PINNACLE WEST CAPITAL CORP, 10-Q filed on 11/3/2016
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2016
Oct. 28, 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
Sep. 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
 
111,306,107 
Document Fiscal Year Focus
2016 
 
Document Fiscal Period Focus
Q3 
 
APS
 
 
Entity Information [Line Items]
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY  
 
Entity Central Index Key
0000007286  
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 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
Q3 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
OPERATING REVENUES
$ 1,166,922 
$ 1,199,146 
$ 2,759,483 
$ 2,761,013 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
336,120 
363,847 
832,253 
868,561 
Operations and maintenance
217,568 
220,449 
703,042 
646,358 
Depreciation and amortization
120,428 
125,625 
362,977 
369,313 
Taxes other than income taxes
41,284 
43,241 
125,902 
129,489 
Other expenses
264 
873 
2,141 
2,524 
Total
715,664 
754,035 
2,026,315 
2,016,245 
OPERATING INCOME
451,258 
445,111 
733,168 
744,768 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
10,194 
7,645 
31,079 
26,214 
Other income (Note 8)
71 
139 
385 
549 
Other expense (Note 8)
(5,205)
(5,538)
(12,085)
(12,433)
Total
5,060 
2,246 
19,379 
14,330 
INTEREST EXPENSE
 
 
 
 
Interest charges
51,293 
49,342 
154,886 
146,069 
Allowance for borrowed funds used during construction
(4,321)
(3,518)
(14,849)
(12,056)
Total
46,972 
45,824 
140,037 
134,013 
INCOME BEFORE INCOME TAXES
409,346 
401,533 
612,510 
625,085 
INCOME TAXES
141,446 
139,555 
209,102 
214,873 
NET INCOME
267,900 
261,978 
403,408 
410,212 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,862 
14,620 
14,072 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
263,027 
257,116 
388,788 
396,140 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
111,416 
111,036 
111,363 
110,984 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
112,100 
111,616 
111,987 
111,490 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 2.36 
$ 2.32 
$ 3.49 
$ 3.57 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 2.35 
$ 2.30 
$ 3.47 
$ 3.55 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 0 
$ 0 
$ 1.25 
$ 1.19 
APS
 
 
 
 
ELECTRIC OPERATING REVENUES
1,166,359 
1,198,380 
2,752,748 
2,758,771 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
339,510 
363,847 
835,643 
868,561 
Operations and maintenance
209,366 
216,011 
681,789 
633,989 
Depreciation and amortization
120,013 
125,592 
362,492 
369,234 
Income taxes
148,945 
148,543 
225,239 
232,454 
Taxes other than income taxes
40,924 
43,149 
125,370 
129,258 
Total
858,758 
897,142 
2,230,533 
2,233,496 
OPERATING INCOME
307,601 
301,238 
522,215 
525,275 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
10,194 
7,645 
31,079 
26,214 
Income taxes
5,753 
5,678 
9,289 
10,809 
Other income (Note 8)
567 
650 
6,924 
1,999 
Other expense (Note 8)
(3,776)
(3,965)
(12,956)
(11,768)
Total
12,738 
10,008 
34,336 
27,254 
INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
46,970 
44,011 
142,692 
134,265 
Interest on short-term borrowings
2,401 
3,460 
6,408 
6,339 
Debt discount, premium and expense
1,195 
1,218 
3,529 
3,455 
Allowance for borrowed funds used during construction
(4,320)
(3,492)
(14,359)
(12,019)
Total
46,246 
45,197 
138,270 
132,040 
NET INCOME
274,093 
266,049 
418,281 
420,489 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,862 
14,620 
14,072 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 269,220 
$ 261,187 
$ 403,661 
$ 406,417 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
NET INCOME
$ 267,900 
$ 261,978 
$ 403,408 
$ 410,212 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(29)
(151)
(595)
(926)
Reclassification of net realized loss, net of tax benefit
798 
892 
2,564 
3,742 
Pension and other postretirement benefits activity, net of tax benefit (expense)
804 
869 
633 
1,335 
Total other comprehensive income
1,573 
1,610 
2,602 
4,151 
COMPREHENSIVE INCOME
269,473 
263,588 
406,010 
414,363 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,862 
14,620 
14,072 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
264,600 
258,726 
391,390 
400,291 
APS
 
