PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/2/2016
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2016
Jul. 22, 2016
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, 2016 
 
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
 
111,174,772 
Document Fiscal Year Focus
2016 
 
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, 2016 
 
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
2016 
 
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, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
OPERATING REVENUES
$ 915,394 
$ 890,648 
$ 1,592,561 
$ 1,561,867 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
274,848 
281,477 
496,133 
504,714 
Operations and maintenance
242,279 
210,965 
485,474 
425,909 
Depreciation and amortization
123,073 
122,739 
242,549 
243,688 
Taxes other than income taxes
42,117 
43,032 
84,618 
86,248 
Other expenses
1,329 
462 
1,877 
1,651 
Total
683,646 
658,675 
1,310,651 
1,262,210 
OPERATING INCOME
231,748 
231,973 
281,910 
299,657 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
10,369 
9,345 
20,885 
18,569 
Other income (Note 8)
197 
175 
314 
410 
Other expense (Note 8)
(2,842)
(2,609)
(6,880)
(6,895)
Total
7,724 
6,911 
14,319 
12,084 
INTEREST EXPENSE
 
 
 
 
Interest charges
52,849 
48,328 
103,593 
96,727 
Allowance for borrowed funds used during construction
(5,301)
(4,322)
(10,528)
(8,538)
Total
47,548 
44,006 
93,065 
88,189 
INCOME BEFORE INCOME TAXES
191,924 
194,878 
203,164 
223,552 
INCOME TAXES
65,742 
67,371 
67,656 
75,318 
NET INCOME
126,182 
127,507 
135,508 
148,234 
Less: Net income attributable to noncontrolling interests (Note 5)
4,874 
4,605 
9,747 
9,210 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
121,308 
122,902 
125,761 
139,024 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
111,368 
110,986 
111,336 
110,958 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
112,004 
111,460 
111,930 
111,426 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 1.09 
$ 1.11 
$ 1.13 
$ 1.25 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 1.08 
$ 1.10 
$ 1.12 
$ 1.25 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 1.25 
$ 1.19 
$ 1.25 
$ 1.19 
APS
 
 
 
 
ELECTRIC OPERATING REVENUES
909,757 
889,723 
1,586,389 
1,560,391 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
274,848 
281,477 
496,133 
504,714 
Operations and maintenance
233,712 
208,031 
472,423 
417,978 
Depreciation and amortization
123,033 
122,716 
242,479 
243,642 
Income taxes
70,444 
71,672 
76,294 
83,911 
Taxes other than income taxes
42,036 
43,123 
84,446 
86,109 
Total
744,073 
727,019 
1,371,775 
1,336,354 
OPERATING INCOME
165,684 
162,704 
214,614 
224,037 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
10,369 
9,345 
20,885 
18,569 
Income taxes
1,721 
2,980 
3,536 
5,131 
Other income (Note 8)
5,747 
710 
6,357 
1,349 
Other expense (Note 8)
(4,430)
(2,449)
(9,180)
(7,803)
Total
13,407 
10,586 
21,598 
17,246 
INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
48,903 
44,826 
95,722 
90,254 
Interest on short-term borrowings
1,930 
1,705 
4,007 
2,879 
Debt discount, premium and expense
1,195 
1,103 
2,334 
2,237 
Allowance for borrowed funds used during construction
(4,999)
(4,311)
(10,039)
(8,527)
Total
47,029 
43,323 
92,024 
86,843 
NET INCOME
132,062 
129,967 
144,188 
154,440 
Less: Net income attributable to noncontrolling interests (Note 5)
4,874 
4,605 
9,747 
9,210 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 127,188 
$ 125,362 
$ 134,441 
$ 145,230 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
NET INCOME
$ 126,182 
$ 127,507 
$ 135,508 
$ 148,234 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
128 
25 
(566)
(775)
Reclassification of net realized loss, net of tax benefit
624 
874 
1,766 
2,850 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(701)
(117)
(171)
466 
Total other comprehensive income
51 
782 
1,029 
2,541 
COMPREHENSIVE INCOME
126,233 
128,289 
136,537 
150,775 
Less: Comprehensive income attributable to noncontrolling interests
4,874 
4,605 
9,747 
9,210 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
121,359 
123,684 
126,790 
141,565 
APS
 
 
 
 
NET INCOME
132,062 
129,967 
144,188 
154,440 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
128 
25 
(566)
(775)
Reclassification of net realized loss, net of tax benefit
624 
874 
1,766 
2,850 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(642)
(74)
(31)
607 
Total other comprehensive income
110 
825 
1,169 
2,682 
COMPREHENSIVE INCOME
132,172 
130,792 
145,357 
157,122 
Less: Comprehensive income attributable to noncontrolling interests
4,874 
4,605 
9,747 
9,210 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 127,298 
$ 126,187 
$ 135,610 
$ 147,912 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Net unrealized gain, tax expense
$ 80 
$ 16 
$ 626 
$ 489 
Reclassification of net realized loss, tax benefit
392 
556 
191 
923 
Pension and other postretirement benefits activity, tax benefit (expense)
439 
74 
(206)
(793)
Arizona Public Service Company
 
 
 
 
Net unrealized gain, tax expense
80 
16 
626 
489 
Reclassification of net realized loss, tax benefit
392 
556 
191 
923 
Pension and other postretirement benefits activity, tax benefit (expense)
$ 403 
$ 47 
$ (156)
$ (722)
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 43,040 
$ 39,488 
Customer and other receivables
278,900 
274,691 
Accrued unbilled revenues
197,571 
96,240 
Allowance for doubtful accounts
(2,755)
(3,125)
Materials and supplies (at average cost)
241,612 
234,234 
Fossil fuel (at average cost)
36,768 
45,697 
Income tax receivable
0 
589 
Assets from risk management activities (Note 6)
16,676 
15,905 
Regulatory assets (Note 3)
108,596 
149,555 
Other current assets
42,979 
37,242 
Total current assets
963,387 
890,516 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
5,464 
12,106 
Nuclear decommissioning trust (Note 11)
767,416 
735,196 
Other assets
54,401 
52,518 
Total investments and other assets
827,281 
799,820 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
16,663,962 
16,222,232 
Accumulated depreciation and amortization
(5,733,857)
(5,594,094)
Net
10,930,105 
10,628,138 
Construction work in progress
966,146 
816,307 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
115,450 
117,385 
Intangible assets, net of accumulated amortization
108,751 
123,975 
Nuclear fuel, net of accumulated amortization
120,408 
123,139 
Total property, plant and equipment
12,240,860 
11,808,944 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,190,622 
1,214,146 
Assets for other postretirement benefits (Note 4)
186,505 
185,997 
Other
129,910 
128,835 
Total deferred debits
1,507,037 
1,528,978 
TOTAL ASSETS
15,538,565 
15,028,258 
CURRENT LIABILITIES
 
 
Accounts payable
316,589 
297,480 
Accrued taxes
145,167 
138,600 
Accrued interest
57,927 
56,305 
Common dividends payable
69,484 
69,363 
Short-term borrowings (Note 2)
64,140 
0 
Current maturities of long-term debt (Note 2)
293,580 
357,580 
Customer deposits
79,136 
73,073 
Liabilities from risk management activities (Note 6)
55,338 
77,716 
Liabilities for asset retirements (Note 14)
15,513 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
2,439 
9,688 
Other regulatory liabilities (Note 3)
113,733 
136,078 
Other current liabilities
265,498 
197,861 
Total current liabilities
1,478,544 
1,442,317 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,897,835 
3,462,391 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,794,741 
2,723,425 
Regulatory liabilities (Note 3)
1,010,821 
994,152 
Liabilities for asset retirements (Note 14)
446,324 
415,003 
Liabilities for pension benefits (Note 4)
440,919 
480,998 
Liabilities from risk management activities (Note 6)
52,212 
89,973 
Customer advances
101,568 
115,609 
Coal mine reclamation
203,623 
201,984 
Deferred investment tax credit
184,998 
187,080 
Unrecognized tax benefits
9,772 
9,524 
Other
198,025 
186,345 
Total deferred credits and other
5,443,003 
5,404,093 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,175,500 and 111,095,402 issued at respective dates
2,549,498 
2,541,668 
Treasury stock at cost; 1,900 and 115,030 shares at respective dates
(130)
(5,806)
Total common stock
2,549,368 
2,535,862 
Retained earnings
2,079,619 
2,092,803 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(37,764)
(37,593)
Derivative instruments
(5,955)
(7,155)
Total accumulated other comprehensive loss
(43,719)
(44,748)
Total shareholders’ equity
4,585,268 
4,583,917 
Noncontrolling interests (Note 5)
133,915 
135,540 
Total equity
4,719,183 
4,719,457 
TOTAL LIABILITIES AND EQUITY
15,538,565 
15,028,258 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
31,207 
22,056 
Customer and other receivables
278,692 
274,428 
Accrued unbilled revenues
197,571 
96,240 
Allowance for doubtful accounts
(2,755)
(3,125)
Materials and supplies (at average cost)
241,612 
234,234 
Fossil fuel (at average cost)
36,768 
45,697 
Assets from risk management activities (Note 6)
16,676 
15,905 
Regulatory assets (Note 3)
108,596 
149,555 
Other current assets
39,602 
35,765 
Total current assets
947,969 
870,755 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
5,464 
12,106 
Nuclear decommissioning trust (Note 11)
767,416 
735,196 
Other assets
34,843 
34,455 
Total investments and other assets
807,723 
781,757 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
16,660,370 
16,218,724 
Accumulated depreciation and amortization
(5,730,672)
(5,590,937)
Net
10,929,698 
10,627,787 
Construction work in progress
948,472 
812,845 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
115,450 
117,385 
Intangible assets, net of accumulated amortization
108,596 
123,820 
Nuclear fuel, net of accumulated amortization
120,408 
123,139 
Total property, plant and equipment
12,222,624 
11,804,976 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,190,622 
1,214,146 
Assets for other postretirement benefits (Note 4)
183,131 
182,625 
Other
128,348 
127,923 
Total deferred debits
1,502,101 
1,524,694 
TOTAL ASSETS
15,480,417 
14,982,182 
CURRENT LIABILITIES
 
 
Accounts payable
311,655 
291,574 
Accrued taxes
161,629 
144,488 
Accrued interest
57,627 
56,003 
Common dividends payable
69,500 
69,400 
Short-term borrowings (Note 2)
64,140 
0 
Current maturities of long-term debt (Note 2)
293,580 
357,580 
Customer deposits
79,136 
73,073 
Liabilities from risk management activities (Note 6)
55,338 
77,716 
Liabilities for asset retirements (Note 14)
16,000 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
2,439 
9,688 
Other regulatory liabilities (Note 3)
113,733 
136,078 
Other current liabilities
239,926 
180,535 
Total current liabilities
1,464,216 
1,424,708 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,830,006 
2,764,489 
Regulatory liabilities (Note 3)
1,010,821 
994,152 
Liabilities for asset retirements (Note 14)
446,324 
415,003 
Liabilities for pension benefits (Note 4)
419,545 
459,065 
Liabilities from risk management activities (Note 6)
52,212 
89,973 
Customer advances
101,568 
115,609 
Coal mine reclamation
203,623 
201,984 
Deferred investment tax credit
184,998 
187,080 
Unrecognized tax benefits
35,497 
35,251 
Other
148,993 
142,683 
Total deferred credits and other
5,433,587 
5,405,289 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
2,143,934 
2,148,493 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(19,973)
(19,942)
Derivative instruments
(5,955)
(7,155)
Total shareholders’ equity
4,675,864 
4,679,254 
Noncontrolling interests (Note 5)
133,915 
135,540 
Total equity
4,809,779 
4,814,794 
Long-term debt less current maturities (Note 2)
3,772,835 
3,337,391 
Total capitalization
8,582,614 
8,152,185 
TOTAL LIABILITIES AND EQUITY
$ 15,480,417 
$ 14,982,182 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Jun. 30, 2016
Dec. 31, 2015
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
 
 
Common stock, par value (in dollars per share)
   
   
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
111,175,500 
111,095,402 
Treasury stock at cost, shares
1,900 
115,030 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 135,508 
$ 148,234 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
282,291 
282,218 
Deferred fuel and purchased power
(21,026)
11,711 
Deferred fuel and purchased power amortization
13,778 
11,424 
Allowance for equity funds used during construction
(20,885)
(18,569)
Deferred income taxes
65,881 
65,377 
Deferred investment tax credit
(2,083)
(2,218)
Change in derivative instruments fair value
(237)
(225)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(19,898)
(17,402)
Accrued unbilled revenues
(101,331)
(84,683)
Materials, supplies and fossil fuel
1,551 
(18,311)
Income tax receivable
589 
3,098 
Other current assets
(5,649)
(8,728)
Accounts payable
47,621 
36,634 
Accrued taxes
6,567 
15,199 
Other current liabilities
53,912 
(13,138)
Change in margin and collateral accounts — assets
(34)
(4,552)
Change in margin and collateral accounts — liabilities
18,010 
26,853 
Change in other long-term assets
(41,101)
(1,616)
Change in other long-term liabilities
9,011 
(37,012)
Net cash flow provided by operating activities
422,475 
394,294 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(731,609)
(531,035)
Contributions in aid of construction
29,127 
41,010 
Allowance for borrowed funds used during construction
(10,528)
(8,538)
Proceeds from nuclear decommissioning trust sales
290,594 
225,779 
Investment in nuclear decommissioning trust
(291,734)
(234,651)
Other
(1,307)
(2,068)
Net cash flow used for investing activities
(715,457)
(509,503)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
445,933 
600,000 
Repayment of long-term debt
(76,850)
(344,847)
Short-term borrowing and payments — net
64,140 
10,100 
Dividends paid on common stock
(135,335)
(128,241)
Common stock equity issuance - net of purchases
10,017 
12,161 
Distributions to noncontrolling interests
(11,372)
(28,012)
Other
1 
1 
Net cash flow provided by financing activities
296,534 
121,162 
NET INCREASE IN CASH AND CASH EQUIVALENTS
3,552 
5,953 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
39,488 
7,604 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
43,040 
13,557 
Cash paid during the period for:
 
