule for the Navajo Plant. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million, is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.  Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  Briefing in the case was completed in February 2014.

In September 2014, APS met with EPA to propose a compromise BART strategy. Pending certain regulatory approvals, APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015.

On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program.  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.

At this time, EPA has yet to publish guidance or proposed rules implementing the CCR provisions of the WIIN Act. In addition, we are unable to predict when Arizona will be able to develop a state-specific permitting program. It is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $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, the majority of which has already been incurred. 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 collect 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.

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 three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for electric generating units ("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 to hold the ongoing litigation over the August 2015 pollution standards 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. At this time we cannot predict the outcome of EPA's review of the August 2015 carbon pollution standards and whether EPA will take action to suspend, rescind or revise these regulations. 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. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners.
    
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 is 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 alleges a shortfall in the Buyer’s purchases for the initial contract year of approximately $27 million. APS’s share of this amount is approximately $17 million. 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.

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 June 30, 2017, standby letters of credit totaled $5 million and will expire in 2017 and 2018. As of June 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 June 30, 2017. Effective July 6, 2016, Pinnacle West has issued three 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 six months ended June 30, 2017 and 2016 (dollars in thousands):

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
387

 
$
184

 
$
864

 
$
302

Investment gains — net
—

 
13

 
—

 
13

Miscellaneous
97

 
—

 
100

 
(1
)
Total other income
$
484

 
$
197

 
$
964

 
$
314

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(3,401
)
 
$
(2,085
)
 
$
(5,360
)
 
$
(4,133
)
Investment losses — net
(227
)
 
(539
)
 
(528
)
 
(1,058
)
Miscellaneous
(194
)
 
(218
)
 
(1,614
)
 
(1,689
)
Total other expense
$
(3,822
)
 
$
(2,842
)
 
$
(7,502
)
 
$
(6,880
)
Other Income and Other Expense 
The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
257

 
$
109

 
$
596

 
$
181

Gain on disposition of property
260

 
4,989

 
567

 
5,321

Miscellaneous
625

 
649

 
1,041

 
855

Total other income
$
1,142

 
$
5,747

 
$
2,204

 
$
6,357

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(3,753
)
 
$
(2,719
)
 
$
(5,918
)
 
$
(4,685
)
Loss on disposition of property
(1,169
)
 
(657
)
 
(1,257
)
 
(1,083
)
Miscellaneous
(729
)
 
(1,054
)
 
(2,854
)
 
(3,412
)
Total other expense
$
(5,651
)
 
$
(4,430
)
 
$
(10,029
)
 
$
(9,180
)

(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 six months ended June 30, 2017 and 2016 (in thousands, except per share amounts):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Net income attributable to common shareholders
$
167,443

 
$
121,308

 
$
190,755

 
$
125,761

Weighted average common shares outstanding — basic
111,797

 
111,368

 
111,763

 
111,336

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
548

 
636

 
507

 
594

Weighted average common shares outstanding — diluted
112,345

 
112,004

 
112,270

 
111,930

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.50

 
$
1.09

 
$
1.71

 
$
1.13

Net income attributable to common shareholders — diluted
$
1.49

 
$
1.08

 
$
1.70

 
$
1.12

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, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments.  See Note 7 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.
 
Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.
 
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.  Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions.
 
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 June 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
June 30,
2017
Assets
 

 
 

 
 

 
 

 
 
 
 

Coal reclamation escrow account (b);


 


 


 


 
 
 


Municipal bonds
$
—

 
$
14,839

 
$
—

 
$
—

 
 
 
$
14,839

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
10,804

 
6,440

 
(16,882
)
 
(c)
 
362

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
384,999

 
(d)
 
384,999

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
—

 
—

 
—

 
1,833

 
(e)
 
1,833

U.S. Treasury
101,337

 
—

 
—

 
—

 
 
 
101,337

Corporate debt
—

 
120,288

 
—

 
—

 
 
 
120,288

Mortgage-backed securities
—

 
113,950

 
—

 
—

 
 
 
113,950

Municipal bonds
—

 
80,659

 
—

 
—

 
 
 
80,659

Other
—

 
19,178

 
—

 
—

 
 
 
19,178

Subtotal nuclear decommissioning trust
101,337

 
334,075

 
—

 
386,832

 
 
 
822,244

Total
$
101,337

 
$
359,718

 
$
6,440

 
$
369,950

 
 
 
$
837,445

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(70,112
)
 
$
(42,685
)
 
$
17,598

 
(c)
 
$
(95,199
)

(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.

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 June 30, 2017 and December 31, 2016:
 
 
June 30, 2017
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
5,996

 
$
25,514

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$18.46 - $38.43
 
$
28.48

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
444

 
17,171

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.16 - $2.81
 
$
2.50

Total
$
6,440

 
$
42,685

 
 
 
 
 
 
 
 


(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 six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
2017
 
2016
 
2017
 
2016
Net derivative balance at beginning of period
 
$
(41,685
)
 
$
(39,507
)
 
$
(47,406
)
 
$
(32,979
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 
 
 
Included in OCI
 
(6
)
 
104

 
(6
)
 
104

Deferred as a regulatory asset or liability
 
4,252

 
1,499

 
(7,503
)
 
(7,604
)
Settlements
 
1,699

 
4,502

 
3,122

 
6,267

Transfers into Level 3 from Level 2
 
(4,350
)
 
120

 
(4,388
)
 
382

Transfers from Level 3 into Level 2
 
3,845

 
902

 
19,936

 
1,450

Net derivative balance at end of period
 
$
(36,245
)
 
$
(32,380
)
 
$
(36,245
)
 
$
(32,380
)
 
 
 
 
 
 
 
 
 
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 June 30, 2017 and December 31, 2016 (dollars in thousands):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
June 30, 2017
 

 
 

 
 

Equity securities
$
384,999

 
$
217,288

 
$
—

Fixed income securities
435,412

 
12,224

 
(2,630
)
Net receivables (a)
1,833

 
—

 
—

Total
$
822,244

 
$
229,512

 
$
(2,630
)
(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 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Realized gains
$
939

 
$
2,282

 
$
3,306

 
$
4,720

Realized losses
(1,159
)
 
(1,350
)
 
(3,612
)
 
(3,136
)
Proceeds from the sale of securities (a)
124,238

 
148,785

 
275,364

 
290,594

(a)
Proceeds are reinvested in the trust.
 