 
 
 
NET INCOME
274,093 
266,049 
418,281 
420,489 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(29)
(151)
(595)
(926)
Reclassification of net realized loss, net of tax benefit
798 
892 
2,564 
3,742 
Pension and other postretirement benefits activity, net of tax benefit (expense)
799 
870 
768 
1,477 
Total other comprehensive income
1,568 
1,611 
2,737 
4,293 
COMPREHENSIVE INCOME
275,661 
267,660 
421,018 
424,782 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,862 
14,620 
14,072 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 270,788 
$ 262,798 
$ 406,398 
$ 410,710 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Net unrealized loss, tax benefit (expense)
$ 18 
$ 96 
$ (608)
$ (392)
Reclassification of net realized loss, tax benefit
500 
567 
691 
1,490 
Pension and other postretirement benefits activity, tax expense
504 
553 
709 
1,345 
Arizona Public Service Company
 
 
 
 
Net unrealized loss, tax benefit (expense)
18 
96 
(608)
(392)
Reclassification of net realized loss, tax benefit
500 
567 
691 
1,490 
Pension and other postretirement benefits activity, tax expense
$ 501 
$ 553 
$ 657 
$ 1,275 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2016
Dec. 31, 2015
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 48,267 
$ 39,488 
Customer and other receivables
325,029 
274,691 
Accrued unbilled revenues
150,531 
96,240 
Allowance for doubtful accounts
(3,608)
(3,125)
Materials and supplies (at average cost)
250,789 
234,234 
Fossil fuel (at average cost)
34,745 
45,697 
Income tax receivable
589 
Assets from risk management activities (Note 6)
6,235 
15,905 
Deferred fuel and purchased power regulatory asset (Note 3)
8,132 
Other regulatory assets (Note 3)
114,088 
149,555 
Other current assets
43,284 
37,242 
Total current assets
977,492 
890,516 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
12,106 
Nuclear decommissioning trust (Note 11)
779,753 
735,196 
Other assets
68,977 
52,518 
Total investments and other assets
848,730 
799,820 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
16,877,695 
16,222,232 
Accumulated depreciation and amortization
(5,895,765)
(5,594,094)
Net
10,981,930 
10,628,138 
Construction work in progress
1,118,666 
816,307 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
114,483 
117,385 
Intangible assets, net of accumulated amortization
96,789 
123,975 
Nuclear fuel, net of accumulated amortization
133,731 
123,139 
Total property, plant and equipment
12,445,599 
11,808,944 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,212,150 
1,214,146 
Assets for other postretirement benefits (Note 4)
191,007 
185,997 
Other
130,748 
128,835 
Total deferred debits
1,533,905 
1,528,978 
TOTAL ASSETS
15,805,726 
15,028,258 
CURRENT LIABILITIES
 
