PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/3/2017
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2017
Jul. 26, 2017
Entity Information [Line Items]
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Jun. 30, 2017 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
111,624,528 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q2 
 
APS
 
 
Entity Information [Line Items]
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY  
 
Entity Central Index Key
0000007286  
 
Document Type
10-Q 
 
Document Period End Date
Jun. 30, 2017 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
71,264,947 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q2 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
OPERATING REVENUES
$ 944,587 
$ 915,394 
$ 1,622,315 
$ 1,592,561 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
254,611 
274,848 
467,006 
496,133 
Operations and maintenance
214,013 
242,279 
433,989 
485,474 
Depreciation and amortization
125,739 
123,073 
253,366 
242,549 
Taxes other than income taxes
44,289 
42,117 
88,125 
84,618 
Other expenses
1,706 
1,329 
2,094 
1,877 
Total
640,358 
683,646 
1,244,580 
1,310,651 
OPERATING INCOME
304,229 
231,748 
377,735 
281,910 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
10,456 
10,369 
19,938 
20,885 
Other income (Note 8)
484 
197 
964 
314 
Other expense (Note 8)
(3,822)
(2,842)
(7,502)
(6,880)
Total
7,118 
7,724 
13,400 
14,319 
INTEREST EXPENSE
 
 
 
 
Interest charges
54,969 
52,849 
106,833 
103,593 
Allowance for borrowed funds used during construction
(4,906)
(5,301)
(9,378)
(10,528)
Total
50,063 
47,548 
97,455 
93,065 
INCOME BEFORE INCOME TAXES
261,284 
191,924 
293,680 
203,164 
INCOME TAXES
88,967 
65,742 
93,178 
67,656 
NET INCOME
172,317 
126,182 
200,502 
135,508 
Less: Net income attributable to noncontrolling interests (Note 5)
4,874 
4,874 
9,747 
9,747 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
167,443 
121,308 
190,755 
125,761 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
111,797 
111,368 
111,763 
111,336 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
112,345 
112,004 
112,270 
111,930 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 1.50 
$ 1.09 
$ 1.71 
$ 1.13 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 1.49 
$ 1.08 
$ 1.70 
$ 1.12 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 1.31 
$ 1.25 
$ 1.31 
$ 1.25 
APS
 
 
 
 
ELECTRIC OPERATING REVENUES
942,615 
909,757 
1,619,485 
1,586,389 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
259,892 
274,848 
476,995 
496,133 
Operations and maintenance
208,286 
233,712 
420,505 
472,423 
Depreciation and amortization
125,317 
123,033 
252,524 
242,479 
Income taxes
92,381 
70,444 
103,754 
76,294 
Taxes other than income taxes
43,949 
42,036 
87,447 
84,446 
Total
729,825 
744,073 
1,341,225 
1,371,775 
OPERATING INCOME
212,790 
165,684 
278,260 
214,614 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Income taxes
3,856 
1,721 
6,579 
3,536 
Allowance for equity funds used during construction
10,456 
10,369 
19,938 
20,885 
Other income (Note 8)
1,142 
5,747 
2,204 
6,357 
Other expense (Note 8)
(5,651)
(4,430)
(10,029)
(9,180)
Total
9,803 
13,407 
18,692 
21,598 
INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
49,989 
48,903 
97,480 
95,722 
Interest on short-term borrowings
2,331 
1,930 
4,459 
4,007 
Debt discount, premium and expense
1,197 
1,195 
2,374 
2,334 
Allowance for borrowed funds used during construction
(4,906)
(4,999)
(9,378)
(10,039)
Total
48,611 
47,029 
94,935 
92,024 
NET INCOME
173,982 
132,062 
202,017 
144,188 
Less: Net income attributable to noncontrolling interests (Note 5)
4,874 
4,874 
9,747 
9,747 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 169,108 
$ 127,188 
$ 192,270 
$ 134,441 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
NET INCOME
$ 172,317 
$ 126,182 
$ 200,502 
$ 135,508 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax expense
128 
(763)
(566)
Reclassification of net realized loss, net of tax expense
564 
624 
1,771 
1,766 
Pension and other postretirement benefits activity, net of tax expense
(1,334)
(701)
(812)
(171)
Total other comprehensive income (loss)
(763)
51 
196 
1,029 
COMPREHENSIVE INCOME
171,554 
126,233 
200,698 
136,537 
Less: Comprehensive income attributable to noncontrolling interests
4,874 
4,874 
9,747 
9,747 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
166,680 
121,359 
190,951 
126,790 
APS
 