The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2017 is as follows (dollars in thousands):
 
Fair Value
Less than one year
$
14,979

1 year – 5 years
123,392

5 years – 10 years
107,622

Greater than 10 years
189,419

Total
$
435,412

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 on-going, 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 June 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.
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 six months ended June 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2017
 
2016
 
2017
 
2016
Balance at beginning of period
$
(42,863
)
 
$
(43,770
)
 
$
(43,822
)
 
$
(44,748
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
7

  
128

 
(763
)
 
(566
)
Amounts reclassified from accumulated other comprehensive loss (a)
564

 
624

 
1,771

 
1,766

Net current period OCI (loss)
571

 
752

  
1,008

 
1,200

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
(2,157
)
 
(1,585
)
 
(2,157
)
 
(1,585
)
Amounts reclassified from accumulated other comprehensive loss (b)
823

 
884

 
1,345

 
1,414

Net current period OCI (loss)
(1,334
)
 
(701
)
 
(812
)
 
(171
)
Balance at end of period
$
(43,626
)
 
$
(43,719
)
 
$
(43,626
)
 
$
(43,719
)

(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 six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
 
2017
 
2016
2017
 
2016
Balance at beginning of period
$
(24,375
)
 
$
(26,038
)
$
(25,423
)
 
$
(27,097
)
Derivative Instruments
 
 
 
 
 
 
OCI (loss) before reclassifications
7

  
128

(763
)
 
(566
)
Amounts reclassified from accumulated other comprehensive loss (a)
564

 
624

1,771

 
1,766

Net current period OCI (loss)
571

 
752

1,008

 
1,200

Pension and Other Postretirement Benefits
 
 
 
 
 
 
OCI (loss) before reclassifications
(2,121
)
 
(1,521
)
(2,121
)
 
(1,521
)
Amounts reclassified from accumulated other comprehensive loss (b)
813

 
879

1,424

 
1,490

Net current period OCI (loss)
(1,308
)
 
(642
)
(697
)
 
(31
)
Balance at end of period
$
(25,112
)
 
$
(25,928
)
$
(25,112
)
 
$
(25,928
)

(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.
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 on-going, 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 June 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.
    

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
Six Months Ended June 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
$
—

 
$
25,048

 
$
25,048

Change in other long-term liabilities
9,011

 
(25,048
)
 
(16,037
)
Summary of supplemental cash flow information 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2017
 
2016
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,062

 
$
2,503

Interest, net of amounts capitalized
94,870

 
89,109

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
80,517

 
$
55,286

Dividends accrued but not yet paid
73,113

 
69,484

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 June 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
4,274,520

 
4,645,844

 
4,021,785

 
4,300,789

Total
$
4,399,520

 
$
4,770,844

 
$
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):
 
 
Six Months Ended 
 June 30,
 
2017
 
2016
Beginning balance
$
12,465

 
$
(9,688
)
Deferred fuel and purchased power costs — current period
21,994

 
21,027

Amounts refunded/(charged) to customers
13,663

 
(13,778
)
Ending balance
$
48,122

 
$
(2,439
)
Schedule of regulatory assets 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
June 30, 2017
 
December 31, 2016
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
697,184

 
$
—

 
$
711,059

Retired power plant costs
Various
 
19,083

 
205,418

 
9,913

 
117,591

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

 
158,356

 
6,305

 
152,118

Deferred fuel and purchased power — mark-to-market (Note 6)
2020
 
45,993

 
43,354

 
—

 
42,963

Deferred fuel and purchased power (b) (e)
2018
 
48,122

 
—

 
12,465

 
—

Four Corners cost deferral
2024
 
6,689

 
53,549

 
6,689

 
56,894

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

 
53,509

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
75,070

 
—

 
61,307

 
—

Palo Verde VIEs (Note 5)
2046
 
—

 
19,085

 
—

 
18,775

Deferred compensation
2036
 
—

 
37,161

 
—

 
35,595

Deferred property taxes
(c)
 
—

 
85,694

 
—

 
73,200

Loss on reacquired debt
2038
 
1,637

 
16,124

 
1,637

 
16,942

Tax expense of Medicare subsidy
2024
 
1,503

 
9,922

 
1,513

 
10,589

Demand Side Management
2018
 
5,122

 
—

 
3,744

 
—

AG-1 deferral
(f)
 
—

 
10,058

 
—

 
5,868

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,542

 
332

 
10,708

Transmission cost adjustor (b)
2018
 
8,115

 
—

 
—

 
1,588

Coal reclamation
2026
 
418

 
15,135

 
418

 
5,182

Other
Various
 
322

 
—

 
432

 
—

Total regulatory assets (d)
 
 
$
220,728

 
$
1,415,091

 
$
106,875

 
$
1,313,428

(a)
See Note 4 for further discussion.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Per the provision of the 2012 Settlement Agreement.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."
(e)
Subject to a carrying charge.
(f)
Amortization is expected through 2022, but the balance is classified as non-current since the related 2017 Settlement Agreement was not approved as of June 30, 2017.

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

 
$
321,732

 
$
—

 
$
279,976

Removal costs
(a)
 
37,943

 
189,959

 
29,899

 
223,145

Other postretirement benefits
(b)
 
32,725

 
107,764

 
32,662

 
123,913

Income taxes — deferred investment tax credit
2046
 
4,315

 
107,153

 
4,368

 
108,827

Income taxes — change in rates
2046
 
2,565

 
68,583

 
1,771

 
70,898

Spent nuclear fuel
2047
 
—

 
71,996

 
—

 
71,726

Renewable energy standard (c)
2018
 
11,519

 
—

 
26,809

 
—

Demand side management (c)
2019
 
—

 
19,921

 
—

 
20,472

Sundance maintenance
2030
 
—

 
16,092

 
—

 
15,287

Deferred gains on utility property
2019
 
2,063

 
7,851

 
2,063

 
8,895

Four Corners coal reclamation
2031
 
—

 
20,894

 
—

 
18,248

Other
Various
 
43

 
8,161

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
91,173

 
$
940,106

 
$
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, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Service cost — benefits earned during the period
$
13,669

