PINNACLE WEST CAPITAL CORP, 10-Q filed on 7/30/2015
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2015
Jul. 24, 2015
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, 2015 
 
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
 
110,813,659 
Document Fiscal Year Focus
2015 
 
Document Fiscal Period Focus
Q2 
 
Arizona Public Service Company
 
 
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, 2015 
 
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
2015 
 
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, 2015
Jun. 30, 2014
Jun. 30, 2015
Jun. 30, 2014
OPERATING REVENUES
$ 890,648 
$ 906,264 
$ 1,561,867 
$ 1,592,515 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
281,477 
290,854 
504,714 
540,640 
Operations and maintenance
210,965 
211,222 
425,909 
424,104 
Depreciation and amortization
122,739 
105,150 
243,688 
206,922 
Taxes other than income taxes
43,032 
44,004 
86,248 
89,849 
Other expenses
462 
921 
1,651 
1,717 
Total
658,675 
652,151 
1,262,210 
1,263,232 
OPERATING INCOME
231,973 
254,113 
299,657 
329,283 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Allowance for equity funds used during construction
9,345 
7,499 
18,569 
14,941 
Other income (Note 9)
175 
2,781 
410 
5,148 
Other expense (Note 9)
(2,609)
(508)
(6,895)
(5,192)
Total
6,911 
9,772 
12,084 
14,897 
INTEREST EXPENSE
 
 
 
 
Interest charges
48,328 
51,751 
96,727 
104,720 
Allowance for borrowed funds used during construction
(4,322)
(3,790)
(8,538)
(7,560)
Total
44,006 
47,961 
88,189 
97,160 
INCOME BEFORE INCOME TAXES
194,878 
215,924 
223,552 
247,020 
INCOME TAXES
67,371 
74,540 
75,318 
80,945 
NET INCOME
127,507 
141,384 
148,234 
166,075 
Less: Net income attributable to noncontrolling interests (Note 6)
4,605 
8,926 
9,210 
17,851 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
122,902 
132,458 
139,024 
148,224 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
110,986 
110,565 
110,958 
110,546 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
111,460 
111,002 
111,426 
110,925 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 1.11 
$ 1.20 
$ 1.25 
$ 1.34 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 1.10 
$ 1.19 
$ 1.25 
$ 1.34 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 1.19 
$ 1.14 
$ 1.19 
$ 1.14 
Arizona Public Service Company
 
 
 
 
ELECTRIC OPERATING REVENUES
889,723 
905,578 
1,560,391 
1,591,123 
OPERATING EXPENSES
 
 
 
 
Fuel and purchased power
281,477 
290,854 
504,714 
540,640 
Operations and maintenance
208,031 
208,059 
417,978 
416,344 
Depreciation and amortization
122,716 
105,127 
243,642 
206,875 
Income taxes
71,672 
77,371 
83,911 
87,849 
Taxes other than income taxes
43,123 
43,773 
86,109 
89,386 
Total
727,019 
725,184 
1,336,354 
1,341,094 
OPERATING INCOME
162,704 
180,394 
224,037 
250,029 
OTHER INCOME (DEDUCTIONS)
 
 
 
 
Income taxes
2,980 
1,568 
5,131 
2,778 
Allowance for equity funds used during construction
9,345 
7,499 
18,569 
14,941 
Other income (Note 9)
710 
3,221 
1,349 
5,983 
Other expense (Note 9)
(2,449)
(1,477)
(7,803)
(6,533)
Total
10,586 
10,811 
17,246 
17,169 
INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
44,826 
48,462 
90,254 
97,358 
Interest on short-term borrowings
1,705 
1,637 
2,879 
3,050 
Debt discount, premium and expense
1,103 
1,054 
2,237 
2,065 
Allowance for borrowed funds used during construction
(4,311)
(3,790)
(8,527)
(7,560)
Total
43,323 
47,363 
86,843 
94,913 
NET INCOME
129,967 
143,842 
154,440 
172,285 
Less: Net income attributable to noncontrolling interests (Note 6)
4,605 
8,926 
9,210 
17,851 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 125,362 
$ 134,916 
$ 145,230 
$ 154,434 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2015
Jun. 30, 2014
Jun. 30, 2015
Jun. 30, 2014
NET INCOME
$ 127,507 
$ 141,384 
$ 148,234 
$ 166,075 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
25 
40 
(775)
(381)
Reclassification of net realized loss, net of tax benefit
874 
1,955 
2,850 
5,070 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(117)
(1,310)
466 
(853)
Total other comprehensive income
782 
685 
2,541 
3,836 
COMPREHENSIVE INCOME
128,289 
142,069 
150,775 
169,911 
Less: Comprehensive income attributable to noncontrolling interests
4,605 
8,926 
9,210 
17,851 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
123,684 
133,143 
141,565 
152,060 
Arizona Public Service Company
 
