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
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 
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 
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
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
 
 
 
 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
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
)