 
$
12,630

 
$
27,429

 
$
26,896

 
$
4,201

 
$
3,560

 
$
8,559

 
$
7,497

Interest cost on benefit obligation
32,177

 
32,878

 
64,878

 
65,823

 
7,415

 
7,519

 
14,980

 
14,860

Expected return on plan assets
(43,425
)
 
(43,161
)
 
(87,135
)
 
(86,953
)
 
(13,350
)
 
(9,125
)
 
(26,701
)
 
(18,247
)
Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
20

 
132

 
41

 
263

 
(9,461
)
 
(9,471
)
 
(18,921
)
 
(18,942
)
Net actuarial loss
11,460

 
10,627

 
23,950

 
20,358

 
1,104

 
1,349

 
2,559

 
2,295

Net periodic benefit cost
$
13,901

 
$
13,106

 
$
29,163

 
$
26,387

 
$
(10,091
)
 
$
(6,168
)
 
$
(19,524
)
 
$
(12,537
)
Portion of cost charged to expense
$
6,894

 
$
6,433

 
$
14,461

 
$
12,951

 
$
(5,004
)
 
$
(3,027
)
 
$
(9,682
)
 
$
(6,153
)
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 June 30, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
June 30, 2017
 
December 31, 2016
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
111,580

 
$
113,515

Equity — Noncontrolling interests
130,665

 
132,290

Derivative Accounting (Tables)
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) 
As of June 30, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
908

 
GWh
Gas
 
247

 
Billion cubic feet
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
11

 
$
208

 
$
(84
)
 
$
60

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(912
)
 
(1,016
)
 
(1,763
)
 
(1,957
)

(a)
During the three and six months ended June 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 six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2017
 
2016
 
2017
 
2016
Net Gain (Loss) Recognized in Income
 
Operating revenues
 
$
(58
)
 
$
585

 
$
(346
)
 
$
483

Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
(5,416
)
 
60,894

 
(58,043
)
 
29,958

Total
 
 
 
$
(5,474
)
 
$
61,479

 
$
(58,389
)
 
$
30,441


(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 June 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 June 30, 2017:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
15,624

 
$
(15,387
)
 
$
237

 
$
70

 
$
307

Investments and other assets
 
1,620

 
(1,565
)
 
55

 
—

 
55

Total assets
 
17,244

 
(16,952
)
 
292

 
70

 
362

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(64,646
)
 
18,587

 
(46,059
)
 
(2,554
)
 
(48,613
)
Deferred credits and other
 
(48,151
)
 
1,565

 
(46,586
)
 
—

 
(46,586
)
Total liabilities
 
(112,797
)
 
20,152

 
(92,645
)
 
(2,554
)
 
(95,199
)
Total
 
$
(95,553
)
 
$
3,200

 
$
(92,353
)
 
$
(2,484
)
 
$
(94,837
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $3,200.
(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 $2,554, and cash margin provided to counterparties of $70.
 
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 June 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 June 30, 2017:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
15,624

 
$
(15,387
)
 
$
237

 
$
70

 
$
307

Investments and other assets
 
1,620

 
(1,565
)
 
55

 
—

 
55

Total assets
 
17,244

 
(16,952
)
 
292

 
70

 
362

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(64,646
)
 
18,587

 
(46,059
)
 
(2,554
)
 
(48,613
)
Deferred credits and other
 
(48,151
)
 
1,565

 
(46,586
)
 
—

 
(46,586
)
Total liabilities
 
(112,797
)
 
20,152

 
(92,645
)
 
(2,554
)
 
(95,199
)
Total
 
$
(95,553
)
 
$
3,200

 
$
(92,353
)
 
$
(2,484
)
 
$
(94,837
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $3,200.
(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 $2,554, and cash margin provided to counterparties of $70.
 
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
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 June 30, 2017 (dollars in thousands):
 
June 30, 2017
Aggregate fair value of derivative instruments in a net liability position
$
112,797

Cash collateral posted
3,200

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
89,336


(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 six months ended June 30, 2017 and 2016 (dollars in thousands):

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
387

 
$
184

 
$
864

 
$
302

Investment gains — net
—

 
13

 
—

 
13

Miscellaneous
97

 
—

 
100

 
(1
)
Total other income
$
484

 
$
197

 
$
964

 
$
314

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(3,401
)
 
$
(2,085
)
 
$
(5,360
)
 
$
(4,133
)
Investment losses — net
(227
)
 
(539
)
 
(528
)
 
(1,058
)
Miscellaneous
(194
)
 
(218
)
 
(1,614
)
 
(1,689
)
Total other expense
$
(3,822
)
 
$
(2,842
)
 
$
(7,502
)
 
$
(6,880
)
Detail of other income and other expense 
The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Other income:
 

 
 

 
 

 
 

Interest income
$
257

 
$
109

 
$
596

 
$
181

Gain on disposition of property
260

 
4,989

 
567

 
5,321

Miscellaneous
625

 
649

 
1,041

 
855

Total other income
$
1,142

 
$
5,747

 
$
2,204

 
$
6,357

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(3,753
)
 
$
(2,719
)
 
$
(5,918
)
 
$
(4,685
)
Loss on disposition of property
(1,169
)
 
(657
)
 
(1,257
)
 
(1,083
)
Miscellaneous
(729
)
 
(1,054
)
 
(2,854
)
 
(3,412
)
Total other expense
$
(5,651
)
 
$
(4,430
)
 
$
(10,029
)
 
$
(9,180
)

(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 six months ended June 30, 2017 and 2016 (in thousands, except per share amounts):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Net income attributable to common shareholders
$
167,443

 
$
121,308

 
$
190,755

 
$
125,761

Weighted average common shares outstanding — basic
111,797

 
111,368

 
111,763

 
111,336

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
548

 
636

 
507

 
594

Weighted average common shares outstanding — diluted
112,345

 
112,004

 
112,270

 
111,930

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.50

 
$
1.09

 
$
1.71

 
$
1.13

Net income attributable to common shareholders — diluted
$
1.49

 
$
1.08

 
$
1.70

 
$
1.12

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 June 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
June 30,
2017
Assets
 

 
 

 
 

 
 

 
 
 
 

Coal reclamation escrow account (b);


 


 


 


 
 
 