 
 
 
NET INCOME
129,967 
143,842 
154,440 
172,285 
Derivative instruments:
 
 
 
 
Net unrealized gain (loss), net of tax benefit (expense)
25 
40 
(775)
(381)
Reclassification of net realized loss, net of tax benefit
874 
1,954 
2,850 
5,070 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(74)
(1,283)
607 
(717)
Total other comprehensive income
825 
711 
2,682 
3,972 
COMPREHENSIVE INCOME
130,792 
144,553 
157,122 
176,257 
Less: Comprehensive income attributable to noncontrolling interests
4,605 
8,926 
9,210 
17,851 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 126,187 
$ 135,627 
$ 147,912 
$ 158,406 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2015
Jun. 30, 2014
Jun. 30, 2015
Jun. 30, 2014
Net unrealized gain (loss), tax benefit (expense)
$ (16)
$ (26)
$ (489)
$ (624)
Reclassification of net realized loss, tax benefit
556 
1,261 
923 
2,584 
Pension and other postretirement benefits activity, tax benefit (expense)
74 
845 
(793)
128 
Arizona Public Service Company
 
 
 
 
Net unrealized gain (loss), tax benefit (expense)
(16)
(26)
(489)
(624)
Reclassification of net realized loss, tax benefit
556 
1,261 
923 
2,584 
Pension and other postretirement benefits activity, tax benefit (expense)
$ 47 
$ 828 
$ (722)
$ 222 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2015
Dec. 31, 2014
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 13,557 
$ 7,604 
Customer and other receivables
289,236 
297,740 
Accrued unbilled revenues
185,216 
100,533 
Allowance for doubtful accounts
(2,518)
(3,094)
Materials and supplies (at average cost)
231,101 
218,889 
Fossil fuel (at average cost)
43,196 
37,097 
Deferred income taxes
77,841 
122,232 
Income tax receivable (Note 5)
3,098 
Assets from risk management activities (Note 7)
14,722 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
Other regulatory assets (Note 3)
134,578 
129,808 
Other current assets
44,827 
38,817 
Total current assets
1,031,756 
973,435 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
18,513 
17,620 
Nuclear decommissioning trust (Note 12)
723,582 
713,866 
Other assets
51,987 
54,047 
Total investments and other assets
794,082 
785,533 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
15,926,594 
15,543,063 
Accumulated depreciation and amortization
(5,497,350)
(5,397,751)
Net
10,429,244 
10,145,312 
Construction work in progress
638,285 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
119,320 
121,255 
Intangible assets, net of accumulated amortization
127,742 
119,755 
Nuclear fuel, net of accumulated amortization
156,608 
125,201 
Total property, plant and equipment
11,471,199 
11,194,330 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,081,113 
1,054,087 
Assets for other postretirement benefits (Note 4)
168,755 
152,290 
Other
154,578 
153,857 
Total deferred debits
1,404,446 
1,360,234 
TOTAL ASSETS
14,701,483 
14,313,532 
CURRENT LIABILITIES
 