 
Accounts payable
248,133 
297,480 
Accrued taxes
219,432 
138,600 
Accrued interest
46,124 
56,305 
Common dividends payable
69,363 
Short-term borrowings (Note 2)
117,300 
Current maturities of long-term debt (Note 2)
16,870 
357,580 
Customer deposits
78,262 
73,073 
Liabilities from risk management activities (Note 6)
45,175 
77,716 
Liabilities for asset retirements (Note 14)
11,852 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
Other regulatory liabilities (Note 3)
104,313 
136,078 
Other current liabilities
222,257 
197,861 
Total current liabilities
1,109,718 
1,442,317 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
4,145,366 
3,462,391 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,941,559 
2,723,425 
Regulatory liabilities (Note 3)
998,349 
994,152 
Liabilities for asset retirements (Note 14)
458,628 
415,003 
Liabilities for pension benefits (Note 4)
401,680 
480,998 
Liabilities from risk management activities (Note 6)
58,343 
89,973 
Customer advances
98,779 
115,609 
Coal mine reclamation
220,269 
201,984 
Deferred investment tax credit
180,738 
187,080 
Unrecognized tax benefits
9,904 
9,524 
Other
190,258 
186,345 
Total deferred credits and other
5,558,507 
5,404,093 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,220,370 and 111,095,402 issued at respective dates
2,552,979 
2,541,668 
Treasury stock at cost; 1,900 and 115,030 shares at respective dates
(130)
(5,806)
Total common stock
2,552,849 
2,535,862 
Retained earnings
2,342,643 
2,092,803 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(36,960)
(37,593)
Derivative instruments
(5,186)
(7,155)
Total accumulated other comprehensive loss
(42,146)
(44,748)
Total shareholders’ equity
4,853,346 
4,583,917 
Noncontrolling interests (Note 5)
138,789 
135,540 
Total equity
4,992,135 
4,719,457 
TOTAL LIABILITIES AND EQUITY
15,805,726 
15,028,258 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
8,027 
22,056 
Customer and other receivables
323,036 
274,428 
Accrued unbilled revenues
150,531 
96,240 
Allowance for doubtful accounts
(3,608)
(3,125)
Materials and supplies (at average cost)
249,554 
234,234 
Fossil fuel (at average cost)
34,745 
45,697 
Assets from risk management activities (Note 6)
6,235 
15,905 
Deferred fuel and purchased power regulatory asset (Note 3)
8,132 
Other regulatory assets (Note 3)
114,088 
149,555 
Other current assets
39,981 
35,765 
Total current assets
930,721 
870,755 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
12,106 
Nuclear decommissioning trust (Note 11)
779,753 
735,196 
Other assets
48,471 
34,455 
Total investments and other assets
828,224 
781,757 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
16,764,278 
16,218,724 
Accumulated depreciation and amortization
(5,808,259)
(5,590,937)
Net
10,956,019 
10,627,787 
Construction work in progress
1,092,895 
812,845 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
114,483 
117,385 
Intangible assets, net of accumulated amortization
96,634 
123,820 
Nuclear fuel, net of accumulated amortization
133,731 
123,139 
Total property, plant and equipment
12,393,762 
11,804,976 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,212,150 
1,214,146 
Assets for other postretirement benefits (Note 4)
187,616 
182,625 
Other
125,863 
127,923 
Total deferred debits
1,525,629 
1,524,694 
TOTAL ASSETS
15,678,336 
14,982,182 
CURRENT LIABILITIES
 
 
Accounts payable
241,495 
291,574 
Accrued taxes
252,443 
144,488 
Accrued interest
45,762 
56,003 
Common dividends payable
69,400 
Short-term borrowings (Note 2)
83,300 
Current maturities of long-term debt (Note 2)
16,870 
357,580 
Customer deposits
78,262 
73,073 
Liabilities from risk management activities (Note 6)
45,175 
77,716 
Liabilities for asset retirements (Note 14)
11,505 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
Other regulatory liabilities (Note 3)
104,313 
136,078 
Other current liabilities
186,402 
180,535 
Total current liabilities
1,065,527 
1,424,708 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,957,021 
2,764,489 
Regulatory liabilities (Note 3)
998,349 
994,152 
Liabilities for asset retirements (Note 14)
450,508 
415,003 
Liabilities for pension benefits (Note 4)
380,640 
459,065 
Liabilities from risk management activities (Note 6)
58,343 
89,973 
Customer advances
98,779 
115,609 
Coal mine reclamation
205,126 
201,984 
Deferred investment tax credit
180,738 
187,080 
Unrecognized tax benefits
37,266 
35,251 
Other
140,233 
142,683 
Total deferred credits and other
5,507,003 
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
2,413,153 
2,148,493 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(19,174)
(19,942)
Derivative instruments
(5,186)
(7,155)
Total shareholders’ equity
4,946,651 
4,679,254 
Noncontrolling interests (Note 5)
138,789 
135,540 
Total equity
5,085,440 
4,814,794 
Long-term debt less current maturities (Note 2)
4,020,366 
3,337,391 
Total capitalization
9,105,806 
8,152,185 
TOTAL LIABILITIES AND EQUITY
$ 15,678,336 
$ 14,982,182 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Sep. 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
111,220,370 
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
9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 403,408 
$ 410,212 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
422,851 
428,121 
Deferred fuel and purchased power
(46,185)
(137)
Deferred fuel and purchased power amortization
28,366 
19,284 
Allowance for equity funds used during construction
(31,079)
(26,214)
Deferred income taxes
194,915 
168,071 
Deferred investment tax credit
(6,342)
9,542 
Change in derivative instruments fair value
(278)
(261)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(77,908)
(107,263)
Accrued unbilled revenues
(54,291)
(61,736)
Materials, supplies and fossil fuel
(4,438)
(22,537)
Income tax receivable
589 
3,098 
Other current assets
(11,665)
1,994 
Accounts payable
(57,237)
(53,247)
Accrued taxes
80,925 
110,066 
Other current liabilities
(12,383)
16,952 
Change in margin and collateral accounts — assets
517 
(1,291)
Change in margin and collateral accounts — liabilities
18,085 
30,678 
Change in unrecognized tax benefits
1,628 
(9,276)
Change in other long-term assets
(59,589)
17,753 
Change in other long-term liabilities
(24,839)
(112,436)
Net cash flow provided by operating activities
765,050 
821,373 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(1,014,910)
(778,700)
Contributions in aid of construction
39,355 
33,982 
Allowance for borrowed funds used during construction
(14,848)
(12,056)
Proceeds from nuclear decommissioning trust sales
447,419 
330,304 
Investment in nuclear decommissioning trust
(449,129)
(343,488)
Other
(18,353)
(2,830)
Net cash flow used for investing activities
(1,010,466)
(772,788)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
693,151 
600,000 
Repayment of long-term debt
(353,560)
(344,847)
Short-term borrowing and payments — net
117,300 
(90,400)
Dividends paid on common stock
(203,115)
(192,466)
Common stock equity issuance - net of purchases
11,790 
12,543 
Distributions to noncontrolling interests
(11,372)
(28,012)
Other
Net cash flow provided by (used for) financing activities
254,195 
(43,182)
NET INCREASE IN CASH AND CASH EQUIVALENTS
8,779 
5,403 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
39,488 
7,604 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
48,267 
13,007 
Cash paid during the period for:
 