Municipal bonds
$
—

 
$
14,839

 
$
—

 
$
—

 
 
 
$
14,839

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
10,804

 
6,440

 
(16,882
)
 
(c)
 
362

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
384,999

 
(d)
 
384,999

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
—

 
—

 
—

 
1,833

 
(e)
 
1,833

U.S. Treasury
101,337

 
—

 
—

 
—

 
 
 
101,337

Corporate debt
—

 
120,288

 
—

 
—

 
 
 
120,288

Mortgage-backed securities
—

 
113,950

 
—

 
—

 
 
 
113,950

Municipal bonds
—

 
80,659

 
—

 
—

 
 
 
80,659

Other
—

 
19,178

 
—

 
—

 
 
 
19,178

Subtotal nuclear decommissioning trust
101,337

 
334,075

 
—

 
386,832

 
 
 
822,244

Total
$
101,337

 
$
359,718

 
$
6,440

 
$
369,950

 
 
 
$
837,445

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(70,112
)
 
$
(42,685
)
 
$
17,598

 
(c)
 
$
(95,199
)

(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.

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 June 30, 2017 and December 31, 2016:
 
 
June 30, 2017
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
5,996

 
$
25,514

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$18.46 - $38.43
 
$
28.48

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
444

 
17,171

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.16 - $2.81
 
$
2.50

Total
$
6,440

 
$
42,685

 
 
 
 
 
 
 
 


(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 six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
2017
 
2016
 
2017
 
2016
Net derivative balance at beginning of period
 
$
(41,685
)
 
$
(39,507
)
 
$
(47,406
)
 
$
(32,979
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 
 
 
Included in OCI
 
(6
)
 
104

 
(6
)
 
104

Deferred as a regulatory asset or liability
 
4,252

 
1,499

 
(7,503
)
 
(7,604
)
Settlements
 
1,699

 
4,502

 
3,122

 
6,267

Transfers into Level 3 from Level 2
 
(4,350
)
 
120

 
(4,388
)
 
382

Transfers from Level 3 into Level 2
 
3,845

 
902

 
19,936

 
1,450

Net derivative balance at end of period
 
$
(36,245
)
 
$
(32,380
)
 
$
(36,245
)
 
$
(32,380
)
 
 
 
 
 
 
 
 
 
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 June 30, 2017 and December 31, 2016 (dollars in thousands):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
June 30, 2017
 

 
 

 
 

Equity securities
$
384,999

 
$
217,288

 
$
—

Fixed income securities
435,412

 
12,224

 
(2,630
)
Net receivables (a)
1,833

 
—

 
—

Total
$
822,244

 
$
229,512

 
$
(2,630
)
(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 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Realized gains
$
939

 
$
2,282

 
$
3,306

 
$
4,720

Realized losses
(1,159
)
 
(1,350
)
 
(3,612
)
 
(3,136
)
Proceeds from the sale of securities (a)
124,238

 
148,785

 
275,364

 
290,594

(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 June 30, 2017 is as follows (dollars in thousands):
 
Fair Value
Less than one year
$
14,979

1 year – 5 years
123,392

5 years – 10 years
107,622

Greater than 10 years
189,419

Total
$
435,412

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 six months ended June 30, 2017 and 2016 (dollars in thousands):
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2017
 
2016
 
2017
 
2016
Balance at beginning of period
$
(42,863
)
 
$
(43,770
)
 
$
(43,822
)
 
$
(44,748
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
7

  
128

 
(763
)
 
(566
)
Amounts reclassified from accumulated other comprehensive loss (a)
564

 
624

 
1,771

 
1,766

Net current period OCI (loss)
571

 
752

  
1,008

 
1,200

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
(2,157
)
 
(1,585
)
 
(2,157
)
 
(1,585
)
Amounts reclassified from accumulated other comprehensive loss (b)
823

 
884

 
1,345

 
1,414

Net current period OCI (loss)
(1,334
)
 
(701
)
 
(812
)
 
(171
)
Balance at end of period
$
(43,626
)
 
$
(43,719
)
 
$
(43,626
)
 
$
(43,719
)

(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 six months ended June 30, 2017 and 2016 (dollars in thousands):
 
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
 
2017
 
2016
2017
 
2016
Balance at beginning of period
$
(24,375
)
 
$
(26,038
)
$
(25,423
)
 
$
(27,097
)
Derivative Instruments
 
 
 
 
 
 
OCI (loss) before reclassifications
7

  
128

(763
)
 
(566
)
Amounts reclassified from accumulated other comprehensive loss (a)
564

 
624

1,771

 
1,766

Net current period OCI (loss)
571

 
752

1,008

 
1,200

Pension and Other Postretirement Benefits
 
 
 
 
 
 
OCI (loss) before reclassifications
(2,121
)
 
(1,521
)
(2,121
)
 
(1,521
)
Amounts reclassified from accumulated other comprehensive loss (b)
813

 
879

1,424

 
1,490

Net current period OCI (loss)
(1,308
)
 
(642
)
(697
)
 
(31
)
Balance at end of period
$
(25,112
)
 
$
(25,928
)
$
(25,112
)
 
$
(25,928
)

(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.
Consolidated and Nature of Operations - Schedule of Reclassification of Prior Period Adjustments (Details) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Stock compensation
$ 12,891 
$ 25,048 
Change in other long-term liabilities
13,279 
(16,037)
As previously reported
 
 
Stock compensation
 
0 
Change in other long-term liabilities
 
9,011 
Reclassifications to conform to current year presentation
 
 
Stock compensation
 
25,048 
Change in other long-term liabilities
 
$ (25,048)
Consolidation and Nature of Operations (Details) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Cash paid during the period for:
 