 
Accounts payable
326,119 
295,211 
Accrued taxes (Note 5)
155,812 
140,613 
Accrued interest
54,547 
52,603 
Common dividends payable
65,933 
65,790 
Short-term borrowings (Note 2)
157,500 
147,400 
Current maturities of long-term debt (Note 2)
102,723 
383,570 
Customer deposits
72,785 
72,307 
Liabilities from risk management activities (Note 7)
60,673 
59,676 
Deferred fuel and purchased power regulatory liability (Note 3)
16,209 
Liabilities for asset retirements (Note 15)
28,543 
32,462 
Other regulatory liabilities (Note 3)
136,273 
130,549 
Other current liabilities
162,742 
178,962 
Total current liabilities
1,339,859 
1,559,143 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,565,857 
3,031,215 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,614,274 
2,582,636 
Regulatory liabilities (Note 3)
1,016,991 
1,051,196 
Liabilities for asset retirements (Note 15)
419,072 
358,288 
Liabilities for pension benefits (Note 4)
425,002 
453,736 
Liabilities from risk management activities (Note 7)
87,689 
50,602 
Customer advances
120,063 
123,052 
Coal mine reclamation
200,155 
198,292 
Deferred investment tax credit
176,389 
178,607 
Unrecognized tax benefits (Note 5)
14,311 
19,377 
Other
196,178 
188,286 
Total deferred credits and other
5,270,124 
5,204,072 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 110,865,030 and 110,649,762 issued at respective dates
2,526,945 
2,512,970 
Treasury stock at cost; 53,559 and 78,400 shares at respective dates
(1,765)
(3,401)
Total common stock
2,525,180 
2,509,569 
Retained earnings
1,933,256 
1,926,065 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(57,290)
(57,756)
Derivative instruments
(8,310)
(10,385)
Total accumulated other comprehensive loss
(65,600)
(68,141)
Total shareholders’ equity
4,392,836 
4,367,493 
Noncontrolling interests (Note 6)
132,807 
151,609 
Total equity
4,525,643 
4,519,102 
TOTAL LIABILITIES AND EQUITY
14,701,483 
14,313,532 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
7,973 
4,515 
Customer and other receivables
281,609 
297,712 
Accrued unbilled revenues
185,216 
100,533 
Allowance for doubtful accounts
(2,518)
(3,094)
Materials and supplies (at average cost)
231,101 
218,889 
Fossil fuel (at average cost)
43,196 
37,097 
Deferred income taxes
54,789 
55,253 
Assets from risk management activities (Note 7)
14,722 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
Other regulatory assets (Note 3)
134,578 
129,808 
Other current assets
44,168 
38,693 
Total current assets
994,834 
900,117 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
18,513 
17,620 
Nuclear decommissioning trust (Note 12)
723,582 
713,866 
Other assets
33,976 
33,362 
Total investments and other assets
776,071 
764,848 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
15,923,342 
15,539,811 
Accumulated depreciation and amortization
(5,494,236)
(5,394,650)
Net
10,429,106 
10,145,161 
Construction work in progress
636,927 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
119,320 
121,255 
Intangible assets, net of accumulated amortization
127,587 
119,600 
Nuclear fuel, net of accumulated amortization
156,608 
125,201 
Total property, plant and equipment
11,469,548 
11,194,024 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,081,113 
1,054,087 
Assets for other postretirement benefits (Note 4)
165,682 
149,260 
Unamortized debt issue costs
27,843 
24,642 
Other
125,694 
128,026 
Total deferred debits
1,400,332 
1,356,015 
TOTAL ASSETS
14,640,785 
14,215,004 
CURRENT LIABILITIES
 