 
Income taxes, net of refunds
2,503 
1,834 
Interest, net of amounts capitalized
89,109 
84,008 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
55,286 
38,985 
Dividends declared but not yet paid
69,484 
65,933 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
144,188 
154,440 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
282,221 
282,172 
Deferred fuel and purchased power
(21,026)
11,711 
Deferred fuel and purchased power amortization
13,778 
11,424 
Allowance for equity funds used during construction
(20,885)
(18,569)
Deferred income taxes
60,131 
24,442 
Deferred investment tax credit
(2,083)
(2,218)
Change in derivative instruments fair value
(237)
(225)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(19,809)
(9,250)
Accrued unbilled revenues
(101,331)
(84,683)
Materials, supplies and fossil fuel
1,551 
(18,311)
Other current assets
(3,749)
(8,193)
Accounts payable
48,593 
37,656 
Accrued taxes
17,141 
68,382 
Other current liabilities
44,711 
(31,408)
Change in margin and collateral accounts — assets
(34)
(4,552)
Change in margin and collateral accounts — liabilities
18,010 
26,853 
Change in other long-term assets
(38,780)
(3,564)
Change in other long-term liabilities
3,979 
(30,337)
Net cash flow provided by operating activities
426,369 
405,770 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(717,729)
(530,850)
Contributions in aid of construction
29,127 
41,010 
Allowance for borrowed funds used during construction
(10,039)
(8,527)
Proceeds from nuclear decommissioning trust sales
290,594 
225,779 
Investment in nuclear decommissioning trust
(291,734)
(234,651)
Other
(388)
(614)
Net cash flow used for investing activities
(700,169)
(507,853)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
445,933 
600,000 
Repayment of long-term debt
(76,850)
(344,847)
Short-term borrowing and payments — net
64,140 
10,100 
Dividends paid on common stock
(138,900)
(131,700)
Distributions to noncontrolling interests
(11,372)
(28,012)
Net cash flow provided by financing activities
282,951 
105,541 
NET INCREASE IN CASH AND CASH EQUIVALENTS
9,151 
3,458 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
22,056 
4,515 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
31,207 
7,973 
Cash paid during the period for:
 
 
Income taxes, net of refunds
8,772 
184 
Interest, net of amounts capitalized
88,066 
82,651 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
55,286 
38,985 
Dividends declared but not yet paid
$ 69,500 
$ 65,900 
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 end of period at Dec. 31, 2014
$ 4,519,102 
$ 2,512,970 
$ (3,401)
$ 1,926,065 
$ (68,141)
$ 151,609 
$ 4,629,852 
$ 178,162 
$ 2,379,696 
$ 1,968,718 
$ (48,333)
$ 151,609 
Beginning balance (in shares) at Dec. 31, 2014
 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
148,234 
 
 
139,024 
 
9,210 
154,440 
 
 
145,230 
 
9,210 
Other comprehensive income
2,541 
 
 
 
2,541 
 
2,682 
 
 
 
2,682 
 
Dividends on common stock
(131,833)
 
 
(131,833)
 
 
(131,800)
 
 
(131,800)
 
 
Other
 
 
 
 
 
 
2 
 
 
2 
 
 
Issuance of common stock (in shares)
 
215,268 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
13,975 
13,975 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(93,280)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(6,096)
 
(6,096)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
118,121 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
7,732 
 
7,732 
0 
 
 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(28,012)
 
 
 
 
(28,012)
(28,012)
 
 
 
 
(28,012)
Balance at beginning of period at Jun. 30, 2015
4,525,643 
2,526,945 
(1,765)
1,933,256 
(65,600)
132,807 
4,627,164 
178,162 
2,379,696 
1,982,150 
(45,651)
132,807 
Ending balance (in shares) at Jun. 30, 2015
 
110,865,030 
53,559 
 
 
 
 
71,264,947 
 
 
 
 
Balance at end of period at Mar. 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
127,507 
 
 
 
 
 
129,967 
 
 
 
 
 
Other comprehensive income
782 
 
 
 
 
 
825 
 
 
 
 
 
Balance at beginning of period at Jun. 30, 2015
4,525,643 
 
 
 
 
 
4,627,164 
178,162 
2,379,696 
 
 
 
Ending balance (in shares) at Jun. 30, 2015
 
 
 
 
 
 
 
71,264,947 
 
 
 
 
Balance at end 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 
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 beginning 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 
111,175,500 
1,900 
 
 
 
 
71,264,947 
 
 
 
 
Balance at end of period at Mar. 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
126,182 
 
 
 
 
 
132,062 
 
 
 
 
 
Other comprehensive income
51 
 
 
 
 
 
110 
 
 
 
 
 
Balance at beginning 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
111,175,500 
 
 
 
 
 
 
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, 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 2015 Form 10-K.
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2016
 
2015
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,503

 
$
1,834

Interest, net of amounts capitalized
89,109

 
84,008

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
55,286

 
$
38,985

Dividends accrued but not yet paid
69,484

 
65,933

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
 
On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $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, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS

During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. Interest rates are based on APS's senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

On May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021.

On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E.

On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A.

On August 1, 2016, APS repaid at maturity APS’s $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016.

At June 30, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021.  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, 2016, APS had $64 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 separate 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, 2016
 
As of December 31, 2015
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,066,415

 
4,658,591

 
3,694,971

 
3,981,367

Total
$
4,191,415

 
$
4,783,591

 
$
3,819,971

 
$
4,106,367

 
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, 2016, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.7 billion, and total capitalization was approximately $8.9 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.6 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 customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%).

The principal provisions of the application are:

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

•
the following proposed capital structure and costs of capital:
 
 
 
Capital Structure
 
Cost of Capital
 
Long-term debt
 
44.2
%
5.13
%
Common stock equity
 
55.8
%
10.50
%
Weighted-average cost of capital
 
 
 
8.13
%

 
•
a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

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

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

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

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

•
updates and modifications to four of APS’s adjustor mechanisms - the Power Supply Adjustor (“PSA”), the Lost Fixed Cost Recovery Mechanism (“LFCR”), the Transmission Cost Adjustor (“TCA”) and the Environmental Improvement Surcharge (“EIS”);

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

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

The Company requested that the increase become effective July 1, 2017.  On July 22, 2016, the administrative law judge set a procedural schedule for the rate proceedings. The ACC staff and interveners will begin filing their direct testimony on December 21, and the hearing will commence on March 22, 2017. The Commission staff supports completing the case within 12 months. APS cannot predict the outcome of its request.

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.
 
Settlement Agreement
 
The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs ("Base Fuel Rate") from $0.03757 to $0.03207 per kilowatt hour ("kWh"); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff ("RES") surcharge to base rates in an estimated amount of $36.8 million.
  
Other key provisions of the 2012 Settlement Agreement include the following:
 
•
An authorized return on common equity of 10.0%;

•
A capital structure comprised of 46.1% debt and 53.9% common equity;

•
A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;
 
•
Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:
 
•
Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

•
Deferral of 100% in all years if Arizona property tax rates decrease;
 
•
A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);
 
•
Implementation of a Lost Fixed Cost Recovery ("LFCR") rate mechanism to support energy efficiency and distributed renewable generation;
 
•
Modifications to the Environmental Improvement Surcharge ("EIS") to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
 
•
Modifications to the Power Supply Adjustor ("PSA"), including the elimination of the 90/10 sharing provision;
 
•
A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge ("DSMAC") to recoup capital expenditures not required under the terms of APS’s 2009 retail rate case settlement agreement (the "2009 Settlement Agreement");
  
•
Modification of the Transmission Cost Adjustor ("TCA") to streamline the process for future transmission-related rate changes; and
 
•
Implementation of various changes to rate schedules, including the adoption of an experimental "buy-through" rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
 
The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.
 
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
  
In accordance with the ACC's decision on APS's 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 megawatts ("MW") of APS-owned grid scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of grid scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program, called the "Solar Partner Program," is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.
 
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.
 
Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. 

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

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology.
 
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. A formal rulemaking has not been initiated and there has been no additional action on the draft to date. 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.
 
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 2016 and 2015 (dollars in thousands):
 
 
Six Months Ended 
 June 30,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,925

Deferred fuel and purchased power costs — current period
21,027

 
(11,710
)
Amounts charged to customers
(13,778
)
 
(11,424
)
Ending balance
$
(2,439
)
 
$
(16,209
)

 
The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh.  On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.
 
Transmission Rates, Transmission Cost Adjustor 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, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2015.

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

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future.
 
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 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. In April 2016, the ACC approved the 2016 annual LFCR to be effective in April 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the one month delay in implementation will not have an adverse effect on APS.

Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS's net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electric grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR.
 
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 
 
On October 20, 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. APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015 and February 23, 2016, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS actively participated in the related hearings held in March 2016. APS has also intervened in the upcoming Tucson Electric Power Company rate case. On June 24, 2016, APS filed testimony in the Tucson Electric Power Company rate case in support of the Tucson Electric Power Company proposed rate design changes. The outcomes of these proceedings will not directly impact our financial position.

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

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument was conducted on March 22, 2016.   If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter.

System Benefits Charge

The 2012 Settlement Agreement  provides 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.

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 $67 million as of June 30, 2016 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. 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 this order in the second quarter of 2016.  On July 29, 2016, APS filed for a 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 the United States Environmental Protection Agency ("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. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and is seeking recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($119 million as of June 30, 2016), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
617,283

 
$
—

 
$
619,223

Retired power plant costs
2033
 
9,913

 
122,554

 
9,913

 
127,518

Income taxes — allowance for funds used during construction ("AFUDC") equity
2046
 
5,419

 
137,611

 
5,495

 
133,712

Deferred fuel and purchased power — mark-to-market (Note 6)
2019
 
30,986

 
40,573

 
71,852

 
69,697

Four Corners cost deferral
2024
 
6,689

 
60,238

 
6,689

 
63,582

Income taxes — investment tax credit basis adjustment
2045
 
1,851

 
47,826

 
1,766

 
48,462

Lost fixed cost recovery (b)
2017
 
49,852

 
—

 
45,507

 
—

Palo Verde VIEs (Note 5)
2046
 
—

 
18,465

 
—

 
18,143

Deferred compensation
2036
 
—

 
35,701

 
—

 
34,751

Deferred property taxes
(c)
 
—

 
62,726

 
—

 
50,453

Loss on reacquired debt
2034
 
1,592

 
16,919

 
1,515

 
16,375

Tax expense of Medicare subsidy
2024
 
1,512

 
11,647

 
1,520

 
12,163

Transmission vegetation management
2016
 
—

 
—

 
4,543

 
—

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,874

 
332

 
11,040

Transmission cost adjustor (b)
2018
 
—

 
2,814

 
—

 
2,942

Coal reclamation
2026
 
418

 
5,391

 
418

 
6,085

Other
Various
 
32

 
—

 
5

 
—

Total regulatory assets (d)
 
 
$
108,596

 
$
1,190,622

 
$
149,555

 
$
1,214,146


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues.  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."

    
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
299,713

 
$
—

 
$
277,554

Removal costs
(a)
 
26,373

 
245,777

 
39,746

 
240,367

Other postretirement benefits
(d)
 
33,294

 
155,279

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2045
 
3,774

 
95,877

 
3,604

 
97,175

Income taxes — change in rates
2046
 
1,771

 
71,257

 
1,113

 
72,454

Spent nuclear fuel
2047
 
31

 
71,342

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
35,882

 
2,182

 
43,773

 
4,365

Demand side management (b)
2017
 
4,957

 
21,864

 
6,079

 
19,115

Sundance maintenance
2030
 
—

 
14,483

 
—

 
13,678

Deferred fuel and purchased power (b) (c)
2017
 
2,439

 
—

 
9,688

 
—

Deferred gains on utility property
2019
 
2,062

 
9,535

 
2,062

 
6,001

Transmission cost adjustor (b)
2017
 
5,545

 
—

 
—

 
—

Four Corners coal reclamation
2031
 
—

 
15,969

 
—

 
8,920

Other
Various
 
44

 
7,543

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
116,172

 
$
1,010,821

 
$
145,766

 
$
994,152


(a)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Subject to a carrying charge.
(d)
See Note 4.
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. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of the plan changes, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $140 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs.
 
Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We completed amortizing these costs as of June 30, 2015. We amortized approximately $2 million and $4 million for the three and six months ended June 30, 2015, respectively.