 
 
 
NET INCOME
173,982 
132,062 
202,017 
144,188 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax expense
128 
(763)
(566)
Reclassification of net realized loss, net of tax expense
564 
624 
1,771 
1,766 
Pension and other postretirement benefits activity, net of tax expense
(1,308)
(642)
(697)
(31)
Total other comprehensive income (loss)
(737)
110 
311 
1,169 
COMPREHENSIVE INCOME
173,245 
132,172 
202,328 
145,357 
Less: Comprehensive income attributable to noncontrolling interests
4,874 
4,874 
9,747 
9,747 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 168,371 
$ 127,298 
$ 192,581 
$ 135,610 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Net unrealized loss, tax expense
$ 4 
$ 80 
$ 679 
$ 626 
Reclassification of net realized loss, tax expense (benefit)
(348)
(392)
(191)
Pension and other postretirement benefits activity, tax benefit (expense)
823 
439 
119 
(206)
Arizona Public Service Company
 
 
 
 
Net unrealized loss, tax expense
80 
679 
626 
Reclassification of net realized loss, tax expense (benefit)
(348)
(392)
(191)
Pension and other postretirement benefits activity, tax benefit (expense)
$ 808 
$ 403 
$ 218 
$ (156)
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 4,953 
$ 8,881 
Customer and other receivables
293,266 
250,491 
Accrued unbilled revenues
213,703 
107,949 
Allowance for doubtful accounts
(2,151)
(3,037)
Materials and supplies (at average cost)
258,134 
253,979 
Fossil fuel (at average cost)
29,890 
28,608 
Income tax receivable
4,073 
3,751 
Assets from risk management activities (Note 6)
307 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
48,122 
12,465 
Other regulatory assets (Note 3)
172,606 
94,410 
Other current assets
45,301 
45,028 
Total current assets
1,068,204 
822,219 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
55 
Nuclear decommissioning trust (Note 11)
822,244 
779,586 
Other assets
71,121 
69,063 
Total investments and other assets
893,420 
848,650 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,227,444 
17,341,888 
Accumulated depreciation and amortization
(5,951,653)
(5,970,100)
Net
11,275,791 
11,371,788 
Construction work in progress
1,195,076 
1,019,947 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
111,580 
113,515 
Intangible assets, net of accumulated amortization
265,926 
90,022 
Nuclear fuel, net of accumulated amortization
118,909 
119,004 
Total property, plant and equipment
12,967,282 
12,714,276 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,415,091 
1,313,428 
Assets for other postretirement benefits (Note 4)
184,629 
166,206 
Other
141,101 
139,474 
Total deferred debits
1,740,821 
1,619,108 
TOTAL ASSETS
16,669,727 
16,004,253 
CURRENT LIABILITIES
 