 
Accounts payable
321,860 
289,930 
Accrued taxes (Note 5)
199,492 
131,110 
Accrued interest
54,314 
52,358 
Common dividends payable
65,900 
65,800 
Short-term borrowings (Note 2)
157,500 
147,400 
Current maturities of long-term debt (Note 2)
102,723 
383,570 
Customer deposits
72,785 
72,307 
Liabilities from risk management activities (Note 7)
60,673 
59,676 
Deferred fuel and purchased power regulatory liability (Note 3)
16,209 
Liabilities for asset retirements (Note 15)
28,543 
32,462 
Other regulatory liabilities (Note 3)
136,273 
130,549 
Other current liabilities
132,800 
167,302 
Total current liabilities
1,349,072 
1,532,464 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,601,294 
2,571,365 
Regulatory liabilities (Note 3)
1,016,991 
1,051,196 
Liabilities for asset retirements (Note 15)
419,072 
358,288 
Liabilities for pension benefits (Note 4)
397,160 
424,508 
Liabilities from risk management activities (Note 7)
87,689 
50,602 
Customer advances
120,063 
123,052 
Coal mine reclamation
200,155 
198,292 
Deferred investment tax credit
176,389 
178,607 
Unrecognized tax benefits (Note 5)
45,305 
45,740 
Other
159,574 
144,823 
Total deferred credits and other
5,223,692 
5,146,473 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
1,982,150 
1,968,718 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(37,341)
(37,948)
Derivative instruments
(8,310)
(10,385)
Total accumulated other comprehensive loss
(45,651)
(48,333)
Total shareholders’ equity
4,494,357 
4,478,243 
Noncontrolling interests (Note 6)
132,807 
151,609 
Total equity
4,627,164 
4,629,852 
Long-term debt less current maturities (Note 2)
3,440,857 
2,906,215 
Total capitalization
8,068,021 
7,536,067 
TOTAL LIABILITIES AND EQUITY
$ 14,640,785 
$ 14,215,004 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Jun. 30, 2015
Dec. 31, 2014
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
110,865,030 
110,649,762 
Treasury stock at cost, shares
53,559 
78,400 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2015
Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 148,234 
$ 166,075 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
282,218 
246,371 
Deferred fuel and purchased power
11,711 
1,315 
Deferred fuel and purchased power amortization
11,424 
18,399 
Allowance for equity funds used during construction
(18,569)
(14,941)
Deferred income taxes
65,377 
32,611 
Deferred investment tax credit
(2,218)
28,875 
Change in derivative instruments fair value
(225)
49 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(17,402)
(64,986)
Accrued unbilled revenues
(84,683)
(75,648)
Materials, supplies and fossil fuel
(18,311)
(9,435)
Income tax receivable
3,098 
135,517 
Other current assets
(8,728)
(14,038)
Accounts payable
36,634 
30,725 
Accrued taxes
15,199 
30,709 
Other current liabilities
(13,138)
19,978 
Change in margin and collateral accounts — assets
(4,552)
(2,107)
Change in margin and collateral accounts — liabilities
26,853 
(22,425)
Change in other long-term assets
(4,817)
(19,243)
Change in other long-term liabilities
(33,811)
(22,735)
Net cash flow provided by operating activities
394,294 
465,066 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(531,035)
(388,752)
Contributions in aid of construction
41,010 
12,646 
Allowance for borrowed funds used during construction
(8,538)
(7,560)
Proceeds from nuclear decommissioning trust sales
225,779 
199,224 
Investment in nuclear decommissioning trust
(234,651)
(207,848)
Other
(2,068)
(678)
Net cash flow used for investing activities
(509,503)
(392,968)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
600,000 
535,975 
Repayment of long-term debt
(344,847)
(503,583)
Short-term borrowings and payments — net
10,100 
23,525 
Dividends paid on common stock
(128,241)
(125,138)
Common stock equity issuance
12,161 
12,625 
Distributions to noncontrolling interest
(28,012)
(15,869)
Other
Net cash flow provided by (used for) financing activities
121,162 
(72,463)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
5,953 
(365)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
7,604 
9,526 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
13,557 
9,161 
Cash paid (received) during the period for:
 
 
Income taxes, net of refunds
1,834 
(131,154)
Interest, net of amounts capitalized
84,008 
90,707 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
38,985 
19,668 
Dividends declared but not yet paid
65,933 
62,656 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
154,440 
172,285 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
282,172 
246,324 
Deferred fuel and purchased power
11,711 
1,315 
Deferred fuel and purchased power amortization
11,424 
18,399 
Allowance for equity funds used during construction
(18,569)
(14,941)
Deferred income taxes
24,442 
34,133 
Deferred investment tax credit
(2,218)
28,875 
Change in derivative instruments fair value
(225)
49 
Changes in current assets and liabilities:
 
 
Customer and other receivables
(9,250)
(65,603)
Accrued unbilled revenues
(84,683)
(75,648)
Materials, supplies and fossil fuel
(18,311)
(9,435)
Income tax receivable
135,179 
Other current assets
(8,193)
(14,120)
Accounts payable
37,656 
28,465 
Accrued taxes
68,382 
38,381 
Other current liabilities
(31,408)
31,296 
Change in margin and collateral accounts — assets
(4,552)
(2,107)
Change in margin and collateral accounts — liabilities
26,853 
(22,425)
Change in other long-term assets
(6,765)
(18,703)
Change in other long-term liabilities
(27,136)
(24,467)
Net cash flow provided by operating activities
405,770 
487,252 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(530,850)
(388,752)
Contributions in aid of construction
41,010 
12,646 
Allowance for borrowed funds used during construction
(8,527)
(7,560)
Proceeds from nuclear decommissioning trust sales
225,779 
199,224 
Investment in nuclear decommissioning trust
(234,651)
(207,848)
Other
(614)
(678)
Net cash flow used for investing activities
(507,853)
(392,968)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
600,000 
535,975 
Repayment of long-term debt
(344,847)
(503,583)
Short-term borrowings and payments — net
10,100 
19,650 
Dividends paid on common stock
(131,700)
(125,100)
Distributions to noncontrolling interest
(28,012)
(15,869)
Net cash flow provided by (used for) financing activities
105,541 
(88,927)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
3,458 
5,357 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
4,515 
3,725 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
7,973 
9,082 
Cash paid (received) during the period for:
 