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 or amortized to the regulatory asset) (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,
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
Service cost — benefits earned during the period
$
12,630

 
$
13,990

 
$
26,896

 
$
29,814

 
$
3,560

 
$
4,068

 
$
7,497

 
$
8,413

Interest cost on benefit obligation
32,878

 
30,802

 
65,823

 
61,992

 
7,519

 
6,867

 
14,860

 
14,051

Expected return on plan assets
(43,161
)
 
(44,467
)
 
(86,953
)
 
(89,616
)
 
(9,125
)
 
(9,281
)
 
(18,247
)
 
(18,428
)
Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost
132

 
149

 
263

 
297

 
(9,471
)
 
(9,492
)
 
(18,942
)
 
(18,984
)
Net actuarial loss
10,627

 
7,767

 
20,358

 
15,528

 
1,349

 
880

 
2,295

 
2,441

Net periodic benefit cost
$
13,106

 
$
8,241

 
$
26,387

 
$
18,015

 
$
(6,168
)
 
$
(6,958
)
 
$
(12,537
)
 
$
(12,507
)
Portion of cost charged to expense
$
6,433

 
$
5,232

 
$
12,951

 
$
11,219

 
$
(3,027
)
 
$
(2,482
)
 
$
(6,153
)
 
$
(4,271
)

 
Contributions
 
We made voluntary contributions of $80 million to our pension plan year-to-date in 2016. 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 2016-2018 period. We expect to make contributions of approximately $1 million in each of 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 for the period 2016 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, resulting in an increase in net income for the three and six months ended June 30, 2016 of $5 million and $10 million respectively, and for the three and six months ended June 30, 2015 of $5 million and $9 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, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):
 
 
June 30,
2016
 
December 31,
2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
115,450

 
$
117,385

Equity — Noncontrolling interests
133,915

 
135,540


 
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 United States 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 $288 million beginning in 2016, 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.
 
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time.  We assess hedge effectiveness both at inception and on a continuing basis.  These assessments exclude the time value of certain options.  For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings.  We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment.  As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.
 
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, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
2,291

 
GWh
Gas
 
220

 
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, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2016
 
2015
 
2016
 
2015
Gain (loss) recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
208

 
$
41

 
$
60

 
$
(286
)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(1,016
)
 
(1,430
)
 
(1,957
)
 
(3,773
)

(a)
During the three and six months ended June 30, 2016 and 2015, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $4 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, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2016
 
2015
 
2016
 
2015
Net gain (loss) recognized in income
 
Operating revenues
 
$
585

 
$
(66
)
 
$
483

 
$
(114
)
Net gain (loss) recognized in income
 
Fuel and purchased power (a)
 
60,894

 
10,613

 
29,958

 
(34,190
)
Total
 
 
 
$
61,479

 
$
10,547

 
$
30,441

 
$
(34,304
)

(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, 2016 and December 31, 2015, include gross liabilities of $2 million and $3 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, 2016 and December 31, 2015.  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, 2016:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
30,393

 
$
(14,424
)
 
$
15,969

 
$
707

 
$
16,676

Investments and other assets
 
14,260

 
(8,796
)
 
5,464

 
—

 
5,464

Total assets
 
44,653

 
(23,220
)
 
21,433

 
707

 
22,140

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(65,432
)
 
14,424

 
(51,008
)
 
(4,330
)
 
(55,338
)
Deferred credits and other
 
(61,008
)
 
8,796

 
(52,212
)
 
—

 
(52,212
)
Total liabilities
 
(126,440
)
 
23,220

 
(103,220
)
 
(4,330
)
 
(107,550
)
Total
 
$
(81,787
)
 
$
—

 
$
(81,787
)
 
$
(3,623
)
 
$
(85,410
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $0.
(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 $4,330, and cash margin provided to counterparties of $707.
 
As of December 31, 2015:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
37,396

 
$
(22,163
)
 
$
15,233

 
$
672

 
$
15,905

Investments and other assets
 
15,960

 
(3,854
)
 
12,106

 
—

 
12,106

Total assets
 
53,356

 
(26,017
)
 
27,339

 
672

 
28,011

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(113,560
)
 
40,223

 
(73,337
)
 
(4,379
)
 
(77,716
)
Deferred credits and other
 
(93,827
)
 
3,854

 
(89,973
)
 
—

 
(89,973
)
Total liabilities
 
(207,387
)
 
44,077

 
(163,310
)
 
(4,379
)
 
(167,689
)
Total
 
$
(154,031
)
 
$
18,060

 
$
(135,971
)
 
$
(3,707
)
 
$
(139,678
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $18,060.
(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 $4,379, and cash margin provided to counterparties of $672.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties.  We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 73% of Pinnacle West’s $22 million of risk management assets as of June 30, 2016.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality.  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, 2016 (dollars in thousands):
 
June 30, 2016
Aggregate fair value of derivative instruments in a net liability position
$
126,440

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
76,949


(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 $145 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 provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016.

APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 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 2016, and payment is expected in the second quarter of 2017.

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 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 $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of $13 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments.  The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $18.9 million per incident, to be periodically adjusted for inflation.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium assessment of approximately $16.6 million.
 
The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination.  APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium assessments 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 $23.8 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 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

There have been no material changes, as of June 30, 2016, outside the normal course of business in contractual obligations from the information provided in our 2015 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.  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. 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.
 
Southwest Power Outage
 
On September 8, 2011 at approximately 3:30 PM, a 500 kilovolt ("kV") transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS.  Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.
 
On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service.  APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.  On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016.
 
Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, 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 requirements on Four Corners and the Navajo Generating Station ("Navajo Plant"). EPA and ADEQ 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 is currently in the process of considering 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.

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these 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. 4C Acquisition, LLC ("4CA"), a wholly-owned subsidiary of Pinnacle West, 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 provided notice of its intent to exercise the option. 4CA is negotiating a definitive purchase agreement with NTEC for the purchase by NTEC of the 7% interest. 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. We cannot predict the outcome of this review process.

Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $100 million (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015), 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 wherein, 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 the Cholla permit, 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.  The proposed rule was published in the Federal Register on July 19, 2016 and is subject to a 45-day public comment period.  APS anticipates that EPA will issue the final rule by the end of 2016. Once EPA’s action is finalized, there may be judicial petitions for review of EPA’s final action filed in the Ninth Circuit Court of Appeals.  APS cannot predict at this time whether such petitions will be filed or if they will be successful.
 
Mercury and Air Toxic Standards ("MATS").  In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants.  APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $8 million for Cholla (excludes costs related to Cholla Unit 2, which was closed on October 1, 2015). No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  Salt River Project Agricultural Improvement and Power District ("SRP"), the operating agent for the Navajo Plant, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. Litigation concerning the rules has occurred and further litigation concerning the propriety of EPA's related findings is expected. These proceedings do not materially impact APS.  Regardless of the results from further judicial or administrative proceedings concerning the MATS rulemaking, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla.
 
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.
Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. 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.
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 $15 million, and its share of incremental costs for Cholla is approximately $40 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires on-going groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions. Because the initial monitoring at these plants is not yet complete, at the present time expenditures related to potential corrective actions cannot be reasonably estimated.
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 existing, new, modified, and reconstructed electric generating units ("EGUs"). EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal.

With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO2 emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below.

Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ reports that it is continuing to assess its options while completing outreach and soliciting feedback from stakeholders. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation.

The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. 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. We cannot predict the extent of such a delay.

With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances.

As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation.

Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material.

Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes.

In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, and additional information or considerations may arise that change our expectations.

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 December 21, 2015, several environmental groups filed a notice of intent to sue with Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies under the Endangered Species Act (“ESA”) alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the United States Department of the Interior's ("DOI's") review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners.  This review process also required separate environmental impact evaluations under the National Environmental Policy Act (“NEPA”) and culminated in the issuance of a Record of Decision justifying the agency action extending the life of the plant and the adjacent mine. 

On April 20, 2016, the same environmental groups followed through with their notice of intent to sue by filing a lawsuit against OSM and other DOI 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.  Expanding upon the December 2015 ESA notice, the lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  We filed a motion to intervene in the proceedings on July 15, 2016. We cannot predict the outcome of this matter or its potential effect on Four Corners.
    
 New Mexico Tax Matter
 
On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment").  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment in the amount of $0.8 million and immediately filed a refund claim with respect to that partial payment in August 2013.  The NMTRD denied the refund claim.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed an appeal of the decision on August 31, 2015.

On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above is approximately $0.8 million.
  
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, 2016, standby letters of credit totaled $79 million and will expire in 2016 and 2017. As of June 30, 2016, surety bonds expiring through 2019 totaled $150 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, 2016. Effective July 6, 2016, Pinnacle West has issued two 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.

Peabody Bankruptcy

On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri.  Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona.  APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement.  

On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleges that the Buyers have breached the Agreement. Peabody requests substantial, but unspecified, monetary damages from the Buyers.  Peabody and the Buyers have agreed to commence non-binding mediation, failing which a trial is expected to occur in November 2016.  There is insufficient information at this time to reasonably estimate any possible loss or range of loss to the Company.
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, 2016 and 2015 (dollars in thousands):

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Other income:
 

 
 

 
 

 
 

Interest income
$
184

 
$
184

 
$
302

 
$
294

Investment gains — net
13

 
—

 
13

 
—

Miscellaneous
—

 
(9
)
 
(1
)
 
116

Total other income
$
197

 
$
175

 
$
314

 
$
410

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(2,085
)
 
$
(1,952
)
 
$
(4,133
)
 
$
(4,200
)
Investment losses — net
(539
)
 
(650
)
 
(1,058
)
 
(1,145
)
Miscellaneous
(218
)
 
(7
)
 
(1,689
)
 
(1,550
)
Total other expense
$
(2,842
)
 
$
(2,609
)
 
$
(6,880
)
 
$
(6,895
)
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, 2016 and 2015 (dollars in thousands):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Other income:
 

 
 

 
 

 
 

Interest income
$
109

 
$
6

 
$
181

 
$
73

Gain on disposition of property
4,989

 
478

 
5,321

 
685

Miscellaneous
649

 
226

 
855

 
591

Total other income
$
5,747

 
$
710

 
$
6,357

 
$
1,349

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(2,719
)
 
$
(1,878
)
 
$
(4,685
)
 
$
(4,395
)
Loss on disposition of property
(657
)
 
(251
)
 
(1,083
)
 
(894
)
Miscellaneous
(1,054
)
 
(320
)
 
(3,412
)
 
(2,514
)
Total other expense
$
(4,430
)
 
$
(2,449
)
 
$
(9,180
)
 
$
(7,803
)

(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, 2016 and 2015 (in thousands, except per share amounts):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Net income attributable to common shareholders
$
121,308

 
$
122,902

 
$
125,761

 
$
139,024

Weighted average common shares outstanding — basic
111,368

 
110,986

 
111,336

 
110,958

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
636

 
474

 
594

 
468

Weighted average common shares outstanding — diluted
112,004

 
111,460

 
111,930

 
111,426

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.09

 
$
1.11

 
$
1.13

 
$
1.25

Net income attributable to common shareholders — diluted
$
1.08

 
$
1.10

 
$
1.12

 
$
1.25

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. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires instruments valued using NAV, as a practical expedient, to no longer be classified within the fair value hierarchy. As such, instruments valued using NAV, as a practical expedient, are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 7 in the 2015 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.

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 and the use of option valuation models with significant unobservable inputs.
 
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, 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
June 30,
2016
Assets
 

 
 

 
 

 
 

 
 
 
 

Cash equivalents
$
9,857

 
$
—

 
$
—

 
$
—

 
 
 
$
9,857

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
26,509

 
18,118

 
(22,487
)
 
(b)
 
22,140

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
328,037

 
(c)
 
328,037

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
17,892

 
—

 
—

 
(13,139
)
 
(d)
 
4,753

U.S. Treasury
117,448

 
—

 
—

 
—

 
 
 
117,448

Corporate debt
—

 
106,399

 
—

 
—

 
 
 
106,399

Mortgage-backed securities
—

 
112,771

 
—

 
—

 
 
 
112,771

Municipal bonds
—

 
73,847

 
—

 
—

 
 
 
73,847

Other
—

 
24,161

 
—

 
—

 
 
 
24,161

Subtotal nuclear decommissioning trust
135,340

 
317,178

 
—

 
314,898

 
 
 
767,416

Total
$
145,197

 
$
343,687

 
$
18,118

 
$
292,411

 
 
 
$
799,413

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(75,916
)
 
$
(50,498
)
 
$
18,864

 
(b)
 
$
(107,550
)

(a)
Primarily consists of heat rate options and other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral. See Note 6.
(c)
Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.
(d)
Represents nuclear decommissioning trust net pending securities sales and purchases.


The following table presents the fair value at December 31, 2015, 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,
2015
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
22,992

 
$
30,364

 
$
(25,345
)
 
(b)
 
$
28,011

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
314,957

 
(c)
 
314,957

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
12,260

 
—

 
—

 
(335
)
 
(d)
 
11,925

U.S. Treasury
117,245

 
—

 
—

 
—

 
 
 
117,245

Corporate debt
—

 
96,243

 
—

 
—

 
 
 
96,243

Mortgage-backed securities
—

 
99,065

 
—

 
—

 
 
 
99,065

Municipal bonds
—

 
72,206

 
—

 
—

 
 
 
72,206

Other
—

 
23,555

 
—

 
—

 
 
 
23,555

Subtotal nuclear decommissioning trust
129,505

 
291,069

 
—

 
314,622

 
 
 
735,196

Total
$
129,505

 
$
314,061

 
$
30,364

 
$
289,277

 
 
 
$
763,207

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(144,044
)
 
$
(63,343
)
 
$
39,698

 
(b)
 
$
(167,689
)

(a)
Primarily consists of heat rate options and other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral. See Note 6.
(c)
Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.
(d)
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 and option model inputs.  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.
 