 
Accounts payable
270,262 
264,631 
Accrued taxes
150,709 
138,964 
Accrued interest
53,046 
52,835 
Common dividends payable
73,113 
72,926 
Short-term borrowings (Note 2)
482,000 
177,200 
Current maturities of long-term debt (Note 2)
207,000 
125,000 
Customer deposits
72,585 
82,520 
Liabilities from risk management activities (Note 6)
48,613 
25,836 
Liabilities for asset retirements
8,960 
9,135 
Regulatory liabilities (Note 3)
91,173 
99,899 
Other current liabilities
181,133 
244,000 
Total current liabilities
1,638,594 
1,292,946 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
4,192,520 
4,021,785 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
3,048,007 
2,945,232 
Regulatory liabilities (Note 3)
940,106 
948,916 
Liabilities for asset retirements
631,657 
615,340 
Liabilities for pension benefits (Note 4)
460,368 
509,310 
Liabilities from risk management activities (Note 6)
46,586 
47,238 
Customer advances
98,795 
88,672 
Coal mine reclamation
236,811 
221,910 
Deferred investment tax credit
206,969 
210,162 
Unrecognized tax benefits
10,307 
10,046 
Other
168,930 
156,784 
Total deferred credits and other
5,848,536 
5,753,610 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,642,680 and 111,392,053 issued at respective dates
2,604,482 
2,596,030 
Treasury stock at cost; 19,298 and 55,317 shares at respective dates
(1,553)
(4,133)
Total common stock
2,602,929 
2,591,897 
Retained earnings
2,300,109 
2,255,547 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(39,882)
(39,070)
Derivative instruments
(3,744)
(4,752)
Total accumulated other comprehensive loss
(43,626)
(43,822)
Total shareholders’ equity
4,859,412 
4,803,622 
Noncontrolling interests (Note 5)
130,665 
132,290 
Total equity
4,990,077 
4,935,912 
TOTAL LIABILITIES AND EQUITY
16,669,727 
16,004,253 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
4,851 
8,840 
Customer and other receivables
285,482 
262,611 
Accrued unbilled revenues
213,703 
107,949 
Allowance for doubtful accounts
(2,151)
(3,037)
Materials and supplies (at average cost)
256,828 
252,777 
Fossil fuel (at average cost)
29,890 
28,608 
Income tax receivable
11,174 
Assets from risk management activities (Note 6)
307 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
48,122 
12,465 
Other regulatory assets (Note 3)
172,606 
94,410 
Other current assets
38,743 
41,849 
Total current assets
1,048,381 
837,340 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
55 
Nuclear decommissioning trust (Note 11)
822,244 
779,586 
Other assets
49,798 
48,320 
Total investments and other assets
872,097 
827,907 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,112,413 
17,228,787 
Accumulated depreciation and amortization
(5,865,446)
(5,881,941)
Net
11,246,967 
11,346,846 
Construction work in progress
1,157,017 
989,497 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
111,580 
113,515 
Intangible assets, net of accumulated amortization
265,764 
89,868 
Nuclear fuel, net of accumulated amortization
118,909 
119,004 
Total property, plant and equipment
12,900,237 
12,658,730 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,415,091 
1,313,428 
Assets for other postretirement benefits (Note 4)
181,237 
162,911 
Other
129,423 
130,859 
Total deferred debits
1,725,751 
1,607,198 
TOTAL ASSETS
16,546,466 
15,931,175 
CURRENT LIABILITIES
 
 
Accounts payable
265,291 
259,161 
Accrued taxes
147,335 
130,576 
Accrued interest
52,752 
52,525 
Common dividends payable
73,100 
72,900 
Short-term borrowings (Note 2)
385,700 
135,500 
Current maturities of long-term debt (Note 2)
82,000 
Customer deposits
72,585 
82,520 
Liabilities from risk management activities (Note 6)
48,613 
25,836 
Liabilities for asset retirements
8,499 
8,703 
Regulatory liabilities (Note 3)
91,173 
99,899 
Other current liabilities
180,095 
226,417 
Total current liabilities
1,407,143 
1,094,037 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
3,095,019 
2,999,295 
Regulatory liabilities (Note 3)
940,106 
948,916 
Liabilities for asset retirements
623,437 
607,234 
Liabilities for pension benefits (Note 4)
440,016 
488,253 
Liabilities from risk management activities (Note 6)
46,586 
47,238 
Customer advances
98,795 
88,672 
Coal mine reclamation
221,295 
206,645 
Deferred investment tax credit
206,969 
210,162 
Unrecognized tax benefits
37,669 
37,408 
Other
154,185 
143,560 
Total deferred credits and other
5,864,077 
5,777,383 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,421,696 
2,421,696 
Retained earnings
2,377,315 
2,331,245 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(21,368)
(20,671)
Derivative instruments
(3,744)
(4,752)
Total accumulated other comprehensive loss
(25,112)
(25,423)
Total shareholders’ equity
4,952,061 
4,905,680 
Noncontrolling interests (Note 5)
130,665 
132,290 
Total equity
5,082,726 
5,037,970 
Long-term debt less current maturities (Note 2)
4,192,520 
4,021,785 
Total capitalization
9,275,246 
9,059,755 
TOTAL LIABILITIES AND EQUITY
$ 16,546,466 
$ 15,931,175 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Jun. 30, 2017
Dec. 31, 2016
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
 