 
Income taxes, net of refunds
2,562 
2,692 
Interest, net of amounts capitalized
146,691 
143,116 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
91,315 
36,718 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
418,281 
420,489 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
422,365 
428,042 
Deferred fuel and purchased power
(46,185)
(137)
Deferred fuel and purchased power amortization
28,366 
19,284 
Allowance for equity funds used during construction
(31,079)
(26,214)
Deferred income taxes
171,000 
72,737 
Deferred investment tax credit
(6,342)
9,542 
Change in derivative instruments fair value
(278)
(261)
Changes in current assets and liabilities:
 
 
Customer and other receivables
(75,961)
(106,236)
Accrued unbilled revenues
(54,291)
(61,736)
Materials, supplies and fossil fuel
(4,368)
(22,537)
Other current assets
(9,857)
2,676 
Accounts payable
(56,349)
(52,919)
Accrued taxes
107,955 
215,524 
Other current liabilities
(30,973)
7,759 
Change in margin and collateral accounts — assets
517 
(1,291)
Change in margin and collateral accounts — liabilities
18,085 
30,678 
Change in unrecognized tax benefits
1,628 
(9,276)
Change in other long-term assets
(54,051)
16,955 
Change in other long-term liabilities
(32,146)
(111,121)
Net cash flow provided by operating activities
766,317 
831,958 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(992,735)
(778,207)
Contributions in aid of construction
39,355 
33,982 
Allowance for borrowed funds used during construction
(14,359)
(12,019)
Proceeds from nuclear decommissioning trust sales
447,419 
330,304 
Investment in nuclear decommissioning trust
(449,129)
(343,488)
Other
(14,016)
(840)
Net cash flow used for investing activities
(983,465)
(770,268)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
693,151 
600,000 
Repayment of long-term debt
(353,560)
(344,847)
Short-term borrowing and payments — net
83,300 
(90,400)
Dividends paid on common stock
(208,400)
(197,600)
Distributions to noncontrolling interests
(11,372)
(28,012)
Net cash flow provided by (used for) financing activities
203,119 
(60,859)
NET INCREASE IN CASH AND CASH EQUIVALENTS
(14,029)
831 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
22,056 
4,515 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
8,027 
5,346 
Cash paid during the period for:
 