Our option contracts classified as Level 3 primarily relate to purchase heat rate options.  The significant unobservable inputs at June 30, 2016 and December 31, 2015 for these instruments include electricity prices, and volatilities. If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease.  If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase.  The commodity prices and volatilities do not always move in corresponding directions.  The options’ fair values are impacted by the net changes of these various inputs.
 
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, 2016 and December 31, 2015:
 
 
June 30, 2016
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
16,151

 
$
39,548

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$21.68 - $43.50
 
$
31.26

Option Contracts (b)
—

 
2,993

 
Option model
 
Electricity forward price (per MWh)
 
$35.46 - $49.65
 
$
43.12

 
 

 
 

 
 
 
Electricity price volatilities
 
56% - 140%
 
94
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
38% - 80%
 
49
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
1,967

 
7,957

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.67 - $3.37
 
$
2.91

Total
$
18,118

 
$
50,498

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
 
December 31, 2015
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
24,543

 
$
54,679

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$15.92 - $40.73
 
$
26.86

Option Contracts (b)
—

 
5,628

 
Option model
 
Electricity forward price (per MWh)
 
$23.87 - $44.13
 
$
33.91

 
 

 
 

 
 
 
Electricity price volatilities
 
40% - 59%
 
52
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
32% - 40%
 
35
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
5,821

 
3,036

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.18 - $3.14
 
$
2.61

Total
$
30,364

 
$
63,343

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
 
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, 2016 and 2015 (dollars in thousands):
 
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
2016
 
2015
 
2016
 
2015
Net derivative balance at beginning of period
 
$
(39,507
)
 
$
(48,814
)
 
$
(32,979
)
 
$
(41,386
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 

 
 

Included in OCI
 
104

 
25

 
104

 
(237
)
Deferred as a regulatory asset or liability
 
1,499

 
5,813

 
(7,604
)
 
(4,933
)
Settlements
 
4,502

 
4,541

 
6,267

 
4,852

Transfers into Level 3 from Level 2
 
120

 
(3,566
)
 
382

 
(3,968
)
Transfers from Level 3 into Level 2
 
902

 
(944
)
 
1,450

 
2,727

Net derivative balance at end of period
 
$
(32,380
)
 
$
(42,945
)
 
$
(32,380
)
 
$
(42,945
)
 
 
 
 
 
 
 
 
 
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, 2016 and December 31, 2015 (dollars in thousands):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
June 30, 2016
 

 
 

 
 

Equity securities
$
328,037

 
$
165,926

 
$
(7
)
Fixed income securities
452,518

 
22,953

 
(345
)
Net payables (a)
(13,139
)
 
—

 
—

Total
$
767,416

 
$
188,879

 
$
(352
)

 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
December 31, 2015
 

 
 

 
 

Equity securities
$
314,957

 
$
157,098

 
$
(115
)
Fixed income securities
420,574

 
11,955

 
(2,645
)
Net payables (a)
(335
)
 
—

 
—

Total
$
735,196

 
$
169,053

 
$
(2,760
)
(a)
Net 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,
 
2016
 
2015
 
2016
 
2015
Realized gains
$
2,282

 
$
1,260

 
$
4,720

 
$
2,455

Realized losses
(1,350
)
 
(1,525
)
 
(3,136
)
 
(2,050
)
Proceeds from the sale of securities (a)
148,785

 
110,498

 
290,594

 
225,779

(a)
Proceeds are reinvested in the trust.
 
The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2016 is as follows (dollars in thousands):
 
Fair Value
Less than one year
$
13,046

1 year – 5 years
133,548

5 years – 10 years
103,874

Greater than 10 years
202,050

Total
$
452,518

New Accounting Standards
New Accounting Standards
New Accounting Standards

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 has been 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 guidance 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 are currently evaluating the new standard, and related amendments, and the impacts it may have on our financial statements.

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 guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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 guidance 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 guidance must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In March 2016, new stock compensation accounting guidance was issued that modifies the accounting for employee share-based payments. The new guidance will require all tax benefits and deficiencies arising from share-based payments to be recognized in net income, modifies the tax withholding threshold for awards to qualify for equity classification, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. The new guidance is effective for us on January 1, 2017, with early application permitted. Certain aspects of the guidance must be adopted using a prospective approach and other aspects will be adopted using a retrospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In June 2016, new accounting guidance was issued that amends the measurement of credit losses on certain financial instruments. The new guidance 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.
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, 2016 and 2015 (dollars in thousands):
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2016
 
2015
 
2016
 
2015
Balance at beginning of period
$
(43,770
)
 
$
(66,382
)
 
$
(44,748
)
 
$
(68,141
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
128

  
25

 
(566
)
 
(775
)
Amounts reclassified from accumulated other comprehensive loss (a)
624

 
874

 
1,766

 
2,850

Net current period OCI (loss)
752

 
899

  
1,200

  
2,075

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
(1,585
)
 
(969
)
 
(1,585
)
 
(969
)
Amounts reclassified from accumulated other comprehensive loss (b)
884

 
852

 
1,414

 
1,435

Net current period OCI (loss)
(701
)
 
(117
)
 
(171
)
 
466

Balance at end of period
$
(43,719
)
 
$
(65,600
)
 
$
(43,719
)
 
$
(65,600
)

(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, 2016 and 2015 (dollars in thousands):
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2016
 
2015
 
2016
 
2015
Balance at beginning of period
$
(26,038
)
 
$
(46,476
)
 
$
(27,097
)
 
$
(48,333
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
128

  
25

 
(566
)
 
(775
)
Amounts reclassified from accumulated other comprehensive loss (a)
624

 
874

 
1,766

 
2,850

Net current period OCI (loss)
752

 
899

  
1,200

  
2,075

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
(1,521
)
 
(927
)
 
(1,521
)
 
(927
)
Amounts reclassified from accumulated other comprehensive loss (b)
879

 
853

 
1,490

 
1,534

Net current period OCI (loss)
(642
)
 
(74
)
 
(31
)
 
607

Balance at end of period
$
(25,928
)
 
$
(45,651
)
 
$
(25,928
)
 
$
(45,651
)

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

In 2016, APS recognized an asset retirement obligation (“ARO”) for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million.

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2016 (dollars in thousands): 
Asset retirement obligations at January 1, 2016
$
443,576

Changes attributable to:
 

Accretion expense
13,112

Settlements
(5,224
)
Newly incurred liabilities
10,373

Asset retirement obligations at June 30, 2016
$
461,837


 
Decommissioning activities for Four Corners Units 1-3 began in January 2014. Decommissioning activities for Cholla Ash Ponds began in January 2015. Thus, $16 million of the total asset retirement obligation of $462 million at June 30, 2016, is classified as a current liability on the balance sheet.

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note
New Accounting Standards (Policies)
New Accounting Standards
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 has been 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 guidance 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 are currently evaluating the new standard, and related amendments, and the impacts it may have on our financial statements.

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 guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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 guidance 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 guidance must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In March 2016, new stock compensation accounting guidance was issued that modifies the accounting for employee share-based payments. The new guidance will require all tax benefits and deficiencies arising from share-based payments to be recognized in net income, modifies the tax withholding threshold for awards to qualify for equity classification, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. The new guidance is effective for us on January 1, 2017, with early application permitted. Certain aspects of the guidance must be adopted using a prospective approach and other aspects will be adopted using a retrospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In June 2016, new accounting guidance was issued that amends the measurement of credit losses on certain financial instruments. The new guidance 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.

Consolidation and Nature of Operations (Tables)
Summary of supplemental cash flow information
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2016
 
2015
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,503

 
$
1,834

Interest, net of amounts capitalized
89,109

 
84,008

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
55,286

 
$
38,985

Dividends accrued but not yet paid
69,484

 
65,933

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, 2016
 
As of December 31, 2015
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,066,415

 
4,658,591

 
3,694,971

 
3,981,367

Total
$
4,191,415

 
$
4,783,591

 
$
3,819,971

 
$
4,106,367

Regulatory Matters (Tables)
Proposed capital structure and cost of capital 
the following proposed capital structure and costs of capital:
 
 
 
Capital Structure
 
Cost of Capital
 
Long-term debt
 
44.2
%
5.13
%
Common stock equity
 
55.8
%
10.50
%
Weighted-average cost of capital
 
 
 
8.13
%
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 2016 and 2015 (dollars in thousands):
 
 
Six Months Ended 
 June 30,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,925

Deferred fuel and purchased power costs — current period
21,027

 
(11,710
)
Amounts charged to customers
(13,778
)
 
(11,424
)
Ending balance
$
(2,439
)
 
$
(16,209
)
Schedule of regulatory assets 
The detail of regulatory assets is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
617,283

 
$
—

 
$
619,223

Retired power plant costs
2033
 
9,913

 
122,554

 
9,913

 
127,518

Income taxes — allowance for funds used during construction ("AFUDC") equity
2046
 
5,419

 
137,611

 
5,495

 
133,712

Deferred fuel and purchased power — mark-to-market (Note 6)
2019
 
30,986

 
40,573

 
71,852

 
69,697

Four Corners cost deferral
2024
 
6,689

 
60,238

 
6,689

 
63,582

Income taxes — investment tax credit basis adjustment
2045
 
1,851

 
47,826

 
1,766

 
48,462

Lost fixed cost recovery (b)
2017
 
49,852

 
—

 
45,507

 
—

Palo Verde VIEs (Note 5)
2046
 
—

 
18,465

 
—

 
18,143

Deferred compensation
2036
 
—

 
35,701

 
—

 
34,751

Deferred property taxes
(c)
 
—

 
62,726

 
—

 
50,453

Loss on reacquired debt
2034
 
1,592

 
16,919

 
1,515

 
16,375

Tax expense of Medicare subsidy
2024
 
1,512

 
11,647

 
1,520

 
12,163

Transmission vegetation management
2016
 
—

 
—

 
4,543

 
—

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,874

 
332

 
11,040

Transmission cost adjustor (b)
2018
 
—

 
2,814

 
—

 
2,942

Coal reclamation
2026
 
418

 
5,391

 
418

 
6,085

Other
Various
 
32

 
—

 
5

 
—

Total regulatory assets (d)
 
 
$
108,596

 
$
1,190,622

 
$
149,555

 
$
1,214,146


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues.  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."
Schedule of regulatory liabilities 
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$
—

 
$
299,713

 
$
—

 
$
277,554

Removal costs
(a)
 
26,373

 
245,777

 
39,746

 
240,367

Other postretirement benefits
(d)
 
33,294

 
155,279

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2045
 
3,774

 
95,877

 
3,604

 
97,175

Income taxes — change in rates
2046
 
1,771

 
71,257

 
1,113

 
72,454

Spent nuclear fuel
2047
 
31

 
71,342

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
35,882

 
2,182

 
43,773

 
4,365

Demand side management (b)
2017
 
4,957

 
21,864

 
6,079

 
19,115

Sundance maintenance
2030
 
—

 
14,483

 
—

 
13,678

Deferred fuel and purchased power (b) (c)
2017
 
2,439

 
—

 
9,688

 
—

Deferred gains on utility property
2019
 
2,062

 
9,535

 
2,062

 
6,001

Transmission cost adjustor (b)
2017
 
5,545

 
—

 
—

 
—

Four Corners coal reclamation
2031
 
—

 
15,969

 
—

 
8,920

Other
Various
 
44

 
7,543

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
116,172

 
$
1,010,821

 
$
145,766

 
$
994,152


(a)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Subject to a carrying charge.
(d)
See Note 4.
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 or amortized to the regulatory asset) (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,
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
Service cost — benefits earned during the period
$
12,630

 
$
13,990

 
$
26,896

 
$
29,814

 
$
3,560

 
$
4,068

 
$
7,497

 
$
8,413

Interest cost on benefit obligation
32,878

 
30,802

 
65,823

 
61,992

 
7,519

 
6,867

 
14,860

 
14,051

Expected return on plan assets
(43,161
)
 
(44,467
)
 
(86,953
)
 
(89,616
)
 
(9,125
)
 
(9,281
)
 
(18,247
)
 
(18,428
)
Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost
132

 
149

 
263

 
297

 
(9,471
)
 
(9,492
)
 
(18,942
)
 
(18,984
)
Net actuarial loss
10,627

 
7,767

 
20,358

 
15,528

 
1,349

 
880

 
2,295

 
2,441

Net periodic benefit cost
$
13,106

 
$
8,241

 
$
26,387

 
$
18,015

 
$
(6,168
)
 
$
(6,958
)
 
$
(12,537
)
 
$
(12,507
)
Portion of cost charged to expense
$
6,433

 
$
5,232

 
$
12,951

 
$
11,219

 
$
(3,027
)
 
$
(2,482
)
 
$
(6,153
)
 
$
(4,271
)
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, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):
 
 
June 30,
2016
 
December 31,
2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
115,450

 
$
117,385

Equity — Noncontrolling interests
133,915

 
135,540

Derivative Accounting (Tables)
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) 
As of June 30, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
2,291

 
GWh
Gas
 
220

 
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, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2016
 
2015
 
2016
 
2015
Gain (loss) recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
208

 
$
41

 
$
60

 
$
(286
)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(1,016
)
 
(1,430
)
 
(1,957
)
 
(3,773
)

(a)
During the three and six months ended June 30, 2016 and 2015, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments 
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2016
 
2015
 
2016
 
2015
Net gain (loss) recognized in income
 
Operating revenues
 
$
585

 
$
(66
)
 
$
483

 
$
(114
)
Net gain (loss) recognized in income
 
Fuel and purchased power (a)
 
60,894

 
10,613

 
29,958

 
(34,190
)
Total
 
 
 
$
61,479

 
$
10,547

 
$
30,441

 
$
(34,304
)

(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, 2016 and December 31, 2015.  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, 2016:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
30,393

 
$
(14,424
)
 
$
15,969

 
$
707

 
$
16,676

Investments and other assets
 
14,260

 
(8,796
)
 
5,464

 
—

 
5,464

Total assets
 
44,653

 
(23,220
)
 
21,433

 
707

 
22,140

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(65,432
)
 
14,424

 
(51,008
)
 
(4,330
)
 
(55,338
)
Deferred credits and other
 
(61,008
)
 
8,796

 
(52,212
)
 
—

 
(52,212
)
Total liabilities
 
(126,440
)
 
23,220

 
(103,220
)
 
(4,330
)
 
(107,550
)
Total
 
$
(81,787
)
 
$
—

 
$
(81,787
)
 
$
(3,623
)
 
$
(85,410
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $0.
(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 $4,330, and cash margin provided to counterparties of $707.
 