 
Income taxes, net of refunds
184 
(134,399)
Interest, net of amounts capitalized
82,651 
88,461 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
38,985 
19,668 
Dividends declared but not yet paid
$ 65,900 
$ 62,600 
CONDENSED CONSOLIDATED STATEMENTS OF 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
Beginning balance at Dec. 31, 2013
$ 4,340,460 
$ 2,491,558 
$ (4,308)
$ 1,785,273 
$ (78,053)
$ 145,990 
$ 4,454,874 
$ 178,162 
$ 2,379,696 
$ 1,804,398 
$ (53,372)
$ 145,990 
Beginning balance (in shares) at Dec. 31, 2013
 
110,280,703 
98,944 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
166,075 
 
 
148,224 
 
17,851 
172,285 
 
 
154,434 
 
17,851 
Other comprehensive income
3,836 
 
 
 
3,836 
 
3,972 
 
 
 
3,972 
 
Dividends on common stock
(125,265)
 
 
(125,265)
 
 
(125,200)
 
 
(125,200)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
149,753 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
8,506 
8,506 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(82,474)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,535)
 
(4,535)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
157,594 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
8,654 
 
8,654 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(15,869)
 
 
 
 
(15,869)
(15,869)
 
 
 
 
(15,869)
Ending balance at Jun. 30, 2014
4,381,862 
2,500,064 
(189)
1,808,232 
(74,217)
147,972 
4,490,065 
178,162 
2,379,696 
1,833,635 
(49,400)
147,972 
Ending balance (in shares) at Jun. 30, 2014
 
110,430,456 
23,824 
 
 
 
 
71,264,947 
 
 
 
 
Beginning balance at Mar. 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
141,384 
 
 
 
 
 
143,842 
 
 
 
 
 
Other comprehensive income
685 
 
 
 
 
 
711 
 
 
 
 
 
Ending balance at Jun. 30, 2014
4,381,862 
 
 
 
 
 
4,490,065 
178,162 
2,379,696 
 
 
 
Ending balance (in shares) at Jun. 30, 2014
 
 
 
 
 
 
 
71,264,947 
 
 
 
 
Beginning balance 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 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
148,234 
 
 
139,024 
 
9,210 
154,440 
 
 
145,230 
 
9,210 
Other comprehensive income
2,541 
 
 
 
2,541 
 
2,682 
 
 
 
2,682 
 
Dividends on common stock
(131,833)
 
 
(131,833)
 
 
(131,800)
 
 
(131,800)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
215,268 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
13,975 
13,975 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(93,280)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(6,096)
 
(6,096)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
118,121 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
7,732 
 
7,732 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(28,012)
 
 
 
 
(28,012)
(28,012)
 
 
 
 
(28,012)
Ending balance at Jun. 30, 2015
4,525,643 
2,526,945 
(1,765)
1,933,256 
(65,600)
132,807 
4,627,164 
178,162 
2,379,696 
1,982,150 
(45,651)
132,807 
Ending balance (in shares) at Jun. 30, 2015
110,865,030 
110,865,030 
53,559 
 
 
 
 
71,264,947 
 
 
 
 
Beginning balance at Mar. 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
127,507 
 
 
 
 
 
129,967 
 
 
 
 
 
Other comprehensive income
782 
 
 
 
 
 
825 
 
 
 
 
 
Ending balance at Jun. 30, 2015
$ 4,525,643 
 
 
 
 
 
$ 4,627,164 
$ 178,162 
$ 2,379,696 
 
 
 
Ending balance (in shares) at Jun. 30, 2015
110,865,030 
 
 
 
 
 
 
71,264,947 
 
 
 
 
Consolidation and Nature of Operations
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado").  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 6 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.
 
Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.
 
Our condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission ("SEC").  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.
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2015
 
2014
Cash paid (received) during the period for:
 
 
 
Income taxes, net of refunds
$
1,834

 
$
(131,154
)
Interest, net of amounts capitalized
84,008

 
90,707

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
38,985

 
$
19,668

Dividends accrued but not yet paid
65,933

 
62,656

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.
 
Pinnacle West
 
Pinnacle West's $200 million revolving credit facility matures in May 2019.  At June 30, 2015, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the size 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, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS
 
On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020.  The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash used to fund capital expenditures.

On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% Notes due May 15, 2015.

On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness.
 
On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

At June 30, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million facility that matures in May 2019.  APS may increase the size of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.
 
The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2015, APS had $158 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.
 
See "Financial Assurances" in Note 8 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 represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 
As of June 30, 2015
 
As of December 31, 2014
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125

 
$
125

 
$
125

 
$
125

APS
3,544

 
3,818

 
3,290

 
3,714

Total
$
3,669

 
$
3,943

 
$
3,415

 
$
3,839


 
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, 2015, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.3 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, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
Settlement Agreement
 
The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs ("Base Fuel Rate") from $0.03757 to $0.03207 per kilowatt hour ("kWh"); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff ("RES") surcharge to base rates in an estimated amount of $36.8 million.
  
Other key provisions of the 2012 Settlement Agreement include the following:
 
An authorized return on common equity of 10.0%;

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

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

Deferral of 100% in all years if Arizona property tax rates decrease;
 
A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);
 
Implementation of a Lost Fixed Cost Recovery ("LFCR") rate mechanism to support energy efficiency and distributed renewable generation;
 
Modifications to the Environmental Improvement Surcharge ("EIS") to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
 
Modifications to the Power Supply Adjustor ("PSA"), including the elimination of the 90/10 sharing provision;
 
A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge ("DSMAC") to recoup capital expenditures not required under the terms of APS’s 2009 retail rate case settlement agreement (the "2009 Settlement Agreement");
 
Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;
 
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.
 
On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.
 
In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 Megawatt ("MW") of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with an appropriate amount of distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.
 
On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million.
 
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.
 
On June 1, 2012, APS filed its 2013 DSM Plan.  In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.
 
On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for 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. Consistent with the ACC’s March 11, 2014 order, APS intends to continue its other approved DSM programs in 2015.

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. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.
 
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 rule making has not been initiated and there has been no additional action on the draft to date.
 
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 2015 and 2014 (dollars in millions):
 
 
Six Months Ended 
 June 30,
 
2015
 
2014
Beginning balance
$
7

 
$
21

Deferred fuel and purchased power costs — current period
(12
)
 
(1
)
Amounts charged to customers
(11
)
 
(19
)
Ending balance
$
(16
)
 
$
1


 
The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh.  Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016.
 
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 Charge because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.
 
Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 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, 2014.

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.

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 or if metering is unavailable, through accepted estimating techniques.
 
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.

Deregulation
 
On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a "market" basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and early 2015. No further action has been taken by the ACC to date.

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 electricity 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 electrical grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. 
 
On April 2, 2015, APS filed an application with the ACC seeking to increase the fixed grid access charge to $3.00 per kilowatt, or approximately $21 per month for a typical new residential solar customer, effective August 1. Customers who installed rooftop solar panels prior to January 1, 2014 would continue to be grandfathered and would not pay a grid access charge, and those who installed panels between January 1, 2014 and the effective date of the requested change would continue paying a charge of $0.70 per kilowatt. Solar customers that take electric service under APS’s demand-based ECT-2 residential rate, an existing rate that includes time-of-use rates with a demand charge, are not subject to the grid access charge.

APS cannot predict the outcome of this filing. The proposed grid access charge adjustment is designed to moderate the cost shift discussed above on an interim basis until the issue is further addressed in APS’s next general rate case.

On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.
   