 
Income taxes, net of refunds
$ 2,062 
$ 2,503 
Interest, net of amounts capitalized
94,870 
89,109 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
80,517 
55,286 
Dividends declared but not yet paid
$ 73,113 
$ 69,484 
Long-Term Debt and Liquidity Matters - Narrative (Details) (USD $)
6 Months Ended 0 Months Ended
Jun. 30, 2017
Dec. 31, 2016
Jun. 30, 2017
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing May 2021
Jun. 30, 2017
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing in August 2017
Jun. 30, 2017
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing July 2018
Jun. 30, 2017
Pinnacle West
Letter of Credit
Revolving credit facility maturing May 2021
Jun. 30, 2017
Pinnacle West
Commercial paper
Revolving credit facility maturing May 2021
Jun. 30, 2017
APS
Dec. 31, 2016
APS
Jun. 30, 2017
APS
ACC
Jun. 30, 2017
APS
ACC
Minimum
Jun. 30, 2017
APS
Revolving Credit Facility
Revolving Credit Facilities Maturing in 2021 and 2022
Facility
Jun. 30, 2017
APS
Revolving Credit Facility
Revolving credit facility maturing May 2021
Jun. 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
Jun. 30, 2017
APS
Revolving Credit Facility
Revolving credit facility maturing September 2020
Jun. 29, 2017
APS
Revolving Credit Facility
Revolving credit facility maturing September 2020
Jun. 30, 2017
APS
Letter of Credit
Revolving Credit Facilities Maturing in 2021 and 2022
Jun. 30, 2017
APS
Commercial paper
Jun. 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
Jul. 31, 2017
Subsequent Event
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing July 2018
Jul. 31, 2017
Subsequent Event
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 
 
 
 
 
 
 
 
 
$ 1,000,000,000 
$ 500,000,000 
$ 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)
 
 
300,000,000 
75,000,000 
 
 
 
 
 
 
 
1,400,000,000 
700,000,000 
 
 
700,000,000 
 
 
 
 
 
125,000,000 
 
Long-term line of credit
 
 
0 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
Commercial paper
 
 
 
 
 
 
39,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
385,700,000 
 
 
 
Debt instrument, term
 
 
 
 
364 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, basis spread on variable rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.80% 
Shot-term debt
482,000,000 
177,200,000 
 
57,000,000 
 
 
 
385,700,000 
135,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250,000,000 
 
 
Debt instrument, stated interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.35% 
 
 
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
4,859,412,000 
4,803,622,000 
 
 
 
 
 
4,952,061,000 
4,905,680,000 
5,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total capitalization
 
 
 
 
 
 
 
 
 
9,400,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
 
 
 
 
$ 3,800,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
$ 4,399,520 
$ 4,146,785 
Fair Value
4,770,844 
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
4,274,520 
4,021,785 
Fair Value
$ 4,645,844 
$ 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
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
5.74% 
 
 
Approximate percentage of increase in average residential customer bill
7.96% 
 
 
Regulatory Matters - Settlement Agreement, Cost Recovery Mechanism and Net Metering (Details) (USD $)
6 Months Ended 1 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended 1 Months Ended 0 Months Ended 2 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended 0 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
APS
Jun. 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
Jun. 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
Mar. 27, 2017
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
AZ Sun Program Phase 2
Jun. 30, 2017
ACC
RES
APS
Jan. 12, 2016
ACC
RES 2016
APS
Jul. 1, 2016
ACC
RES 2017
APS
Jun. 30, 2017
ACC
RES 2018
APS
Sep. 30, 2016
ACC
Modernization and Expansion of the Renewal Energy Standard
APS
Jul. 12, 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
Feb. 1, 2017
ACC
Power Supply Adjustor (PSA)
APS
Jun. 30, 2017
ACC
Power Supply Adjustor (PSA)
APS
Jun. 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
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
8 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of energy storage systems
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of high solar penetration feeders
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of approved budget
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
148,000,000 
 
 
 
 
68,900,000 
68,900,000 
 
68,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of proposed budget
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
150,000,000 
90,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
66,600,000 
62,600,000 
 
 
 
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
21,993,000 
21,026,000 
21,994,000 
21,026,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21,994,000 
21,027,000 
 
 
 
 
 
 
 
Amounts refunded/(charged) to customers
13,663,000 
(13,778,000)
13,663,000 
(13,778,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
13,663,000 
(13,778,000)
 
 
 
 
 
 
 
Ending balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48,122,000 
(2,439,000)
 
 
 
 
 
 
 
PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.001348)
 
 
 
 
 
 
 
 
 
PSA rate for prior year (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001678 
Forward component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.001027)
 
 
 
 
 
 
 
 
 
Historical component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 6 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
Jun. 30, 2017
Four Corners cost deferral
SCE
Four Corners Units 4 and 5
Jun. 30, 2017
Retired power plant costs
Jun. 30, 2017
Navajo Plant
Jun. 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
 
 
 
60 
 
 
 
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
 
 
 
 
$ 112 
$ 102 
 
 
Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Detail of regulatory assets
 
 
Regulatory assets, current
$ 220,728 
$ 106,875 
Regulatory assets, non-current
1,415,091 
1,313,428 
Pension
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
697,184 
711,059 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
19,083 
9,913 
Regulatory assets, non-current
205,418 
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
158,356 
152,118 
Deferred fuel and purchased power — mark-to-market (Note 6)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
45,993 
0 
Regulatory assets, non-current
43,354 
42,963 
Deferred fuel and purchased power (b) (e)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
48,122 
12,465 
Regulatory assets, non-current
0 
0 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,689 
6,689 
Regulatory assets, non-current
53,549 
56,894 
Income taxes — investment tax credit basis adjustment
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
2,120 
2,120 
Regulatory assets, non-current
53,509 
54,356 
Lost fixed cost recovery (b)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
75,070 
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
19,085 
18,775 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
37,161 
35,595 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
85,694 
73,200 
Loss on reacquired debt
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,637 
1,637 
Regulatory assets, non-current
16,124 
16,942 
Tax expense of Medicare subsidy
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,503 
1,513 
Regulatory assets, non-current
9,922 
10,589 
Demand side management (c)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
5,122 
3,744 
Regulatory assets, non-current
0 
0 
AG-1 deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
10,058 
5,868 
Mead-Phoenix transmission line CIAC
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
332 
332 
Regulatory assets, non-current
10,542 
10,708 
Transmission cost adjustor (b)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
8,115 
0 
Regulatory assets, non-current
0 
1,588 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
418 
418 
Regulatory assets, non-current
15,135 
5,182 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
322 
432 
Regulatory assets, non-current
$ 0 
$ 0 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 91,173 
$ 99,899 
Regulatory liabilities, non-current
940,106 
948,916 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
321,732 
279,976 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
37,943 
29,899 
Regulatory liabilities, non-current
189,959 
223,145 
Other postretirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
32,725 
32,662 
Regulatory liabilities, non-current
107,764 
123,913 
Income taxes — deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
4,315 
4,368 
Regulatory liabilities, non-current
107,153 
108,827 
Income taxes — change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,565 
1,771 
Regulatory liabilities, non-current
68,583 
70,898 
Spent nuclear fuel
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
71,996 
71,726 
Renewable energy standard (c)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
11,519 
26,809 
Regulatory liabilities, non-current
0 
0 
Demand side management (c)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
19,921 
20,472 
Sundance maintenance
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
16,092 
15,287 
Deferred gains on utility property
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,063 
2,063 
Regulatory liabilities, non-current
7,851 
8,895 
Four Corners coal reclamation
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
20,894 
18,248 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
43 
2,327 
Regulatory liabilities, non-current
$ 8,161 
$ 7,529 
Retirement Plans and Other Postretirement Benefits - Narrative (Details) (USD $)
6 Months Ended
Jun. 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
80,000,000 
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 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Pension Benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
$ 13,669 
$ 12,630 
$ 27,429 
$ 26,896 
Interest cost on benefit obligation
32,177 
32,878 
64,878 
65,823 
Expected return on plan assets
(43,425)
(43,161)
(87,135)
(86,953)
Amortization of:
 