As of December 31, 2015:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
37,396

 
$
(22,163
)
 
$
15,233

 
$
672

 
$
15,905

Investments and other assets
 
15,960

 
(3,854
)
 
12,106

 
—

 
12,106

Total assets
 
53,356

 
(26,017
)
 
27,339

 
672

 
28,011

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(113,560
)
 
40,223

 
(73,337
)
 
(4,379
)
 
(77,716
)
Deferred credits and other
 
(93,827
)
 
3,854

 
(89,973
)
 
—

 
(89,973
)
Total liabilities
 
(207,387
)
 
44,077

 
(163,310
)
 
(4,379
)
 
(167,689
)
Total
 
$
(154,031
)
 
$
18,060

 
$
(135,971
)
 
$
(3,707
)
 
$
(139,678
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $18,060.
(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 $4,379, and cash margin provided to counterparties of $672.

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, 2016 and December 31, 2015.  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, 2016:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
30,393

 
$
(14,424
)
 
$
15,969

 
$
707

 
$
16,676

Investments and other assets
 
14,260

 
(8,796
)
 
5,464

 
—

 
5,464

Total assets
 
44,653

 
(23,220
)
 
21,433

 
707

 
22,140

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(65,432
)
 
14,424

 
(51,008
)
 
(4,330
)
 
(55,338
)
Deferred credits and other
 
(61,008
)
 
8,796

 
(52,212
)
 
—

 
(52,212
)
Total liabilities
 
(126,440
)
 
23,220

 
(103,220
)
 
(4,330
)
 
(107,550
)
Total
 
$
(81,787
)
 
$
—

 
$
(81,787
)
 
$
(3,623
)
 
$
(85,410
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $0.
(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 $4,330, and cash margin provided to counterparties of $707.
 
As of December 31, 2015:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
37,396

 
$
(22,163
)
 
$
15,233

 
$
672

 
$
15,905

Investments and other assets
 
15,960

 
(3,854
)
 
12,106

 
—

 
12,106

Total assets
 
53,356

 
(26,017
)
 
27,339

 
672

 
28,011

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(113,560
)
 
40,223

 
(73,337
)
 
(4,379
)
 
(77,716
)
Deferred credits and other
 
(93,827
)
 
3,854

 
(89,973
)
 
—

 
(89,973
)
Total liabilities
 
(207,387
)
 
44,077

 
(163,310
)
 
(4,379
)
 
(167,689
)
Total
 
$
(154,031
)
 
$
18,060

 
$
(135,971
)
 
$
(3,707
)
 
$
(139,678
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $18,060.
(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 $4,379, and cash margin provided to counterparties of $672.
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, 2016 (dollars in thousands):
 
June 30, 2016
Aggregate fair value of derivative instruments in a net liability position
$
126,440

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
76,949


(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, 2016 and 2015 (dollars in thousands):

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Other income:
 

 
 

 
 

 
 

Interest income
$
184

 
$
184

 
$
302

 
$
294

Investment gains — net
13

 
—

 
13

 
—

Miscellaneous
—

 
(9
)
 
(1
)
 
116

Total other income
$
197

 
$
175

 
$
314

 
$
410

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(2,085
)
 
$
(1,952
)
 
$
(4,133
)
 
$
(4,200
)
Investment losses — net
(539
)
 
(650
)
 
(1,058
)
 
(1,145
)
Miscellaneous
(218
)
 
(7
)
 
(1,689
)
 
(1,550
)
Total other expense
$
(2,842
)
 
$
(2,609
)
 
$
(6,880
)
 
$
(6,895
)
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, 2016 and 2015 (dollars in thousands):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Other income:
 

 
 

 
 

 
 

Interest income
$
109

 
$
6

 
$
181

 
$
73

Gain on disposition of property
4,989

 
478

 
5,321

 
685

Miscellaneous
649

 
226

 
855

 
591

Total other income
$
5,747

 
$
710

 
$
6,357

 
$
1,349

Other expense:
 

 
 

 
 

 
 

Non-operating costs (a)
$
(2,719
)
 
$
(1,878
)
 
$
(4,685
)
 
$
(4,395
)
Loss on disposition of property
(657
)
 
(251
)
 
(1,083
)
 
(894
)
Miscellaneous
(1,054
)
 
(320
)
 
(3,412
)
 
(2,514
)
Total other expense
$
(4,430
)
 
$
(2,449
)
 
$
(9,180
)
 
$
(7,803
)

(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, 2016 and 2015 (in thousands, except per share amounts):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Net income attributable to common shareholders
$
121,308

 
$
122,902

 
$
125,761

 
$
139,024

Weighted average common shares outstanding — basic
111,368

 
110,986

 
111,336

 
110,958

Net effect of dilutive securities:
 

 
 

 
 

 
 

Contingently issuable performance shares and restricted stock units
636

 
474

 
594

 
468

Weighted average common shares outstanding — diluted
112,004

 
111,460

 
111,930

 
111,426

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.09

 
$
1.11

 
$
1.13

 
$
1.25

Net income attributable to common shareholders — diluted
$
1.08

 
$
1.10

 
$
1.12

 
$
1.25

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, 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
June 30,
2016
Assets
 

 
 

 
 

 
 

 
 
 
 

Cash equivalents
$
9,857

 
$
—

 
$
—

 
$
—

 
 
 
$
9,857

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
—

 
26,509

 
18,118

 
(22,487
)
 
(b)
 
22,140

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
328,037

 
(c)
 
328,037

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
17,892

 
—

 
—

 
(13,139
)
 
(d)
 
4,753

U.S. Treasury
117,448

 
—

 
—

 
—

 
 
 
117,448

Corporate debt
—

 
106,399

 
—

 
—

 
 
 
106,399

Mortgage-backed securities
—

 
112,771

 
—

 
—

 
 
 
112,771

Municipal bonds
—

 
73,847

 
—

 
—

 
 
 
73,847

Other
—

 
24,161

 
—

 
—

 
 
 
24,161

Subtotal nuclear decommissioning trust
135,340

 
317,178

 
—

 
314,898

 
 
 
767,416

Total
$
145,197

 
$
343,687

 
$
18,118

 
$
292,411

 
 
 
$
799,413

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(75,916
)
 
$
(50,498
)
 
$
18,864

 
(b)
 
$
(107,550
)

(a)
Primarily consists of heat rate options and other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral. See Note 6.
(c)
Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.
(d)
Represents nuclear decommissioning trust net pending securities sales and purchases.


The following table presents the fair value at December 31, 2015, 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,
2015
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
22,992

 
$
30,364

 
$
(25,345
)
 
(b)
 
$
28,011

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds
—

 
—

 
—

 
314,957

 
(c)
 
314,957

Fixed income securities:
 

 
 

 
 

 
 

 
 
 
 

Cash and cash equivalent funds
12,260

 
—

 
—

 
(335
)
 
(d)
 
11,925

U.S. Treasury
117,245

 
—

 
—

 
—

 
 
 
117,245

Corporate debt
—

 
96,243

 
—

 
—

 
 
 
96,243

Mortgage-backed securities
—

 
99,065

 
—

 
—

 
 
 
99,065

Municipal bonds
—

 
72,206

 
—

 
—

 
 
 
72,206

Other
—

 
23,555

 
—

 
—

 
 
 
23,555

Subtotal nuclear decommissioning trust
129,505

 
291,069

 
—

 
314,622

 
 
 
735,196

Total
$
129,505

 
$
314,061

 
$
30,364

 
$
289,277

 
 
 
$
763,207

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(144,044
)
 
$
(63,343
)
 
$
39,698

 
(b)
 
$
(167,689
)

(a)
Primarily consists of heat rate options and other long-dated electricity contracts.
(b)
Represents counterparty netting, margin and collateral. See Note 6.
(c)
Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.
(d)
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, 2016 and December 31, 2015:
 
 
June 30, 2016
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
16,151

 
$
39,548

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$21.68 - $43.50
 
$
31.26

Option Contracts (b)
—

 
2,993

 
Option model
 
Electricity forward price (per MWh)
 
$35.46 - $49.65
 
$
43.12

 
 

 
 

 
 
 
Electricity price volatilities
 
56% - 140%
 
94
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
38% - 80%
 
49
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
1,967

 
7,957

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.67 - $3.37
 
$
2.91

Total
$
18,118

 
$
50,498

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
 
December 31, 2015
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
24,543

 
$
54,679

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$15.92 - $40.73
 
$
26.86

Option Contracts (b)
—

 
5,628

 
Option model
 
Electricity forward price (per MWh)
 
$23.87 - $44.13
 
$
33.91

 
 

 
 

 
 
 
Electricity price volatilities
 
40% - 59%
 
52
%
 
 

 
 

 
 
 
Natural gas price volatilities
 
32% - 40%
 
35
%
Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
5,821

 
3,036

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$2.18 - $3.14
 
$
2.61

Total
$
30,364

 
$
63,343

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
(b)
Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities
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, 2016 and 2015 (dollars in thousands):
 
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
2016
 
2015
 
2016
 
2015
Net derivative balance at beginning of period
 
$
(39,507
)
 
$
(48,814
)
 
$
(32,979
)
 
$
(41,386
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 

 
 

Included in OCI
 
104

 
25

 
104

 
(237
)
Deferred as a regulatory asset or liability
 
1,499

 
5,813

 
(7,604
)
 
(4,933
)
Settlements
 
4,502

 
4,541

 
6,267

 
4,852

Transfers into Level 3 from Level 2
 
120

 
(3,566
)
 
382

 
(3,968
)
Transfers from Level 3 into Level 2
 
902

 
(944
)
 
1,450

 
2,727

Net derivative balance at end of period
 
$
(32,380
)
 
$
(42,945
)
 
$
(32,380
)
 
$
(42,945
)
 
 
 
 
 
 
 
 
 
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, 2016 and December 31, 2015 (dollars in thousands):
 
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
June 30, 2016
 

 
 

 
 

Equity securities
$
328,037

 
$
165,926

 
$
(7
)
Fixed income securities
452,518

 
22,953

 
(345
)
Net payables (a)
(13,139
)
 
—

 
—

Total
$
767,416

 
$
188,879

 
$
(352
)

 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
December 31, 2015
 

 
 

 
 

Equity securities
$
314,957

 
$
157,098

 
$
(115
)
Fixed income securities
420,574

 
11,955

 
(2,645
)
Net payables (a)
(335
)
 
—

 
—

Total
$
735,196

 
$
169,053

 
$
(2,760
)
(a)
Net 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,
 
2016
 
2015
 
2016
 
2015
Realized gains
$
2,282

 
$
1,260

 
$
4,720

 
$
2,455

Realized losses
(1,350
)
 
(1,525
)
 
(3,136
)
 
(2,050
)
Proceeds from the sale of securities (a)
148,785

 
110,498

 
290,594

 
225,779

(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, 2016 is as follows (dollars in thousands):
 
Fair Value
Less than one year
$
13,046

1 year – 5 years
133,548

5 years – 10 years
103,874

Greater than 10 years
202,050

Total
$
452,518

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, 2016 and 2015 (dollars in thousands):
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2016
 
2015
 
2016
 
2015
Balance at beginning of period
$
(43,770
)
 
$
(66,382
)
 
$
(44,748
)
 
$
(68,141
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
128

  
25

 
(566
)
 
(775
)
Amounts reclassified from accumulated other comprehensive loss (a)
624

 
874

 
1,766

 
2,850

Net current period OCI (loss)
752

 
899

  
1,200

  
2,075

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
(1,585
)
 
(969
)
 
(1,585
)
 
(969
)
Amounts reclassified from accumulated other comprehensive loss (b)
884

 
852

 
1,414

 
1,435

Net current period OCI (loss)
(701
)
 
(117
)
 
(171
)
 
466

Balance at end of period
$
(43,719
)
 
$
(65,600
)
 
$
(43,719
)
 
$
(65,600
)

(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, 2016 and 2015 (dollars in thousands):
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2016
 
2015
 
2016
 
2015
Balance at beginning of period
$
(26,038
)
 
$
(46,476
)
 
$
(27,097
)
 
$
(48,333
)
Derivative Instruments
 
 
 
 
 
 
 
OCI (loss) before reclassifications
128

  
25

 
(566
)
 