 
Common stock, par value (in dollars per share)
   
   
Common stock, authorized shares (in shares)
150,000,000 
150,000,000 
Common stock, issued shares (in shares)
111,642,680 
111,392,053 
Treasury stock at cost, shares (in shares)
19,298 
55,317 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 200,502 
$ 135,508 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
291,285 
282,291 
Deferred fuel and purchased power
(21,993)
(21,026)
Deferred fuel and purchased power amortization
(13,663)
13,778 
Allowance for equity funds used during construction
(19,938)
(20,885)
Deferred income taxes
94,365 
65,881 
Deferred investment tax credit
(3,194)
(2,083)
Change in derivative instruments fair value
(222)
(237)
Stock compensation
12,891 
25,048 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(62,624)
(19,898)
Accrued unbilled revenues
(105,754)
(101,331)
Materials, supplies and fossil fuel
(5,437)
1,551 
Income tax receivable
(322)
589 
Other current assets
(23,418)
(5,649)
Accounts payable
21,771 
47,621 
Accrued taxes
11,745 
6,567 
Other current liabilities
(44,778)
53,912 
Change in margin and collateral accounts — assets
(71)
(34)
Change in margin and collateral accounts — liabilities
(4,700)
18,010 
Change in other long-term assets
(49,162)
(41,101)
Change in other long-term liabilities
13,279 
(16,037)
Net cash flow provided by operating activities
290,562 
422,475 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(693,626)
(731,609)
Contributions in aid of construction
18,032 
29,127 
Allowance for borrowed funds used during construction
(9,378)
(10,528)
Proceeds from nuclear decommissioning trust sales
275,364 
290,594 
Investment in nuclear decommissioning trust
(276,505)
(291,734)
Other
(2,127)
(1,307)
Net cash flow used for investing activities
(688,240)
(715,457)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
251,635 
445,933 
Repayment of long-term debt
(76,850)
Short-term borrowing and payments — net
287,800 
64,140 
Short-term debt borrowings under revolving credit facility
17,000 
Dividends paid on common stock
(142,520)
(135,335)
Common stock equity issuance - net of purchases
(8,792)
10,017 
Distributions to noncontrolling interests
(11,372)
(11,372)
Other
(1)
Net cash flow provided by financing activities
393,750 
296,534 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(3,928)
3,552 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,881 
39,488 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
4,953 
43,040 
Cash paid during the period for:
 