 
 
 
Prior service cost (credit)
20 
132 
41 
263 
Net actuarial loss
11,460 
10,627 
23,950 
20,358 
Net periodic benefit cost
13,901 
13,106 
29,163 
26,387 
Portion of cost charged to expense
6,894 
6,433 
14,461 
12,951 
Other Benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
4,201 
3,560 
8,559 
7,497 
Interest cost on benefit obligation
7,415 
7,519 
14,980 
14,860 
Expected return on plan assets
(13,350)
(9,125)
(26,701)
(18,247)
Amortization of:
 
 
 
 
Prior service cost (credit)
(9,461)
(9,471)
(18,921)
(18,942)
Net actuarial loss
1,104 
1,349 
2,559 
2,295 
Net periodic benefit cost
(10,091)
(6,168)
(19,524)
(12,537)
Portion of cost charged to expense
$ (5,004)
$ (3,027)
$ (9,682)
$ (6,153)
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) (USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2017
power_plant
Jun. 30, 2016
Jun. 30, 2017
power_plant
Jun. 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
$ 4,874,000 
$ 4,874,000 
$ 9,747,000 
$ 9,747,000 
 
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
4,874,000 
4,874,000 
9,747,000 
9,747,000 
 
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 
10,000,000 
10,000,000 
 
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
Jun. 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
$ 111,580 
$ 113,515 
Equity — Noncontrolling interests
130,665 
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
111,580 
113,515 
Equity — Noncontrolling interests
130,665 
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
111,580 
113,515 
Equity — Noncontrolling interests
$ 130,665 
$ 132,290 
Derivative Accounting - Narrative (Details) (USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2017
Designated as Hedging Instruments
Dec. 31, 2016
Designated as Hedging Instruments
Jun. 30, 2017
Commodity Contracts
Dec. 31, 2016
Commodity Contracts
Jun. 30, 2017
Commodity Contracts
Designated as Hedging Instruments
Jun. 30, 2016
Commodity Contracts
Designated as Hedging Instruments
Jun. 30, 2017
Commodity Contracts
Designated as Hedging Instruments
Jun. 30, 2016
Commodity Contracts
Designated as Hedging Instruments
Jun. 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
 
 
 
 
 
 
(3,000,000)
 
 
Gross recognized derivatives
1,000,000 
2,000,000 
112,797,000 
104,123,000 
 
 
 
 
 
Additional collateral to counterparties for energy related non-derivative instrument contracts
 
 
$ 126,000,000 
 
 
 
 
 
 
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) (Commodity Contracts)
6 Months Ended
Jun. 30, 2017
Bcf
GWh
Commodity Contracts
 
Outstanding gross notional amount of derivatives
 
Power
908 
Gas
247 
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 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)
(912,000)
(1,016,000)
(1,763,000)
(1,957,000)
Not Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net loss recognized in income
(5,474,000)
61,479,000 
(58,389,000)
30,441,000 
Not Designated as Hedging Instruments |
Operating revenues
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net loss recognized in income
(58,000)
585,000 
(346,000)
483,000 
Not Designated as Hedging Instruments |
Fuel and purchased power
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net loss recognized in income
(5,416,000)
60,894,000 
(58,043,000)
29,958,000 
Other comprehensive income |
Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
$ 11,000 
$ 208,000 
$ (84,000)
$ 60,000 
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) (Commodity Contracts, USD $)
Jun. 30, 2017
Dec. 31, 2016
Assets
 
 
Gross Recognized Derivatives
$ 17,244,000 
$ 54,798,000 
Amounts Offset
(16,952,000)
(35,103,000)
Net Recognized Derivatives
292,000 
19,695,000 
Other
70,000 
0 
Derivative assets
362,000 
19,695,000 
Liabilities
 
 
Gross Recognized Derivatives
(112,797,000)
(104,123,000)
Amounts Offset
20,152,000 
35,103,000 
Net Recognized Derivatives
(92,645,000)
(69,020,000)
Other
(2,554,000)
(4,054,000)
Amount Reported on Balance Sheet
(95,199,000)
(73,074,000)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(95,553,000)
(49,325,000)
Amounts Offset
3,200,000 
0 
Net Recognized Derivatives
(92,353,000)
(49,325,000)
Other
(2,484,000)
(4,054,000)
Amount Reported on Balance Sheet
(94,837,000)
(53,379,000)
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
15,624,000 
48,094,000 
Amounts Offset
(15,387,000)
(28,400,000)
Net Recognized Derivatives
237,000 
19,694,000 
Other
70,000 
0 
Derivative assets
307,000 
19,694,000 
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
1,620,000 
6,704,000 
Amounts Offset
(1,565,000)
(6,703,000)
Net Recognized Derivatives
55,000 
1,000 
Other
0 
0 
Derivative assets
55,000 
1,000 
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(64,646,000)
(50,182,000)
Amounts Offset
18,587,000 
28,400,000 
Net Recognized Derivatives
(46,059,000)
(21,782,000)
Other
(2,554,000)
(4,054,000)
Amount Reported on Balance Sheet
(48,613,000)
(25,836,000)
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(48,151,000)
(53,941,000)
Amounts Offset
1,565,000 
6,703,000 
Net Recognized Derivatives
(46,586,000)
(47,238,000)
Other
0 
0 
Amount Reported on Balance Sheet
$ (46,586,000)
$ (47,238,000)
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Commodity Contracts
 