(775
)
Amounts reclassified from accumulated other comprehensive loss (a)
624

 
874

 
1,766

 
2,850

Net current period OCI (loss)
752

 
899

  
1,200

  
2,075

Pension and Other Postretirement Benefits
 
 
 
 
 
 
 
OCI (loss) before reclassifications
(1,521
)
 
(927
)
 
(1,521
)
 
(927
)
Amounts reclassified from accumulated other comprehensive loss (b)
879

 
853

 
1,490

 
1,534

Net current period OCI (loss)
(642
)
 
(74
)
 
(31
)
 
607

Balance at end of period
$
(25,928
)
 
$
(45,651
)
 
$
(25,928
)
 
$
(45,651
)

(a)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 6.
(b)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 4.
Asset Retirement Obligations (Tables)
Change in asset retirement obligations
The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2016 (dollars in thousands): 
Asset retirement obligations at January 1, 2016
$
443,576

Changes attributable to:
 

Accretion expense
13,112

Settlements
(5,224
)
Newly incurred liabilities
10,373

Asset retirement obligations at June 30, 2016
$
461,837

Consolidation and Nature of Operations (Details) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Cash paid during the period for:
 
 
Income taxes, net of refunds
$ 2,503 
$ 1,834 
Interest, net of amounts capitalized
89,109 
84,008 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
55,286 
38,985 
Dividends accrued but not yet paid
$ 69,484 
$ 65,933 
Long-Term Debt and Liquidity Matters - Narrative (Details) (USD $)
0 Months Ended
Jun. 30, 2016
Dec. 31, 2015
May 12, 2016
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing in May 2019
Jun. 30, 2016
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing May 2021
May 13, 2016
Pinnacle West
Revolving Credit Facility
Revolving credit facility maturing May 2021
Jun. 30, 2016
Pinnacle West
Letter of Credit
Revolving credit facility maturing May 2021
Jun. 30, 2016
Pinnacle West
Commercial paper
Revolving credit facility maturing May 2021
Jun. 30, 2016
APS
Dec. 31, 2015
APS
Jun. 30, 2016
APS
ACC
Jun. 30, 2016
APS
ACC
Minimum
Jun. 1, 2016
APS
Arizona pollution control corporation revenue refunding bonds, 2009 series A
May 12, 2016
APS
Revolving Credit Facility
Revolving credit facility maturing in May 2019
Jun. 30, 2016
APS
Revolving Credit Facility
Revolving Credit Facilities Maturing in 2020 and 2021
Facility
Jun. 30, 2016
APS
Revolving Credit Facility
Revolving credit facility maturing May 2021
May 13, 2016
APS
Revolving Credit Facility
Revolving credit facility maturing May 2021
Jun. 30, 2016
APS
Revolving Credit Facility
Revolving credit facility maturing September 2020
Jun. 30, 2016
APS
Commercial paper
Mar. 31, 2016
APS
Commercial paper
Dec. 31, 2015
APS
Commercial paper
Jun. 30, 2016
APS
Commercial paper
Revolving Credit Facilities Maturing in 2020 and 2021
Apr. 22, 2016
APS
Secured debt
Term loan facility maturing April 22, 2019
May 6, 2016
Senior Notes
APS
Unsecured senior notes 3.75 percent mature on 15 May, 2046
Jun. 1, 2016
Current Maturities of Long-term Debt
APS
Arizona pollution control corporation revenue refunding bonds, 2009 series D and E
Aug. 1, 2016
Subsequent Event
Senior Notes
APS
Unsecured Senior Notes 6.25 Percent Mature on 01 August, 2016 [Member]
Aug. 1, 2016
Subsequent Event
Senior Notes
APS
Unsecured Senior Notes 6.25 Percent Mature on 01 August, 2016 [Member]
Long-Term Debt and Liquidity Matters
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current borrowing capacity on credit facility
 
 
$ 200,000,000 
 
$ 200,000,000 
 
 
 
 
 
 
 
$ 500,000,000 
$ 1,000,000,000 
$ 500,000,000 
$ 500,000,000 
$ 500,000,000 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)
 
 
 
300,000,000 
 
 
 
 
 
 
 
 
 
1,400,000,000 
700,000,000 
 
700,000,000 
 
 
 
 
 
 
 
 
 
Outstanding borrowings
 
 
 
0 
 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial paper
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
64,140,000 
 
 
 
 
 
Maximum commercial paper support available under credit facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000,000 
500,000,000 
250,000,000 
 
 
 
 
 
 
Debt issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
350,000,000 
 
 
 
Debt instrument, stated interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.75% 
 
 
6.25% 
Debt Instrument, repurchased face amount
 
 
 
 
 
 
 
 
 
 
 
12,850,000 
 
 
 
 
 
 
 
 
 
 
 
64,000,000 
 
 
Repayments of debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250,000,000 
 
Number of line of credit facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Provisions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Required common equity ratio ordered by ACC (as a percent) (at least)
 
 
 
 
 
 
 
 
 
 
40.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total shareholder equity
4,585,268,000 
4,583,917,000 
 
 
 
 
 
4,675,864,000 
4,679,254,000 
4,700,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total capitalization
 
 
 
 
 
 
 
 
 
8,900,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend restrictions, shareholder equity required
 
 
 
 
 
 
 
 
 
$ 3,600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Estimated fair value of long-term debt, including current maturities
 
 
Carrying Amount
$ 4,191,415 
$ 3,819,971 
Fair Value
4,783,591 
4,106,367 
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
4,066,415 
3,694,971 
Fair Value
$ 4,658,591 
$ 3,981,367 
Regulatory Matters - Retail Rate Case Filing (Details) (Retail Rate Case Filing with Arizona Corporation Commission, ACC, APS, USD $)
0 Months Ended
Jun. 1, 2016
kWh
Dec. 31, 2015
Jun. 1, 2011
Public Utilities, General Disclosures [Line Items]
 
 
 
Net retail rate increase
$ 165,900,000 
 
$ 95,500,000 
Adjustor account balance transferred into base rates, amount
 
267,600,000 
 
Approximate percentage of increase in average customer bill
5.74% 
 
 
Approximate percentage of increase in average residential customer bill
7.96% 
 
 
Original cost rate base
6,800,000,000 
 
 
Required return on incremental fair value rate base above original cost rate base
1.00% 
 
 
Base rate for fuel and purchased power costs (in dollars per kWh)
0.029882 
 
 
Decrease in base rate for fuel and purchased power costs (in dollars per kWh)
0.03207 
 
 
Plan option, non-partial requirements customers, maximum average monthly energy usage (in kWh)
600 
 
 
Public utilities, case completion term
12 months 
 
 
Approximate percentage of increase in the average retail customer bill
 
 
6.60% 
Proposed Capital Structure and Costs of Capital
 
 
 
Requested debt capital structure (as a percent)
44.20% 
 
 
Requested debt cost of capital (as a percent)
5.13% 
 
 
Requested equity capital structure (as a percent)
55.80% 
 
 
Requested equity cost of capital (as a percent)
10.50% 
 
 
Requested weighted-average cost of capital (as a percent)
8.13% 
 
 
Four Corners Power Plant
 
 
 
Public Utilities, General Disclosures [Line Items]
 
 
 
Authorization to defer for potential future recovery of construction costs
400,000,000 
 
 
Ocotillo Plant
 
 
 
Public Utilities, General Disclosures [Line Items]
 
 
 
Authorization to defer for potential future recovery of construction costs
$ 500,000,000 
 
 
Regulatory Matters (Details) (USD $)
6 Months Ended 0 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended 2 Months Ended 0 Months Ended 3 Months Ended 6 Months Ended 12 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
APS
Jun. 30, 2015
APS
Apr. 15, 2014
RES 2014
APS
AZ Sun Program
MW
Apr. 15, 2014
RES 2014
APS
Alternative to AZ Sun Program
Customer
MW
Apr. 15, 2014
RES 2014
APS
Alternative to AZ Sun Program
MW
Dec. 19, 2014
RES 2014
APS
Alternative to AZ Sun Program, Phase 1
MW
Dec. 19, 2014
RES 2014
APS
Alternative to AZ Sun Program Phase 2
MW
Jan. 15, 2016
Lost Fixed Cost Recovery Mechanisms
APS
Mar. 2, 2015
Lost Fixed Cost Recovery Mechanisms
APS
Mar. 1, 2014
Lost Fixed Cost Recovery Mechanisms
APS
Jun. 30, 2016
Lost Fixed Cost Recovery Mechanisms
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
Jan. 6, 2012
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Jan. 6, 2012
ACC
Retail Rate Case Filing with Arizona Corporation Commission
APS
Maximum
Jun. 30, 2016
ACC
RES
APS
Jan. 12, 2016
ACC
RES 2016
APS
Jul. 1, 2016
ACC
RES 2017
APS
Apr. 1, 2016
ACC
DSMAC 2015
APS
Nov. 25, 2015
ACC
DSMAC 2015
APS
Mar. 20, 2015
ACC
DSMAC 2015
APS
project
Jul. 12, 2016
ACC
DSMAC 2015
Subsequent Event
APS
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, 2016
ACC
Power Supply Adjustor (PSA)
APS
Jan. 31, 2016
ACC
Power Supply Adjustor (PSA)
APS
Jun. 30, 2016
ACC
Power Supply Adjustor (PSA)
APS
Jun. 30, 2015
ACC
Power Supply Adjustor (PSA)
APS
Dec. 31, 2015
ACC
Power Supply Adjustor (PSA)
APS
Jan. 1, 2014
ACC
Net Metering
APS
Jun. 30, 2016
ACC
Net Metering
APS
Jun. 1, 2016
United States Federal Energy Regulatory Commission
Open Access Transmission Tariff [Member]
APS
Jun. 1, 2015
United States Federal Energy Regulatory Commission
Open Access Transmission Tariff [Member]
APS
Settlement Agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net change in base rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-fuel base rate increase
 
 
 
 
 
 
 
 
 
 
 
 
 
 
116,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel-related base rate decrease
 
 
 
 
 
 
 
 
 
 
 
 
 
 
153,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorized return on common equity (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of debt in capital structure
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46.10% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of common equity in capital structure
 
 
 
 
 
 
 
 
 
 
 
 
 
 
53.90% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual cost recovery due to modifications to the Environmental Improvement Surcharge
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Elimination of the sharing provision of fuel and purchased power costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Period to process the subsequent rate cases
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ACC staff sufficiency findings, general period of time
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plan term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Request to build additional utility scale solar, capacity
 
 
 
 
20 
 
10 
8 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional capacity from APS-owned non AZ Sun projects, impacted customers
 
 
 
 
 
1,500 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of approved budget
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
148,000,000 
 
68,900,000 
68,900,000 
 
 
68,900,000 
 
 
 
 
 
 
 
 
 
 
 
Amount of proposed budget
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
150,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional budget approved
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Number of resource savings projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of workshops
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
Number of days to convene a workshop
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
120 days 
 
 
 
 
 
 
 
 
 
 
Change in regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(9,688,000)
6,925,000 
6,925,000 
 
 
 
 
Deferred fuel and purchased power costs — current period
21,026,000 
(11,711,000)
21,026,000 
(11,711,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21,027,000 
(11,710,000)
 
 
 
 
 
Amounts charged to customers
(13,778,000)
(11,424,000)
(13,778,000)
(11,424,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(13,778,000)
(11,424,000)
 
 
 
 
 
Ending balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(2,439,000)
(16,209,000)
(9,688,000)
 
 
 
 
PSA rate (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001678 
 
 
 
 
 
 
 
 
PSA rate for prior year (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.000887 
 
 
 
 
Forward component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.001975 
 
 
 
 
 
 
 
 
Historical component of increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.000297)
 
 
 
 
 
 
 
 
Transition component increase in PSA (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(0.004936)
 
 
 
 
 
 
 
Decrease in annual wholesale transmission rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
17,600,000 
Increase in annual wholesale transmission rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
46,400,000 
38,500,000 
25,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in amount of adjustment representing prorated sales losses
 
 
 
 
 
 
 
 
 
7,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charge on future customers who install rooftop solar panels (in dollars per kWh)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.70 
0.70 
 
 
Estimated monthly collection due to charge on future customers who install rooftop solar panels
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.90 
 
 
 
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, 2016
Four Corners cost deferral
SCE
Four Corners Units 4 and 5
Jun. 30, 2016
Retired power plant costs
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
 
 
 
67 
 
 
12 
Regulatory asset, write off amount
 
 
 
 
 
12 
 
Regulatory noncurrent asset amortization period
 
 
 
10 years 
 
 
 
Net receipt due to negotiation of alternate arrangement
 
40 
 
 
 
 
 
Net book value
 
 
 