 
Income taxes, net of refunds
2,062 
2,503 
Interest, net of amounts capitalized
94,870 
89,109 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
80,517 
55,286 
Dividends declared but not yet paid
73,113 
69,484 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
202,017 
144,188 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
290,444 
282,221 
Deferred fuel and purchased power
(21,994)
(21,026)
Deferred fuel and purchased power amortization
(13,663)
13,778 
Allowance for equity funds used during construction
(19,938)
(20,885)
Deferred income taxes
87,412 
60,131 
Deferred investment tax credit
(3,194)
(2,083)
Change in derivative instruments fair value
(222)
(237)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(41,422)
(19,809)
Accrued unbilled revenues
(105,754)
(101,331)
Materials, supplies and fossil fuel
(5,333)
1,551 
Income tax receivable
11,174 
Other current assets
(20,039)
(3,749)
Accounts payable
20,147 
48,593 
Accrued taxes
16,759 
17,141 
Other current liabilities
(33,408)
44,711 
Change in margin and collateral accounts — assets
(71)
(34)
Change in margin and collateral accounts — liabilities
(4,700)
18,010 
Change in other long-term assets
(45,420)
(38,780)
Change in other long-term liabilities
13,061 
3,979 
Net cash flow provided by operating activities
325,856 
426,369 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(680,343)
(717,729)
Contributions in aid of construction
18,032 
29,127 
Allowance for borrowed funds used during construction
(9,378)
(10,039)
Proceeds from nuclear decommissioning trust sales
275,364 
290,594 
Investment in nuclear decommissioning trust
(276,505)
(291,734)
Other
(1,478)
(388)
Net cash flow used for investing activities
(674,308)
(700,169)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
251,635 
445,933 
Repayment of long-term debt
(76,850)
Short-term borrowing and payments — net
250,200 
64,140 
Dividends paid on common stock
(146,000)
(138,900)
Distributions to noncontrolling interests
(11,372)
(11,372)
Net cash flow provided by financing activities
344,463 
282,951 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(3,989)
9,151 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,840 
22,056 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
4,851 
31,207 
Cash paid during the period for:
 
 
Income taxes, net of refunds
8,772 
Interest, net of amounts capitalized
92,334 
88,066 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
82,621 
55,286 
Dividends declared but not yet paid
$ 73,100 
$ 69,500 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Arizona Public Service Company
Arizona Public Service Company
Common Stock
Arizona Public Service Company
Additional Paid-In Capital
Arizona Public Service Company
Retained Earnings
Arizona Public Service Company
Accumulated Other Comprehensive Income (Loss)
Arizona Public Service Company
Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2015
$ 4,719,457 
$ 2,541,668 
$ (5,806)
$ 2,092,803 
$ (44,748)
$ 135,540 
$ 4,814,794 
$ 178,162 
$ 2,379,696 
$ 2,148,493 
$ (27,097)
$ 135,540 
Beginning balance (in shares) at Dec. 31, 2015
 
111,095,402 
115,030 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
135,508 
 
 
125,761 
 
9,747 
144,188 
 
 
134,441 
 
9,747 
Other comprehensive income
1,029 
 
 
 
1,029 
 
1,169 
 
 
 
1,169 
 
Dividends on common stock
(138,947)
 
 
(138,947)
 
 
(139,000)
 
 
(139,000)
 
 
Issuance of common stock (in shares)
 
80,098 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
7,830 
7,830 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(71,962)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,880)
 
(4,880)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
185,092 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
10,558 
 
10,556 
 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(11,372)
 
 
 
 
(11,372)
(11,372)
 
 
 
 
(11,372)
Balance at end of period at Jun. 30, 2016
4,719,183 
2,549,498 
(130)
2,079,619 
(43,719)
133,915 
4,809,779 
178,162 
2,379,696 
2,143,934 
(25,928)
133,915 
Ending balance (in shares) at Jun. 30, 2016
 
111,175,500 
1,900 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Mar. 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
126,182 
 
 
 
 
 
132,062 
 
 
 
 
 
Other comprehensive income
51 
 
 
 
 
 
110 
 
 
 
 
 
Balance at end of period at Jun. 30, 2016
4,719,183 
 
 
 
 
 
4,809,779 
178,162 
2,379,696 
 
 
 
Ending balance (in shares) at Jun. 30, 2016
 
 
 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Dec. 31, 2016
4,935,912 
2,596,030 
(4,133)
2,255,547 
(43,822)
132,290 
5,037,970 
178,162 
2,421,696 
2,331,245 
(25,423)
132,290 
Beginning balance (in shares) at Dec. 31, 2016
111,392,053 
111,392,053 
55,317 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
200,502 
 
 
190,755 
 
9,747 
202,017 
 
 
192,270 
 
9,747 
Other comprehensive income
196 
 
 
 
196 
 
311 
 
 
 
311 
 
Dividends on common stock
(146,204)
 