Credit Risk and Credit-Related Contingent Features
 
Aggregate fair value of derivative instruments in a net liability position
$ 112,797 
Cash collateral posted
3,200 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered
$ 89,336 
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)
0 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended
Jun. 30, 2017
Aug. 18, 2014
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Jun. 30, 2017
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Jun. 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
Jun. 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
$ 670,000,000 
 
 
 
 
 
 
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 6 Months Ended
Dec. 16, 2016
plaintiff
Aug. 6, 2013
Defendant
Jun. 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 6 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended
Apr. 28, 2017
Jun. 13, 2017
Coal Supply Agreement Arbitration
Four Corners
Jun. 13, 2017
Arizona Public Service Company
Coal Supply Agreement Arbitration
Four Corners
Jun. 30, 2017
Arizona Public Service Company
Letter of Credit Expiring in 2016 and 2017
Jun. 30, 2017
Arizona Public Service Company
Letters of Credit Expiring in 2017
Jun. 30, 2017
4C Acquisition, LLC
Four Corners Units 4 and 5
Jun. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Four Corners Units 4 and 5
Jun. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Natural gas tolling contract obligations
Four Corners Units 4 and 5
Jun. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Four Corners
Four Corners Units 4 and 5
Jun. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Navajo Plant
Jun. 30, 2017
Regional Haze Rules
Arizona Public Service Company
Cholla
Jun. 30, 2017
Coal combustion waste
Arizona Public Service Company
Four Corners
Jun. 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
Jun. 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% 
63.00% 
 
 
 
 
 
 
 
 
 
Expected environmental cost
 
 
 
 
 
 
$ 400,000,000 
 
 
$ 200,000,000 
$ 100,000,000 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
Litigation abeyance period
60 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Damages sought
 
27,000,000 
17,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds expiring, amount
 
 
 
 
$ 62,000,000 
 
 
 
 
 
 
 
 
 
 
 
Number of parental guarantees
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Other income:
 
 
 
 
Interest income
$ 387 
$ 184 
$ 864 
$ 302 
Investment gains — net
0 
13 
0 
13 
Miscellaneous
97 
0 
100 
(1)
Total other income
484 
197 
964 
314 
Other expense:
 
 
 
 
Non-operating costs
(3,401)
(2,085)
(5,360)
(4,133)
Investment losses — net
(227)
(539)
(528)
(1,058)
Miscellaneous
(194)
(218)
(1,614)
(1,689)
Total other expense
(3,822)
(2,842)
(7,502)
(6,880)
Arizona Public Service Company
 
 
 
 
Other income:
 
 
 
 
Interest income
257 
109 
596 
181 
Gain on disposition of property
260 
4,989 
567 
5,321 
Miscellaneous
625 
649 
1,041 
855 
Total other income
1,142 
5,747 
2,204 
6,357 
Other expense:
 
 
 
 
Non-operating costs
(3,753)
(2,719)
(5,918)
(4,685)
Loss on disposition of property
(1,169)
(657)
(1,257)
(1,083)
Miscellaneous
(729)
(1,054)
(2,854)
(3,412)
Total other expense
$ (5,651)
$ (4,430)
$ (10,029)
$ (9,180)
Earnings Per Share (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Earnings Per Share [Abstract]
 
 
 
 
Net income attributable to common shareholders
$ 167,443 
$ 121,308 
$ 190,755 
$ 125,761 
Weighted average common shares outstanding - basic (in shares)
111,797 
111,368 
111,763 
111,336 
Net effect of dilutive securities:
 
 
 
 
Contingently issuable performance shares and restricted stock units (in shares)
548 
636 
507 
594 
Weighted average common shares outstanding — diluted (in shares)
112,345 
112,004 
112,270 
111,930 
Earnings per weighted-average common share outstanding
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 1.50 
$ 1.09 
$ 1.71 
$ 1.13 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 1.49 
$ 1.08 
$ 1.70 
$ 1.12 
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Assets
 
 
Total
$ 822,244 
$ 779,586 
Total assets
6,440 
11,076 
Municipal bonds
 
 
Assets
 
 
Coal reclamation escrow amount
14,839 
 
Recurring
 
 
Assets
 
 
Coal reclamation escrow amount
 
14,521 
Derivative instruments, other
(16,882)
(35,103)
Derivative assets
362 
19,695 
Nuclear decommissioning trust, other
386,832 
354,056 
Total
822,244 
779,586 
Total, other
369,950 
318,953 
Total assets
837,445 
813,802 
Liabilities
 
 
Total, other
17,598 
31,049 
Amount Reported on Balance Sheet
(95,199)
(73,074)
Recurring |
US commingled equity funds
 
 
Assets
 
 
Nuclear decommissioning trust, other
384,999 
353,261 
Total
384,999 
353,261 
Recurring |
Cash and cash equivalent funds
 
 
Assets
 
 
Nuclear decommissioning trust, other
1,833 
795 
Total
1,833 
795 
Recurring |
U.S. Treasury
 
 
Assets
 
 
Total
101,337 
95,441 
Recurring |
Corporate debt
 
 
Assets
 
 
Total
120,288 
111,623 
Recurring |
Mortgage-backed securities
 
 
Assets
 
 
Total
113,950 
115,337 
Recurring |
Municipal bonds
 
 
Assets
 
 
Total
80,659 
80,997 
Recurring |
Other
 
 
Assets
 
 
Total
19,178 
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
101,337 
95,441 
Gross assets, fair value disclosure
101,337 
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
0 
0 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
U.S. Treasury
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
101,337 
95,441 
Recurring |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Gross derivative assets
10,804 
43,722 
Decommissioning fund investments, gross fair value
334,075 
330,089 
Gross assets, fair value disclosure
359,718 
373,811 
Liabilities
 