 
$ 119 
 
 
Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Detail of regulatory assets
 
 
Regulatory assets, current
$ 108,596 
$ 149,555 
Regulatory assets, non-current
1,190,622 
1,214,146 
Pension
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
617,283 
619,223 
Retired power plant costs
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
9,913 
9,913 
Regulatory assets, non-current
122,554 
127,518 
Income taxes — allowance for funds used during construction (AFUDC) equity
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
5,419 
5,495 
Regulatory assets, non-current
137,611 
133,712 
Deferred fuel and purchased power — mark-to-market (Note 6)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
30,986 
71,852 
Regulatory assets, non-current
40,573 
69,697 
Four Corners cost deferral
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
6,689 
6,689 
Regulatory assets, non-current
60,238 
63,582 
Income taxes — investment tax credit basis adjustment
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,851 
1,766 
Regulatory assets, non-current
47,826 
48,462 
Lost fixed cost recovery (b)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
49,852 
45,507 
Regulatory assets, non-current
0 
0 
Palo Verde VIEs (Note 5)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
18,465 
18,143 
Deferred compensation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
35,701 
34,751 
Deferred property taxes
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
62,726 
50,453 
Loss on reacquired debt
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,592 
1,515 
Regulatory assets, non-current
16,919 
16,375 
Tax expense of Medicare subsidy
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
1,512 
1,520 
Regulatory assets, non-current
11,647 
12,163 
Transmission vegetation management
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
4,543 
Regulatory assets, non-current
0 
0 
Mead-Phoenix transmission line CIAC
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
332 
332 
Regulatory assets, non-current
10,874 
11,040 
Transmission cost adjustor (b)
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
0 
0 
Regulatory assets, non-current
2,814 
2,942 
Coal reclamation
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
418 
418 
Regulatory assets, non-current
5,391 
6,085 
Other
 
 
Detail of regulatory assets
 
 
Regulatory assets, current
32 
5 
Regulatory assets, non-current
$ 0 
$ 0 
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
$ 116,172 
$ 145,766 
Regulatory liabilities, non-current
1,010,821 
994,152 
Asset retirement obligations
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
299,713 
277,554 
Removal costs
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
26,373 
39,746 
Regulatory liabilities, non-current
245,777 
240,367 
Other postretirement benefits
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
33,294 
34,100 
Regulatory liabilities, non-current
155,279 
179,521 
Income taxes — deferred investment tax credit
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
3,774 
3,604 
Regulatory liabilities, non-current
95,877 
97,175 
Income taxes — change in rates
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
1,771 
1,113 
Regulatory liabilities, non-current
71,257 
72,454 
Spent nuclear fuel
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
31 
3,051 
Regulatory liabilities, non-current
71,342 
67,437 
Renewable energy standard (b)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
35,882 
43,773 
Regulatory liabilities, non-current
2,182 
4,365 
Demand side management (b)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
4,957 
6,079 
Regulatory liabilities, non-current
21,864 
19,115 
Sundance maintenance
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
14,483 
13,678 
Deferred fuel and purchased power (b) (c)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,439 
9,688 
Regulatory liabilities, non-current
0 
0 
Deferred gains on utility property
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
2,062 
2,062 
Regulatory liabilities, non-current
9,535 
6,001 
Transmission cost adjustor (b)
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
5,545 
0 
Regulatory liabilities, non-current
0 
0 
Four Corners coal reclamation
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
0 
0 
Regulatory liabilities, non-current
15,969 
8,920 
Other
 
 
Detail of regulatory liabilities
 
 
Regulatory liabilities, current
44 
2,550 
Regulatory liabilities, non-current
$ 7,543 
$ 7,565 
Retirement Plans and Other Postretirement Benefits - Narrative (Details) (USD $)
1 Months Ended 3 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended
Jul. 31, 2012
Jun. 30, 2015
Jun. 30, 2015
Jun. 30, 2016
Pension Benefits
Sep. 30, 2014
Other Benefits
Jun. 30, 2016
Other Benefits
Other Postretirement Benefit Plan Remeasurement
 
 
 
 
 
 
Other postretirement plan benefit remeasurement, amount seeking approval to move to separate account to Pay Union employee medical costs
 
 
 
 
$ 140,000,000 
 
Regulatory Assets
 
 
 
 
 
 
Regulatory asset amortization period
3 years 
 
 
 
 
 
Amortization of regulatory asset
 
2,000,000 
4,000,000 
 
 
 
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 
 
 
2016 (up to)
 
 
 
 
 
1,000,000 
2017 (up to)
 
 
 
 
 
1,000,000 
2015
 
 
 
 
 
$ 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, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Pension Benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
$ 12,630 
$ 13,990 
$ 26,896 
$ 29,814 
Interest cost on benefit obligation
32,878 
30,802 
65,823 
61,992 
Expected return on plan assets
(43,161)
(44,467)
(86,953)
(89,616)
Amortization of:
 
 
 
 
Prior service cost
132 
149 
263 
297 
Net actuarial loss
10,627 
7,767 
20,358 
15,528 
Net periodic benefit cost
13,106 
8,241 
26,387 
18,015 
Portion of cost charged to expense
6,433 
5,232 
12,951 
11,219 
Other postretirement benefits
 
 
 
 
Retirement Plans and Other Benefits
 
 
 
 
Service cost — benefits earned during the period
3,560 
4,068 
7,497 
8,413 
Interest cost on benefit obligation
7,519 
6,867 
14,860 
14,051 
Expected return on plan assets
(9,125)
(9,281)
(18,247)
(18,428)
Amortization of:
 
 
 
 
Prior service cost
(9,471)
(9,492)
(18,942)
(18,984)
Net actuarial loss
1,349 
880 
2,295 
2,441 
Net periodic benefit cost
(6,168)
(6,958)
(12,537)
(12,507)
Portion of cost charged to expense
$ (3,027)
$ (2,482)
$ (6,153)
$ (4,271)
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) (USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2016
power_plant
Jun. 30, 2015
Jun. 30, 2016
power_plant
Jun. 30, 2015
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 
$ 4,605,000 
$ 9,747,000 
$ 9,210,000 
 
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 
4,605,000 
9,747,000 
9,210,000 
 
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 
9,000,000 
 
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period
 
 
288,000,000 
 
 
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 2016 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, 2016
Dec. 31, 2015
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
 
 
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$ 115,450 
$ 117,385 
Equity — Noncontrolling interests
133,915 
135,540 
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
115,450 
117,385 
Equity — Noncontrolling interests
133,915 
135,540 
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
115,450 
117,385 
Equity — Noncontrolling interests
$ 133,915 
$ 135,540 
Derivative Accounting - Narrative (Details) (USD $)
6 Months Ended
Jun. 30, 2016
Counterparty
Dec. 31, 2015
Designated as Hedging Instruments
 
 
Derivative Accounting
 
 
Gross recognized derivatives
$ 2,000,000 
$ 3,000,000 
Commodity Contracts
 
 
Derivative Accounting
 
 
Gross recognized derivatives
126,440,000 
207,387,000 
Concentration of credit risk, number of counterparties
1 
 
Concentration of risk with two counterparties, as a percentage of risk management assets
73.00% 
 
Risk management activities-derivative instruments: Commodity Contracts
22,000,000 
28,011,000 
Additional collateral to counterparties for energy related non-derivative instrument contracts
145,000,000 
 
Commodity Contracts |
Designated as Hedging Instruments
 
 
Derivative Accounting
 
 
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income
$ (4,000,000)
 
Arizona Public Service Company
 
 
Derivative Accounting
 
 
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment
100.00% 
 
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) (Commodity Contracts)
6 Months Ended
Jun. 30, 2016
MMcf
GWh
Commodity Contracts
 
Outstanding gross notional amount of derivatives
 
Power
2,291 
Gas
220,000 
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges
$ 0 
$ 0 
$ 0 
$ 0 
Designated as Hedging Instruments |
Fuel and purchased power
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Loss reclassified from accumulated OCI into income (effective portion realized)
(1,016,000)
(1,430,000)
(1,957,000)
(3,773,000)
Not Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net gain (loss) recognized in income
61,479,000 
10,547,000 
30,441,000 
(34,304,000)
Not Designated as Hedging Instruments |
Revenue
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net gain (loss) recognized in income
585,000 
(66,000)
483,000 
(114,000)
Not Designated as Hedging Instruments |
Fuel and purchased power
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Net gain (loss) recognized in income
60,894,000 
10,613,000 
29,958,000 
(34,190,000)
Other comprehensive income |
Designated as Hedging Instruments
 
 
 
 
Gains and losses from derivative instruments
 
 
 
 
Gain (loss) recognized in OCI on derivative instruments (effective portion)
$ 208,000 
$ 41,000 
$ 60,000 
$ (286,000)
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Assets
 
 
Gross Recognized Derivatives
$ 44,653 
$ 53,356 
Amounts Offset
(23,220)
(26,017)
Net Recognized Derivatives
21,433 
27,339 
Other
707 
672 
Amount Reported on Balance Sheet
22,000 
28,011 
Liabilities
 
 
Gross Recognized Derivatives
(126,440)
(207,387)
Amounts Offset
23,220 
44,077 
Net Recognized Derivatives
(103,220)
(163,310)
Other
(4,330)
(4,379)
Amount Reported on Balance Sheet
(107,550)
(167,689)
Assets and Liabilities
 
 
Gross Recognized Derivatives
(81,787)
(154,031)
Amounts Offset
0 
18,060 
Net Recognized Derivatives
(81,787)
(135,971)
Other
(3,623)
(3,707)
Amount Reported on Balance Sheet
(85,410)
(139,678)
Current Assets
 
 
Assets
 
 
Gross Recognized Derivatives
30,393 
37,396 
Amounts Offset
(14,424)
(22,163)
Net Recognized Derivatives
15,969 
15,233 
Other
707 
672 
Amount Reported on Balance Sheet
16,676 
15,905 
Investments and Other Assets
 
 
Assets
 
 
Gross Recognized Derivatives
14,260 
15,960 
Amounts Offset
(8,796)
(3,854)
Net Recognized Derivatives
5,464 
12,106 
Other
0 
0 
Amount Reported on Balance Sheet
5,464 
12,106 
Current Liabilities
 
 
Liabilities
 
 
Gross Recognized Derivatives
(65,432)
(113,560)
Amounts Offset
14,424 
40,223 
Net Recognized Derivatives
(51,008)
(73,337)
Other
(4,330)
(4,379)
Amount Reported on Balance Sheet
(55,338)
(77,716)
Deferred Credits and Other
 
 
Liabilities
 
 
Gross Recognized Derivatives
(61,008)
(93,827)
Amounts Offset
8,796 
3,854 
Net Recognized Derivatives
(52,212)
(89,973)
Other
0 
0 
Amount Reported on Balance Sheet
$ (52,212)
$ (89,973)
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) (Commodity Contracts, USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Commodity Contracts
 
Credit Risk and Credit-Related Contingent Features
 
Aggregate fair value of derivative instruments in a net liability position
$ 126,440 
Cash collateral posted
0 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered
$ 76,949 
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
Aug. 18, 2014
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Jun. 30, 2016
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Jun. 30, 2016
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, 2016
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
 
 
 
 
 
2 
Number of settlement agreement time periods
 
 
 
 
 
2 
Proceeds from legal settlements
 
53,900,000 
 
 
 
15,700,000 
Maximum insurance against public liability per occurrence for a nuclear incident (up to)
 
 
13,400,000,000 
 
 
 
Maximum available nuclear liability insurance (up to)
 
 
375,000,000 
 
 
 
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
 
 
18,900,000 
 
 
 
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
 
 
23,800,000 
 
 
 
Collateral assurance provided based on rating triggers
 
 
$ 64,000,000 
 
 
 
Period to provide collateral assurance based on rating triggers
 
 
20 days 
 
 
 
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) (Arizona Public Service Company, USD $)
In Millions, unless otherwise specified
0 Months Ended 6 Months Ended
Sep. 8, 2011
Customer
kV
Aug. 6, 2013
Contaminated groundwater wells
Defendant
Jun. 30, 2016
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 
 
Capacity of transmission line that tripped out of service (in kV)
500 
 
 
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost
10 minutes 
 
 
Number of customers losing service in Yuma area
69,700 
 
 
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)
6 Months Ended 0 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended 0 Months Ended
Jun. 30, 2016
Mar. 16, 2016
Four Corners
New Mexico Tax Matter
May 23, 2013
Four Corners
New Mexico Tax Matter
Jun. 30, 2016
Arizona Public Service Company
Letter of Credit Expiring in 2016 and 2017
Jun. 30, 2016
Arizona Public Service Company
Letters of Credit Expiring in 2017
Letter_of_credit
Mar. 16, 2016
Arizona Public Service Company
Four Corners
New Mexico Tax Matter
May 23, 2013
Arizona Public Service Company
Four Corners
New Mexico Tax Matter
Jun. 30, 2016
4C Acquisition, LLC
Four Corners Units 4 and 5
Jun. 30, 2016
Regional Haze Rules
Arizona Public Service Company
Four Corners Units 4 and 5
Jun. 30, 2016
Regional Haze Rules
Arizona Public Service Company
Natural gas tolling contract obligations
Four Corners Units 4 and 5
Jun. 30, 2016
Regional Haze Rules
Arizona Public Service Company
Four Corners
Four Corners Units 4 and 5
Jun. 30, 2016
Regional Haze Rules
Arizona Public Service Company
Navajo Plant
Jun. 30, 2016
Regional Haze Rules
Arizona Public Service Company
Cholla
Jun. 30, 2016
Regional Haze Rules
Arizona Public Service Company
Cholla
Jun. 30, 2016
Mercury and air toxic standards (MATS)
Arizona Public Service Company
Navajo Plant
Jun. 30, 2016
Mercury and air toxic standards (MATS)
Arizona Public Service Company
Cholla
Jun. 30, 2016
Coal combustion waste
Arizona Public Service Company
Four Corners
Jun. 30, 2016
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, 2016
Coal combustion waste
Arizona Public Service Company
Cholla
Jul. 6, 2016
Payment Guarantee
Subsequent Event
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 
$ 1,000,000 
$ 8,000,000 
 
 
 
 
 
Proposal comment period
 
 
 