 
(146,204)
 
 
(146,200)
 
 
(146,200)
 
 
Issuance of common stock (in shares)
 
250,627 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
8,452 
8,452 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(156,172)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(12,430)
 
(12,430)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
192,191 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
15,021 
 
15,010 
11 
 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(11,372)
 
 
 
 
(11,372)
(11,372)
 
 
 
 
(11,372)
Balance at end of period at Jun. 30, 2017
4,990,077 
2,604,482 
(1,553)
2,300,109 
(43,626)
130,665 
5,082,726 
178,162 
2,421,696 
2,377,315 
(25,112)
130,665 
Ending balance (in shares) at Jun. 30, 2017
111,642,680 
111,642,680 
19,298 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Mar. 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
172,317 
 
 
 
 
 
173,982 
 
 
 
 
 
Other comprehensive income
(763)
 
 
 
 
 
(737)
 
 
 
 
 
Balance at end of period at Jun. 30, 2017
$ 4,990,077 
 
 
 
 
 
$ 5,082,726 
$ 178,162 
$ 2,421,696 
 
 
 
Ending balance (in shares) at Jun. 30, 2017
111,642,680 
 
 
 
 
 
 
71,264,947 
 
 
 
 
Consolidation and Nature of Operations
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC ("4CA"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado").  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 5 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
 
Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
 
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2016 Form 10-K.

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

Statements of Cash Flows for the
Six Months Ended June 30, 2016
As previously
reported
 
Reclassifications to conform to current year presentation
 
Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
 
 
 
 
 
Stock compensation
$

 
$
25,048

 
$
25,048

Change in other long-term liabilities
9,011

 
(25,048
)
 
(16,037
)

 
 

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

 
$
2,503

Interest, net of amounts capitalized
94,870

 
89,109

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

 
$
55,286

Dividends accrued but not yet paid
73,113

 
69,484

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

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
 
Pinnacle West
 
At June 30, 2017, Pinnacle West had a $200 million facility that matures in May 2021. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At June 30, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $39.3 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended and restated its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018.  Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At June 30, 2017, Pinnacle West had $57 million outstanding under the facility.
 
APS

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

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

At June 30, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million facility that matures in May 2021 and the above-mentioned $500 million credit facility. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2017, APS had $385.7 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 7 for a discussion of APS’s other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

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

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,274,520

 
4,645,844

 
4,021,785

 
4,300,789

Total
$
4,399,520

 
$
4,770,844

 
$
4,146,785

 
$
4,425,789

 
Debt Provisions
 
An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At June 30, 2017, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $5.0 billion, and total capitalization was approximately $9.4 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.8 billion, assuming APS’s total capitalization remains the same.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). The principal provisions of the application are described in detail in Note 3 of our 2016 Form 10-K.

On March 1, 2017, the ACC Staff filed with the ACC a settlement term sheet. The settlement term sheet was agreed to by a majority of the stakeholders in the rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations. The settlement term sheet was converted into a definitive settlement agreement (the "2017 Settlement Agreement"), was signed by the supporting parties and was filed with the ACC on March 27, 2017. The 2017 Settlement Agreement was submitted to the administrative law judge ("ALJ"), whose decision regarding whether the settlement should be approved will be reviewed by the ACC. Hearings on the proposed settlement began on April 24, 2017 and the hearings were completed on May 2, 2017. Post-hearing briefing on the proposed settlement was completed on June 1, 2017.

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

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

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

The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61 million due to changes in depreciation schedules.

Other key provisions of the agreement include the following:

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

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

APS cannot predict whether the 2017 Settlement Agreement will ultimately be approved by the ACC, or the exact timing of the ACC's consideration of the matter.
 
Prior Rate Case Filing
 
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs ("Base Fuel Rate") from $0.03757 to $0.03207 per kWh; and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million. Other key provisions of the 2012 Settlement Agreement are described in detail in Note 3 of our 2016 Form 10-K.
  
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
  
In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC.