 
Income taxes, net of refunds
10,533 
5,504 
Interest, net of amounts capitalized
144,984 
141,216 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 90,069 
$ 36,718 
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
410,212 
 
 
396,140 
 
14,072 
420,489 
 
 
406,417 
 
14,072 
Other comprehensive income
4,151 
 
 
 
4,151 
 
4,293 
 
 
 
4,293 
 
Dividends on common stock
(131,818)
 
 
(131,818)
 
 
(131,800)
 
 
(131,800)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
250,868 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
16,049 
16,049 
 
 
 
 
 
 
 
 
 
 
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
(28,013)
 
 
 
 
(28,013)
(28,013)
 
 
 
 
(28,013)
Balance at beginning of period at Sep. 30, 2015
4,791,319 
2,529,019 
(1,765)
2,190,387 
(63,990)
137,668 
4,894,822 
178,162 
2,379,696 
2,243,336 
(44,040)
137,668 
Ending balance (in shares) at Sep. 30, 2015
 
110,900,630 
53,559 
 
 
 
 
71,264,947 
 
 
 
 
Balance at end of period at Jun. 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
261,978 
 
 
 
 
 
266,049 
 
 
 
 
 
Other comprehensive income
1,610 
 
 
 
 
 
1,611 
 
 
 
 
 
Balance at beginning of period at Sep. 30, 2015
4,791,319 
 
 
 
 
 
4,894,822 
178,162 
2,379,696 
 
 
 
Ending balance (in shares) at Sep. 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
403,408 
 
 
388,788 
 
14,620 
418,281 
 
 
403,661 
 
14,620 
Other comprehensive income
2,602 
 
 
 
2,602 
 
2,737 
 
 
 
2,737 
 
Dividends on common stock
(138,947)
 
 
(138,947)
 
 
(139,001)
 
 
(139,001)
 
 
Issuance of common stock (in shares)
 
124,968 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
11,311 
11,311 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(71,962)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,880)
 
(4,880)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
185,092 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
10,555 
 
10,556 
(1)
 
 
 
 
 
 
 
 
Capital activities by noncontrolling interests
(11,371)
 
 
 
 
(11,371)
(11,371)
 
 
 
 
(11,371)
Balance at beginning of period at Sep. 30, 2016
4,992,135 
2,552,979 
(130)
2,342,643 
(42,146)
138,789 
5,085,440 
178,162 
2,379,696 
2,413,153 
(24,360)
138,789 
Ending balance (in shares) at Sep. 30, 2016
111,220,370 
111,220,370 
1,900 
 
 
 
 
71,264,947 
 
 
 
 
Balance at end of period at Jun. 30, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
267,900 
 
 
 
 
 
274,093 
 
 
 
 
 
Other comprehensive income
1,573 
 
 
 
 
 
1,568 
 
 
 
 
 
Balance at beginning of period at Sep. 30, 2016
$ 4,992,135 
 
 
 
 
 
$ 5,085,440 
$ 178,162 
$ 2,379,696 
 
 
 
Ending balance (in shares) at Sep. 30, 2016
111,220,370 
 
 
 
 
 
 
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 2015 Form 10-K.
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Nine Months Ended 
 September 30,
 
2016
 
2015
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,562

 
$
2,692

Interest, net of amounts capitalized
146,691

 
143,116

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
91,315

 
$
36,718

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 September 30, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

On August 31, 2016, PNW entered into a $75 million 364-day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At September 30, 2016, Pinnacle West had $34 million outstanding under the facility.
 
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.

On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016.

On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B.

At September 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 September 30, 2016, APS had $83 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 September 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
4,037,236

 
4,609,003

 
3,694,971

 
3,981,367

Total
$
4,162,236

 
$
4,734,003

 
$
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 September 30, 2016, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.7 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:

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, 2016, 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 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 an LFCR rate mechanism to support energy efficiency and distributed renewable generation;
 
Modifications to the 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 December of 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 make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The second stage of the program, which includes an additional 2 MW of rooftop solar and energy storage, will place 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 is planned to be 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 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.

In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the United States Environmental Protection Agency ("EPA").  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  APS cannot predict the outcome of this proceeding.
 