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 $74 million as of June 30, 2015 and is being amortized in rates over 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 will actively participate in the proceeding. We cannot predict when or how this appeal 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.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE are unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Cholla

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Unit 2 of the Cholla Power Plant ("Cholla") by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("EPA") approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. On April 14, 2015, the ACC approved APS's proposed retirement of Cholla Unit 2 in accordance with the ACC's Integrated Resource Planning rules. The ACC expressly stated that this approval does not imply any specific treatment or recommendation for rate making purposes.
If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($125 million as of June 30, 2015), 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 millions):
 
 
Remaining
Amortization Period
 
June 30, 2015
 
December 31, 2014
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension benefits
(a)
 
$

 
$
505

 
$

 
$
485

Income taxes — allowance for funds used during construction ("AFUDC") equity
2044
 
5

 
122

 
5

 
118

Deferred fuel and purchased power — mark-to-market (Note 7)
2018
 
53

 
62

 
51

 
46

Transmission vegetation management
2016
 
9

 

 
9

 
5

Coal reclamation
2026
 

 
6

 

 
7

Palo Verde VIEs (Note 6)
2046
 

 
26

 

 
35

Deferred compensation
2036
 

 
36

 

 
34

Deferred fuel and purchased power (b) (c)
2015
 

 

 
7

 

Tax expense of Medicare subsidy
2024
 
2

 
13

 
2

 
14

Loss on reacquired debt
2034
 
1

 
16

 
1

 
16

Income taxes — investment tax credit basis adjustment
2044
 
2

 
46

 
2

 
46

Pension and other postretirement benefits deferral
2015
 

 

 
4

 

Four Corners cost deferral
2024
 
7

 
67

 
7

 
70

Lost fixed cost recovery (b)
2016
 
45

 

 
38

 

Retired power plant costs
2033
 
10

 
131

 
10

 
136

Deferred property taxes
(d)
 

 
40

 

 
30

Other
Various
 
1

 
11

 
2

 
12

Total regulatory assets (e)
 
 
$
135

 
$
1,081

 
$
138

 
$
1,054


(a)
This asset represents the future recovery of pension and other postretirement 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)
Subject to a carrying charge.
(d)
Per the provision of the 2012 Settlement Agreement.
(e)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."

The detail of regulatory liabilities is as follows (dollars in millions):
 
 
Remaining
Amortization Period
 
June 30, 2015
 
December 31, 2014
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
44

 
$
245

 
$
31

 
$
273

Asset retirement obligations
2044
 

 
272

 

 
296

Renewable energy standard (b)
2017
 
29

 
20

 
25

 
23

Income taxes — change in rates
2043
 
1

 
71

 

 
72

Spent nuclear fuel
2047
 
3

 
68

 
5

 
66

Deferred gains on utility property
2019
 
2

 
7

 
2

 
8

Income taxes — deferred investment tax credit
2043
 
3

 
92

 
4

 
93

Deferred fuel and purchased power (b) (c)
2016
 
16

 

 

 

Demand side management (b)
2017
 
8

 
27

 
31

 

Other postretirement benefits
(d)
 
33

 
189

 
32

 
199

Other
Various
 
13

 
26

 
1

 
21

Total regulatory liabilities
 
 
$
152

 
$
1,017

 
$
131

 
$
1,051


(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 Benefits
Retirement Plans and Other Benefits
Retirement Plans and Other 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 these plan changes in 2014, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new 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 amortized approximately $2 million and $4 million for the three and six months ended June 30, 2015 and 2014, 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 millions):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
Service cost — benefits earned during the period
$
14

 
$
12

 
$
30

 
$
27

 
$
4

 
$
5

 
$
8

 
$
9

Interest cost on benefit obligation
31

 
33

 
62

 
65

 
7

 
11

 
14

 
23

Expected return on plan assets
(45
)
 
(39
)
 
(90
)
 
(79
)
 
(9
)
 
(13
)
 
(18
)
 
(25
)
Amortization of:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Prior service cost

 

 

 

 
(9
)
 

 
(19
)
 

Net actuarial loss
8

 
3

 
16

 
5

 

 

 
2

 

Net periodic benefit cost
$
8

 
$
9

 
$
18

 
$
18

 
$
(7
)
 
$
3

 
$
(13
)
 
$
7

Portion of cost charged to expense
$
5

 
$
5

 
$
11

 
$
11

 
$
(2
)
 
$
3

 
$
(4
)
 
$
5


 
Contributions
 
We have made voluntary contributions of $80 million to our pension plan year-to-date in 2015. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.
Income Taxes
Income Taxes
Income Taxes
 
On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations were accounted for in the Condensed Consolidated Balance Sheets as of December 31, 2014.