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

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which includes the revenue neutral transfer of specific revenue requirements in accordance with the 2017 Settlement Agreement.  The ACC has not yet ruled on APS's 2017 RES Implementation Plan.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the United States Environmental Protection Agency ("EPA").  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  APS anticipates that the ACC will schedule the proceedings once there is a decision in APS's pending rate case. APS cannot predict the outcome of this proceeding.

Demand Side Management Adjustor Charge ("DSMAC").  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery Mechanism (“LFCR”) mechanism.

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

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

APS was required to file its 2018 DSM Implementation Plan by June 1, 2017, but the ACC granted APS's request to extend the deadline to file the 2018 DSM Implementation Plan until September 1, 2017.
 
Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.
 
PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):
 
 
Six Months Ended 
 June 30,
 
2017
 
2016
Beginning balance
$
12,465

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

 
21,027

Amounts refunded/(charged) to customers
13,663

 
(13,778
)
Ending balance
$
48,122

 
$
(2,439
)

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

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

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

On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans.  A transmission customer intervened and protested certain aspects of APS’s filing.  FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed.  At this time, APS is unable to predict the outcome of this proceeding.

 Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units.
 
APS files for a LFCR adjustment every January. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective for the first billing cycle of March 2017. On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, to be effective with the first billing cycle of April 2017. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Net Metering

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

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

In addition, the ACC made the following determinations:

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

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

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

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

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

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. Consistent with Arizona statute, TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. In accordance with the 2017 Settlement Agreement described above, in the event the ACC approves the 2017 Settlement Agreement, these appeals will be withdrawn by TASC. The ACC's decision is expected to remain in effect during any legal challenge.

System Benefits Charge

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

Subpoena from Arizona Corporation Commissioner Robert Burns

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

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

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. APS did not produce the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel with the ACC. On June 20, 2017, the ACC denied the motion to compel. The manner by which the courts can or should review this decision, as well as the timing and process for that review, is a subject of dispute and has not been decided. APS and Pinnacle West cannot predict the outcome of this matter.

Four Corners 

On December 30, 2013, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $60 million as of June 30, 2017 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the System Improvement Benefits ("SIB") matter. The Arizona Court of Appeals reversed an ACC rate decision involving a water company regarding the ACC’s method of finding fair value in that case, which raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor. The Arizona Court of Appeals ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. Supplemental briefing has been completed and the Arizona Court of Appeals has the matter under review. We cannot predict when or how this matter will be resolved.
 
As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.
Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates. The 2017 Settlement Agreement described above contemplates continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($112 million as of June 30, 2017), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
Navajo Plant
The co-owners of the Navajo Generating Station (the "Navajo Plant") and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease, at which time a new lease will allow for decommissioning activities to begin after December 2019 instead of later this year. The new lease was approved by the Navajo Nation Tribal Council on June 26, 2017. Certain additional approvals are required for specific co-owners, which are expected to occur by late 2017. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($102 million as of June 30, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.
    
On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

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

 
$
697,184

 
$

 
$
711,059

Retired power plant costs
Various
 
19,083

 
205,418

 
9,913

 
117,591

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

 
158,356

 
6,305

 
152,118

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

 
43,354

 

 
42,963

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

 

 
12,465

 

Four Corners cost deferral
2024
 
6,689

 
53,549

 
6,689

 
56,894

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

 
53,509

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
75,070

 

 
61,307

 

Palo Verde VIEs (Note 5)
2046
 

 
19,085

 

 
18,775

Deferred compensation
2036
 

 
37,161

 

 
35,595

Deferred property taxes
(c)
 

 
85,694

 

 
73,200

Loss on reacquired debt
2038
 
1,637

 
16,124

 
1,637

 
16,942

Tax expense of Medicare subsidy
2024
 
1,503

 
9,922

 
1,513

 
10,589

Demand Side Management
2018
 
5,122

 

 
3,744

 

AG-1 deferral
(f)
 

 
10,058

 

 
5,868

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,542

 
332

 
10,708

Transmission cost adjustor (b)
2018
 
8,115

 