 
Gross derivative liability
(70,112)
(45,641)
Recurring |
Significant Other Observable Inputs (Level 2) |
Corporate debt
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
120,288 
111,623 
Recurring |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
113,950 
115,337 
Recurring |
Significant Other Observable Inputs (Level 2) |
Municipal bonds
 
 
Assets
 
 
Coal reclamation escrow amount
14,839 
 
Decommissioning fund investments, gross fair value
80,659 
80,997 
Recurring |
Significant Other Observable Inputs (Level 2) |
Other
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
19,178 
22,132 
Recurring |
Significant Unobservable Inputs (Level 3)
 
 
Assets
 
 
Gross derivative assets
6,440 
11,076 
Gross assets, fair value disclosure
6,440 
11,076 
Liabilities
 
 
Gross derivative liability
$ (42,685)
$ (58,482)
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) (USD $)
In Thousands, unless otherwise specified
6 Months Ended 12 Months Ended
Jun. 30, 2017
Dec. 31, 2016
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
$ 6,440 
$ 11,076 
Liabilities
42,685 
58,482 
Electricity forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
5,996 
10,648 
Liabilities
25,514 
32,042 
Electricity forward contracts |
Minimum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
18.46 
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)
38.43 
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)
28.48 
29.86 
Natural gas forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
444 
428 
Liabilities
$ 17,171 
$ 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)
2.16 
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)
2.81 
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)
2.50 
2.81 
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
 
 
 
 
Net derivative balance at beginning of period
$ (41,685)
$ (39,507)
$ (47,406)
$ (32,979)
Included in OCI
(6)
104 
(6)
104 
Deferred as a regulatory asset or liability
4,252 
1,499 
(7,503)
(7,604)
Settlements
1,699 
4,502 
3,122 
6,267 
Transfers into Level 3 from Level 2
(4,350)
120 
(4,388)
382 
Transfers from Level 3 into Level 2
3,845 
902 
19,936 
1,450 
Net derivative balance at end of period
(36,245)
(32,380)
(36,245)
(32,380)
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 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Dec. 31, 2016
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
$ 822,244 
 
$ 822,244 
 
$ 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
 
 
275,364 
290,594 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
822,244 
 
822,244 
 
779,586 
Arizona Public Service Company
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
822,244 
 
822,244 
 
779,586 
Unrealized Gains
229,512 
 
229,512 
 
197,911 
Unrealized Losses
(2,630)
 
(2,630)
 
(4,962)
Net receivables for securities purchases
1,833 
 
1,833 
 
795 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
 
 
Realized gains
939 
2,282 
3,306 
4,720 
 
Realized losses
(1,159)
(1,350)
(3,612)
(3,136)
 
Proceeds from the sale of securities
124,238 
148,785 
275,364 
290,594 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
822,244 
 
822,244 
 
779,586 
Arizona Public Service Company |
Equity Securities
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
384,999 
 
384,999 
 
353,261 
Unrealized Gains
217,288 
 
217,288 
 
188,091 
Unrealized Losses
0 
 
0 
 
0 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
384,999 
 
384,999 
 
353,261 
Arizona Public Service Company |
Fixed income securities.
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
435,412 
 
435,412 
 
425,530 
Unrealized Gains
12,224 
 
12,224 
 
9,820 
Unrealized Losses
(2,630)
 
(2,630)
 
(4,962)
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Less than one year
14,979 
 
14,979 
 
 
1 year – 5 years
123,392 
 
123,392 
 
 
5 years – 10 years
107,622 
 
107,622 
 
 
Greater than 10 years
189,419 
 
189,419 
 
 
Total
$ 435,412 
 
$ 435,412 
 
$ 425,530 
Changes in Accumulated Other Comprehensive Loss (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
AOCI Including Portion Attributable to Noncontrolling Interest
Mar. 31, 2017
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2016
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
AOCI Including Portion Attributable to Noncontrolling Interest
Mar. 31, 2016
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2015
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Arizona Public Service Company
Jun. 30, 2016
Arizona Public Service Company
Jun. 30, 2017
Arizona Public Service Company
Jun. 30, 2016
Arizona Public Service Company
Jun. 30, 2017
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Mar. 31, 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
Jun. 30, 2016
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Mar. 31, 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
Jun. 30, 2017
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Arizona Public Service Company
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Arizona Public Service Company
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Arizona Public Service Company
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2017
Arizona Public Service Company
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 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 
$ (43,626)
$ (42,863)
$ (43,822)
$ (43,719)
$ (43,770)
$ (44,748)
 
 
 
 
 
 
 
 
 
 
$ 5,037,970 
$ 4,814,794 
$ (25,112)
$ (24,375)
$ (25,423)
$ (25,928)
$ (26,038)
$ (27,097)
 
 
 
 
 
 
 
 
OCI (loss) before reclassifications
 
 
 
 
 
 
 
 
 
 
7 
128 
(763)
(566)
(2,157)
(1,585)
(2,157)
(1,585)
 
 
 
 
 
 
 
 
 
 
7 
128 
(763)
(566)
(2,121)
(1,521)
(2,121)
(1,521)
Amounts reclassified from accumulated other comprehensive loss
 
 
 
 
 
 
 
 
 
 
564 
624 
1,771 
1,766 
823 
884 
1,345 
1,414 
 
 
 
 
 
 
 
 
 
 
564 
624 
1,771 
1,766 
813 
879 
1,424 
1,490 
Total other comprehensive income (loss)
(763)
51 
196 
1,029 
 
 
 
 
 
 
571 
752 
1,008 
1,200 
(1,334)
(701)
(812)
(171)
(737)
110 
311 
1,169 
 
 
 
 
 
 
571 
752 
1,008 
1,200 
(1,308)
(642)
(697)
(31)
Balance at end of period
$ 4,990,077 
$ 4,719,183 
$ 4,990,077 
$ 4,719,183 
$ (43,626)
$ (42,863)
$ (43,822)
$ (43,719)
$ (43,770)
$ (44,748)
 
 
 
 
 
 
 
 
$ 5,082,726 
$ 4,809,779 
$ 5,082,726 
$ 4,809,779 
$ (25,112)
$ (24,375)
$ (25,423)
$ (25,928)
$ (26,038)
$ (27,097)