Demand Side Management Adjustor Charge.  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):
 
 
Nine Months Ended 
 September 30,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,925

Deferred fuel and purchased power costs — current period
46,185

 
137

Amounts charged to customers
(28,365
)
 
(19,284
)
Ending balance
$
8,132

 
$
(12,222
)

 
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. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two months delay in implementation did 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. On October 7, 2016, an Administrative Law Judge (the "ALJ") issued a recommendation in the docket concerning the value and cost of distributed generation. The ALJ recommended a change to how customers are compensated for energy that they export from rooftop solar systems. Instead of retail rate net metering, the ALJ recommended that the amount of compensation be established by using both an avoided cost calculation and a grid-scale solar resource proxy calculation that would be updated in subsequent utility rate cases. The ALJ recommended that the change to how APS pays for exported rooftop solar energy apply only to those customers who apply to interconnect their distributed generation systems after a decision in APS’s currently pending rate case. The ALJ found rooftop solar customers to be partial requirements customers, but recommended that whether rooftop solar customers should be placed into a separate customer class for purposes of ratemaking be decided in individual utility rate cases. Exceptions to the ALJ recommendation are due November 15, 2016. On December 13, 2016, the ACC will discuss at an open meeting the ALJ recommendation concerning the value and cost of distributed generation.  APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company ("TEP") 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. On August 18, 2016, the ACC issued a decision which ordered that net metering be considered in a separate, phase 2 of the UNS Electric, Inc. rate case to occur after the ACC decides issues raised in the separate, generic docket concerning the value and cost of distributed generation discussed above. APS has also intervened in the upcoming TEP rate case. On June 24, 2016, APS filed testimony in the TEP rate case in support of the TEP proposed rate design changes. In August 2016, the ACC also bifurcated the TEP rate case into two phases, the first of which will address revenue requirements and other traditional rate case issues while the second will address net metering issues. 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 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.

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.

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 year-to-date 2016. The subpoenas request 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 October 6, 2016.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas, or alternatively stay APS’ obligations to comply with the subpoenas and decline to decide APS’ 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. 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 $65 million as of September 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 suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. 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 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. 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 ($117 million as of September 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
 
September 30, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
608,312

 
$

 
$
619,223

Retired power plant costs
2033
 
9,913

 
120,072

 
9,913

 
127,518

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

 
151,451

 
5,495

 
133,712

Deferred fuel and purchased power — mark-to-market (Note 6)
2019
 
30,748

 
53,350

 
71,852

 
69,697

Deferred fuel and purchased power (c) (e)
2017
 
8,132

 

 

 

Four Corners cost deferral
2024
 
6,689

 
58,566

 
6,689

 
63,582

Income taxes — investment tax credit basis adjustment
2045
 
1,852

 
46,699

 
1,766

 
48,462

Lost fixed cost recovery (b)
2017
 
55,297

 

 
45,507

 

Palo Verde VIEs (Note 5)
2046
 

 
18,620

 

 
18,143

Deferred compensation
2036
 

 
36,071

 

 
34,751

Deferred property taxes
(c)
 

 
67,547

 

 
50,453

Loss on reacquired debt
2034
 
1,592

 
16,521

 
1,515

 
16,375

Tax expense of Medicare subsidy
2024
 
1,512

 
10,774

 
1,520

 
12,163

Transmission vegetation management
2016
 

 

 
4,543

 

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,791

 
332

 
11,040

Transmission cost adjustor (b)
2018
 

 
4,687

 

 
2,942

Coal reclamation
2026
 
418

 
5,286

 
418

 
6,085

Other
Various
 
316

 
3,403

 
5

 

Total regulatory assets (d)
 
 
$
122,220

 
$
1,212,150

 
$
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."
(e)
Subject to a carrying charge.