 

 
1,588

Coal reclamation
2026
 
418

 
15,135

 
418

 
5,182

Other
Various
 
322

 

 
432

 

Total regulatory assets (d)
 
 
$
220,728

 
$
1,415,091

 
$
106,875

 
$
1,313,428

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



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

 
$
321,732

 
$

 
$
279,976

Removal costs
(a)
 
37,943

 
189,959

 
29,899

 
223,145

Other postretirement benefits
(b)
 
32,725

 
107,764

 
32,662

 
123,913

Income taxes — deferred investment tax credit
2046
 
4,315

 
107,153

 
4,368

 
108,827

Income taxes — change in rates
2046
 
2,565

 
68,583

 
1,771

 
70,898

Spent nuclear fuel
2047
 

 
71,996

 

 
71,726

Renewable energy standard (c)
2018
 
11,519

 

 
26,809

 

Demand side management (c)
2019
 

 
19,921

 

 
20,472

Sundance maintenance
2030
 

 
16,092

 

 
15,287

Deferred gains on utility property
2019
 
2,063

 
7,851

 
2,063

 
8,895

Four Corners coal reclamation
2031
 

 
20,894

 

 
18,248

Other
Various
 
43

 
8,161

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
91,173

 
$
940,106

 
$
99,899

 
$
948,916


(a)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)
See Note 4 for further discussion.
(c)
See "Cost Recovery Mechanisms" discussion above.
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates. Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $145 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. While we do not expect to transfer any funds prior to 2018, as of June 30, 2017, such methodology would result in an amount of approximately $145 million being transferred to the new trust account.

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

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

 
$
12,630

 
$
27,429

 
$
26,896

 
$
4,201

 
$
3,560

 
$
8,559

 
$
7,497

Interest cost on benefit obligation
32,177

 
32,878

 
64,878

 
65,823

 
7,415

 
7,519

 
14,980

 
14,860

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

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost (credit)
20

 
132

 
41

 
263

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

 
10,627

 
23,950

 
20,358

 
1,104

 
1,349

 
2,559

 
2,295

Net periodic benefit cost
$
13,901

 
$
13,106

 
$
29,163

 
$
26,387

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

 
$
6,433

 
$
14,461

 
$
12,951

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

 
Contributions
 
We have made voluntary contributions of $80 million to our pension plan year-to-date in 2017. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2017-2019 period. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans.
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
 
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three and six months ended June 30, 2017 of $5 million and $10 million respectively, and for the three and six months ended June 30, 2016 of $5 million and $10 million respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
June 30, 2017
 
December 31, 2016
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
111,580

 
$
113,515

Equity — Noncontrolling interests
130,665

 
132,290


 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 million over the lease terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
Derivative Accounting
Derivative Accounting
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value.  See Note 10 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. Cash flow hedge accounting was discontinued for the significant majority of our contracts after May 31, 2012.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of June 30, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
908

 
GWh
Gas
 
247

 
Billion cubic feet

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

 
$
208

 
$
(84
)
 
$
60

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

(a)
During the three and six months ended June 30, 2017 and 2016, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $3 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

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

 
$
(346
)
 
$
483

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

 
(58,043
)
 
29,958

Total
 
 
 
$
(5,474
)
 
$
61,479

 
$
(58,389
)
 
$
30,441


(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed Consolidated Balance Sheets
 
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
 
We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
 
The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016, include gross liabilities of $1 million and $2 million, respectively, of derivative instruments designated as hedging instruments.
 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2017 and December 31, 2016.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

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

 
$
(15,387
)
 
$
237

 
$
70

 
$
307

Investments and other assets
 
1,620

 
(1,565
)
 
55

 

 
55

Total assets
 
17,244

 
(16,952
)
 
292

 
70

 
362

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(64,646
)
 
18,587

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

 
(46,586
)
 

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

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

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

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $3,200.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $2,554, and cash margin provided to counterparties of $70.
 
As of December 31, 2016:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
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