 
 
 
 
 
 
 
 
 
45 days 
 
 
 
 
 
 
 
 
Additional percentage share of cost of control
 
 
 
 
 
 
 
 
 
7.00% 
 
 
 
 
 
 
 
 
 
 
 
Site contingency increase in loss exposure not accrued, best estimate
 
 
 
 
 
 
 
 
 
 
45,000,000 
 
 
 
 
 
15,000,000 
1,000,000 
 
40,000,000 
 
Industry litigation, period to complete rulemaking proceeding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
Clean power plan, optional extension period
2 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal severance surtax, penalty, and interest
 
 
30,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share of the assessment
 
 
 
 
 
 
12,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partial payment of assessment
 
 
 
 
 
 
800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Litigation settlement awarded (against), amount
 
(1,000,000)
 
 
 
(800,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial Assurances
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding letters of credit
 
 
 
$ 79,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of letters of credit expiring
 
 
 
 
150,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of parental guarantees
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
Other Income and Other Expense (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Other income:
 
 
 
 
Interest income
$ 184 
$ 184 
$ 302 
$ 294 
Investment gains — net
13 
0 
13 
0 
Miscellaneous
0 
(9)
(1)
116 
Total other income
197 
175 
314 
410 
Other expense:
 
 
 
 
Non-operating costs
(2,085)
(1,952)
(4,133)
(4,200)
Investment losses — net
(539)
(650)
(1,058)
(1,145)
Miscellaneous
(218)
(7)
(1,689)
(1,550)
Total other expense
(2,842)
(2,609)
(6,880)
(6,895)
Arizona Public Service Company
 
 
 
 
Other income:
 
 
 
 
Interest income
109 
6 
181 
73 
Gain on disposition of property
4,989 
478 
5,321 
685 
Miscellaneous
649 
226 
855 
591 
Total other income
5,747 
710 
6,357 
1,349 
Other expense:
 
 
 
 
Non-operating costs
(2,719)
(1,878)
(4,685)
(4,395)
Loss on disposition of property
(657)
(251)
(1,083)
(894)
Miscellaneous
(1,054)
(320)
(3,412)
(2,514)
Total other expense
$ (4,430)
$ (2,449)
$ (9,180)
$ (7,803)
Earnings Per Share (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Earnings Per Share [Abstract]
 
 
 
 
Net income attributable to common shareholders
$ 121,308 
$ 122,902 
$ 125,761 
$ 139,024 
Weighted average common shares outstanding - basic (in shares)
111,368 
110,986 
111,336 
110,958 
Net effect of dilutive securities:
 
 
 
 
Contingently issuable performance shares and restricted stock units (in shares)
636 
474 
594 
468 
Weighted average common shares outstanding — diluted (in shares)
112,004 
111,460 
111,930 
111,426 
Net income attributable to common shareholders - basic (in dollars per share)
$ 1.09 
$ 1.11 
$ 1.13 
$ 1.25 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 1.08 
$ 1.10 
$ 1.12 
$ 1.25 
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Assets
 
 
Nuclear decommissioning trust
$ 767,416 
$ 735,196 
Total assets
18,118 
30,364 
Recurring
 
 
Assets
 
 
Cash equivalents
9,857 
 
Derivative instruments, other
(22,487)
(25,345)
Derivative assets
22,140 
28,011 
Nuclear decommissioning trust, other
314,898 
314,622 
Nuclear decommissioning trust
767,416 
735,196 
Total, other
292,411 
289,277 
Total assets
799,413 
763,207 
Liabilities
 
 
Total, other
18,864 
39,698 
Derivative liability
(107,550)
(167,689)
Recurring |
US commingled equity funds
 
 
Assets
 
 
Nuclear decommissioning trust, other
328,037 
314,957 
Nuclear decommissioning trust
328,037 
314,957 
Recurring |
Cash and cash equivalent funds
 
 
Assets
 
 
Nuclear decommissioning trust, other
(13,139)
(335)
Nuclear decommissioning trust
4,753 
11,925 
Recurring |
U.S. Treasury
 
 
Assets
 
 
Nuclear decommissioning trust
117,448 
117,245 
Recurring |
Corporate debt
 
 
Assets
 
 
Nuclear decommissioning trust
106,399 
96,243 
Recurring |
Mortgage-backed securities
 
 
Assets
 
 
Nuclear decommissioning trust
112,771 
99,065 
Recurring |
Municipality bonds
 
 
Assets
 
 
Nuclear decommissioning trust
73,847 
72,206 
Recurring |
Other
 
 
Assets
 
 
Nuclear decommissioning trust
24,161 
23,555 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
 
Assets
 
 
Cash equivalents
9,857 
 
Decommissioning fund investments, gross fair value
135,340 
129,505 
Gross assets, fair value disclosure
145,197 
129,505 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Cash and cash equivalent funds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
17,892 
12,260 
Recurring |
Quoted Prices in Active Markets for Identical Assets (Level 1) |
U.S. Treasury
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
117,448 
117,245 
Recurring |
Significant Other Observable Inputs (Level 2)
 
 
Assets
 
 
Gross derivative assets
26,509 
22,992 
Decommissioning fund investments, gross fair value
317,178 
291,069 
Gross assets, fair value disclosure
343,687 
314,061 
Liabilities
 
 
Gross derivative liability
(75,916)
(144,044)
Recurring |
Significant Other Observable Inputs (Level 2) |
Corporate debt
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
106,399 
96,243 
Recurring |
Significant Other Observable Inputs (Level 2) |
Mortgage-backed securities
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
112,771 
99,065 
Recurring |
Significant Other Observable Inputs (Level 2) |
Municipality bonds
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
73,847 
72,206 
Recurring |
Significant Other Observable Inputs (Level 2) |
Other
 
 
Assets
 
 
Decommissioning fund investments, gross fair value
24,161 
23,555 
Recurring |
Significant Unobservable Inputs (a) (Level 3)
 
 
Assets
 
 
Gross derivative assets
18,118 
30,364 
Gross assets, fair value disclosure
18,118 
30,364 
Liabilities
 
 
Gross derivative liability
$ (50,498)
$ (63,343)
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, 2016
Dec. 31, 2015
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
$ 18,118 
$ 30,364 
Liabilities
50,498 
63,343 
Electricity forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
16,151 
24,543 
Liabilities
39,548 
54,679 
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)
21.68 
15.92 
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)
43.50 
40.73 
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)
31.26 
26.86 
Option Contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
0 
0 
Liabilities
2,993 
5,628 
Option Contracts |
Minimum |
Option model
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
35.46 
23.87 
Electricity price volatilities (as a percent)
56.00% 
40.00% 
Natural gas price volatilities (as a percent)
38.00% 
32.00% 
Option Contracts |
Maximum |
Option model
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
49.65 
44.13 
Electricity price volatilities (as a percent)
140.00% 
59.00% 
Natural gas price volatilities (as a percent)
80.00% 
40.00% 
Option Contracts |
Weighted Average |
Option model
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Electricity forward price (per MWh)
43.12 
33.91 
Electricity price volatilities (as a percent)
94.00% 
52.00% 
Natural gas price volatilities (as a percent)
49.00% 
35.00% 
Natural gas forward contracts
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Assets
1,967 
5,821 
Liabilities
$ 7,957 
$ 3,036 
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)
2.67 
2.18 
Natural gas forward contracts |
Maximum |
Discounted cash flows
 
 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
 
 
Natural gas forward price (per MMbtu)
3.37 
3.14 
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)
2.91 
2.61 
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
 
 
 
 
Net derivative balance at beginning of period
$ (39,507)
$ (48,814)
$ (32,979)
$ (41,386)
Included in OCI
104 
25 
104 
(237)
Deferred as a regulatory asset or liability
1,499 
5,813 
(7,604)
(4,933)
Settlements
4,502 
4,541 
6,267 
4,852 
Transfers into Level 3 from Level 2
120 
(3,566)
382 
(3,968)
Transfers from Level 3 into Level 2
902 
(944)
1,450 
2,727 
Net derivative balance at end of period
(32,380)
(42,945)
(32,380)
(42,945)
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, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Dec. 31, 2015
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
$ 767,416 
 
$ 767,416 
 
$ 735,196 
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
 
 
Proceeds from the sale of securities
 
 
290,594 
225,779 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
767,416 
 
767,416 
 
735,196 
Arizona Public Service Company
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
767,416 
 
767,416 
 
735,196 
Unrealized Gains
188,879 
 
188,879 
 
169,053 
Unrealized Losses
(352)
 
(352)
 
(2,760)
Net payables for securities purchases
(13,139)
 
(13,139)
 
(335)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
 
 
 
 
 
Realized gains
2,282 
1,260 
4,720 
2,455 
 
Realized losses
(1,350)
(1,525)
(3,136)
(2,050)
 
Proceeds from the sale of securities
148,785 
110,498 
290,594 
225,779 
 
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
767,416 
 
767,416 
 
735,196 
Arizona Public Service Company |
Equity Securities
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
328,037 
 
328,037 
 
314,957 
Unrealized Gains
165,926 
 
165,926 
 
157,098 
Unrealized Losses
(7)
 
(7)
 
(115)
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Total
328,037 
 
328,037 
 
314,957 
Arizona Public Service Company |
Fixed income securities.
 
 
 
 
 
Nuclear decommissioning trust fund assets
 
 
 
 
 
Fair Value
452,518 
 
452,518 
 
420,574 
Unrealized Gains
22,953 
 
22,953 
 
11,955 
Unrealized Losses
(345)
 
(345)
 
(2,645)
Fair value of fixed income securities, summarized by contractual maturities
 
 
 
 
 
Less than one year
13,046 
 
13,046 
 
 
1 year - 5 years
133,548 
 
133,548 
 
 
5 years - 10 years
103,874 
 
103,874 
 
 
Greater than 10 years
202,050 
 
202,050 
 
 
Total
$ 452,518 
 
$ 452,518 
 
$ 420,574 
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, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
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, 2015
AOCI Including Portion Attributable to Noncontrolling Interest
Mar. 31, 2015
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2014
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2015
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2015
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2015
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, 2015
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Arizona Public Service Company
Jun. 30, 2015
Arizona Public Service Company
Jun. 30, 2016
Arizona Public Service Company
Jun. 30, 2015
Arizona Public Service Company
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, 2015
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Mar. 31, 2015
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Dec. 31, 2014
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Arizona Public Service Company
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2015
Arizona Public Service Company
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2016
Arizona Public Service Company
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
Jun. 30, 2015
Arizona Public Service Company
Accumulated Net Investment Gain (Loss) 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, 2015
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, 2015
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
$ 4,719,183 
$ 4,525,643 
$ 4,719,183 
$ 4,525,643 
$ (43,719)
$ (43,770)
$ (44,748)
$ (65,600)
$ (66,382)
$ (68,141)
 
 
 
 
 
 
 
 
$ 4,809,779 
$ 4,627,164 
$ 4,809,779 
$ 4,627,164 
$ (25,928)
$ (26,038)
$ (27,097)
$ (45,651)
$ (46,476)
$ (48,333)
 
 
 
 
 
 
 
 
OCI (loss) before reclassifications
 
 
 
 
 
 
 
 
 
 
128 
25 
(566)
(775)
(1,585)
(969)
(1,585)
(969)
 
 
 
 
 
 
 
 
 
 
128 
25 
(566)
(775)
(1,521)
(927)
(1,521)
(927)
Amounts reclassified from accumulated other comprehensive loss
 
 
 
 
 
 
 
 
 
 
624 
874 
1,766 
2,850 
884 
852 
1,414 
1,435 
 
 
 
 
 
 
 
 
 
 
624 
874 
1,766 
2,850 
879 
853 
1,490 
1,534 
Total other comprehensive income
51 
782 
1,029 
2,541 
 
 
 
 
 
 
752 
899 
1,200 
2,075 
(701)
(117)
(171)
466 
110 
825 
1,169 
2,682 
 
 
 
 
 
 
752 
899 
1,200 
2,075 
(642)
(74)
(31)
607 
Balance at end of period
 
 
$ 4,719,457 
$ 4,519,102 
$ (43,719)
$ (43,770)
$ (44,748)
$ (65,600)
$ (66,382)
$ (68,141)
 
 
 
 
 
 
 
 
 
 
$ 4,814,794 
$ 4,629,852 
$ (25,928)
$ (26,038)
$ (27,097)
$ (45,651)
$ (46,476)
$ (48,333)
 
 
 
 
 
 
 
 
Asset Retirement Obligations - Roll-Forward (Details) (Arizona Public Service Company, USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2016
Arizona Public Service Company
 
Change in asset retirement obligations
 
Asset retirement obligations at the beginning of year
$ 443,576 
Changes attributable to:
 
Accretion expense
13,112 
Settlements
(5,224)
Newly incurred liabilities
10,373 
Asset retirement obligations at the end of year
$ 462,000 
Asset Retirement Obligations - Narrative (Details) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2016
Dec. 31, 2015
Asset Retirement Obligations
 
 
Asset retirement obligation, current
$ 15,513 
$ 28,573 
Arizona Public Service Company
 
 
Asset Retirement Obligations
 
 
Newly incurred liabilities
10,373 
 
Asset retirement obligation, current
16,000 
28,573 
Asset retirement obligation
462,000 
443,576 
Arizona Public Service Company |
Ocotillo Steam Units
 
 
Asset Retirement Obligations
 
 
Number of constructed turbine units
5 
 
Newly incurred liabilities
$ 10,000