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

 
$
305,862

 
$

 
$
277,554

Removal costs
(a)
 
27,626

 
237,885

 
39,746

 
240,367

Other postretirement benefits
(d)
 
33,294

 
146,988

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2045
 
3,774

 
93,578

 
3,604

 
97,175

Income taxes — change in rates
2046
 
1,771

 
70,233

 
1,113

 
72,454

Spent nuclear fuel
2047
 

 
71,884

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
28,921

 
1,091

 
43,773

 
4,365

Demand side management (b)
2017
 
4,261

 
21,863

 
6,079

 
19,115

Sundance maintenance
2030
 

 
14,885

 

 
13,678

Deferred fuel and purchased power (b) (c)
2017
 

 

 
9,688

 

Deferred gains on utility property
2019
 
2,063

 
9,335

 
2,062

 
6,001

Transmission cost adjustor (b)
2017
 
2,077

 

 

 

Four Corners coal reclamation
2031
 

 
17,213

 

 
8,920

Other
Various
 
526

 
7,532

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
104,313

 
$
998,349

 
$
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 nine months ended September 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 
 September 30,
 
Nine Months Ended 
 September 30,
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
Service cost — benefits earned during the period
$
13,448

 
$
14,907

 
$
40,344

 
$
44,721

 
$
3,748

 
$
4,207

 
$
11,245

 
$
12,620

Interest cost on benefit obligation
32,912

 
30,996

 
98,735

 
92,987

 
7,430

 
7,026

 
22,291

 
21,077

Expected return on plan assets
(43,477
)
 
(44,808
)
 
(130,429
)
 
(134,424
)
 
(9,123
)
 
(9,214
)
 
(27,371
)
 
(27,641
)
Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost
132

 
148

 
395

 
446

 
(9,471
)
 
(9,492
)
 
(28,413
)
 
(28,476
)
Net actuarial loss
10,179

 
7,764

 
30,538

 
23,292

 
1,147

 
1,220

 
3,442

 
3,661

Net periodic benefit cost
$
13,194

 
$
9,007

 
$
39,583

 
$
27,022

 
$
(6,269
)
 
$
(6,253
)
 
$
(18,806
)
 
$
(18,759
)
Portion of cost charged to expense
$
6,476

 
$
4,433

 
$
19,427

 
$
15,653

 
$
(3,077
)
 
$
(3,078
)
 
$
(9,230
)
 
$
(7,348
)

 
Contributions
 
We have made voluntary contributions of $100 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 nine months ended September 30, 2016 of $5 million and $15 million, respectively, and for the three and nine months ended September 30, 2015 of $5 million and $14 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at September 30, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):
 
 
September 30, 2016
 
December 31, 2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
114,483

 
$
117,385

Equity — Noncontrolling interests
138,789

 
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 $289 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 September 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
 
1,630

 
GWh
Gas
 
193

 
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 nine months ended September 30, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Commodity Contracts
 
 
2016
 
2015
 
2016
 
2015
Gain (loss) recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
(47
)
 
$
(247
)
 
$
13

 
$
(534
)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(1,298
)
 
(1,459
)
 
(3,255
)
 
(5,232
)

(a)
During the three and nine months ended September 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 nine months ended September 30, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 September 30,
 
Nine Months Ended
September 30,
Commodity Contracts
 
 
2016
 
2015
 
2016
 
2015
Net gain recognized in income
 
Operating revenues
 
$
41

 
$
560

 
$
524

 
$
445

Net loss recognized in income
 
Fuel and purchased power (a)
 
(35,103
)
 
(50,909
)
 
(5,145
)
 
(85,099
)
Total
 
 
 
$
(35,062
)
 
$
(50,349
)
 
$
(4,621
)
 
$
(84,654
)

(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed Consolidated Balance Sheets
 
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
 
We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
 
The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of September 30, 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 September 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 September 30, 2016:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
24,894

 
$
(18,816
)
 
$
6,078

 
$
157

 
$
6,235

Investments and other assets
 
4,146

 
(4,146
)
 

 

 

Total assets
 
29,040

 
(22,962
)
 
6,078

 
157

 
6,235

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(59,586
)
 
18,816

 
(40,770
)
 
(4,405
)
 
(45,175
)
Deferred credits and other
 
(62,489
)
 
4,146

 
(58,343
)
 

 
(58,343
)
Total liabilities
 
(122,075
)
 
22,962

 
(99,113
)
 
(4,405
)
 
(103,518
)
Total
 
$
(93,035
)
 
$

 
$
(93,035
)
 
$
(4,248
)
 
$
(97,283
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,405, and cash margin provided to counterparties of $157.
 
As of December 31, 2015:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net</