Net income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 6).  As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.
 
As of June 30, 2015, the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS.  With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2009.
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. These lease agreements include fixed rate renewal periods. On July 7, 2014, APS notified the lessor trust entities of APS's intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining 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 $49 million in 2015, $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 renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to 2 years, or return the assets to the lessors.

The fixed rate renewal periods 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.  Predominately due to the fixed rate renewal periods, 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 and interest expense, resulting in an increase in net income for the three and six months ended June 30, 2015 of $5 million and $9 million, respectively, and for the three and six months ended June 30, 2014 of $9 million and $18 million, respectively, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased because of lower rent income resulting from the July 7, 2014 lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.
 
Our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):
 
 
June 30, 2015
 
December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
119

 
$
121

Current maturities of long-term debt
1

 
13

Equity — Noncontrolling interests
133

 
152


 
Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders.  Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.
 
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, assume the VIEs’ debt, 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 had occurred as of June 30, 2015, APS would have been required to pay the noncontrolling equity participants approximately $114 million and assume $1 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.
 
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.
 
On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow hedges.  This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts.  For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through OCI, but are deferred through the PSA.  The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA.  Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.
 
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 11 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
 
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time.  We assess hedge effectiveness both at inception and on a continuing basis.  These assessments exclude the time value of certain options.  For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings.  We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment.  As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of June 30, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
3,808

 
GWh
Gas
 
188

 
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, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Commodity Contracts
 
 
2015
 
2014
 
2015
 
2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
41

 
$
66

 
$
(286
)
 
$
243

Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(1,430
)
 
(3,216
)
 
(3,773
)
 
(7,654
)

(a)
During the three and six months ended June 30, 2015 and 2014, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $4 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 June 30,
 
Six Months Ended June 30,
Commodity Contracts
 
 
2015
 
2014
 
2015
 
2014
Net gain (loss) recognized in income
 
Operating revenues (a)
 
$
(66
)
 
$
155

 
$
(114
)
 
$
63

Net gain (loss) recognized in income
 
Fuel and purchased power (a)
 
10,613

 
4,805

 
(34,190
)
 
22,912

Total
 
 
 
$
10,547

 
$
4,960

 
$
(34,304
)
 
$
22,975


(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, 2015 and December 31, 2014, each include gross liabilities of $4 million 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, 2015 and December 31, 2014.  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, 2015:
(Dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance  Sheet
Current assets
 
$
25,485

 
$
(12,925
)
 
$
12,560

 
$
2,162

 
$
14,722

Investments and other assets
 
20,560

 
(4,787
)
 
15,773

 
2,740

 
18,513

Total assets
 
46,045

 
(17,712
)
 
28,333

 
4,902

 
33,235

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(83,203
)
 
30,626

 
(52,577
)
 
(8,096
)
 
(60,673
)
Deferred credits and other
 
(92,475
)
 
4,786

 
(87,689
)
 

 
(87,689
)
Total liabilities
 
(175,678
)
 
35,412

 
(140,266
)
 
(8,096
)
 
(148,362
)
Total
 
$
(129,633
)
 
$
17,700

 
$
(111,933
)
 
$
(3,194
)
 
$
(115,127
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $17,700.
(c)
Represents cash collateral, cash margin and option premiums that are 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 $8,096, cash margin provided to counterparties of $2,162 and option premiums of $2,740.
 
As of December 31, 2014:
(Dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance  Sheet
Current assets
 
$
28,562

 
$
(15,127
)
 
$
13,435

 
$
350

 
$
13,785

Investments and other assets
 
24,810

 
(7,190
)
 
17,620

 

 
17,620

Total assets
 
53,372

 
(22,317
)
 
31,055

 
350

 
31,405

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(86,062
)
 
33,829

 
(52,233
)
 
(7,443
)
 
(59,676
)
Deferred credits and other
 
(82,990
)
 
32,388

 
(50,602
)
 

 
(50,602
)
Total liabilities
 
(169,052
)
 
66,217

 
(102,835
)
 
(7,443
)
 
(110,278
)
Total
 
$
(115,680
)
 
$