PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/1/2015
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2015
Apr. 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
Mar. 31, 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
 
110,748,842 
Document Fiscal Year Focus
2015 
 
Document Fiscal Period Focus
Q1 
 
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
Mar. 31, 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
Q1 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
OPERATING REVENUES
$ 671,219 
$ 686,251 
OPERATING EXPENSES
 
 
Fuel and purchased power
223,237 
249,786 
Operations and maintenance
214,944 
212,882 
Depreciation and amortization
120,949 
101,772 
Taxes other than income taxes
43,216 
45,845 
Other expenses
1,189 
796 
Total
603,535 
611,081 
OPERATING INCOME
67,684 
75,170 
OTHER INCOME (DEDUCTIONS)
 
 
Allowance for equity funds used during construction
9,224 
7,442 
Other income
235 
2,367 
Other expense
(4,286)
(4,684)
Total
5,173 
5,125 
INTEREST EXPENSE
 
 
Interest charges
48,399 
52,969 
Allowance for borrowed funds used during construction
(4,216)
(3,770)
Total
44,183 
49,199 
INCOME BEFORE INCOME TAXES
28,674 
31,096 
INCOME TAXES
7,947 
6,405 
NET INCOME
20,727 
24,691 
Less: Net income attributable to noncontrolling interests (Note 6)
4,605 
8,925 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
16,122 
15,766 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
110,916 
110,257 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
111,377 
110,888 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.15 
$ 0.14 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 0.14 
$ 0.14 
Arizona Public Service Company
 
 
ELECTRIC OPERATING REVENUES
670,668 
685,545 
OPERATING EXPENSES
 
 
Fuel and purchased power
223,237 
249,786 
Operations and maintenance
209,947 
208,285 
Depreciation and amortization
120,926 
101,748 
Income taxes
12,239 
10,478 
Taxes other than income taxes
42,986 
45,613 
Total
609,335 
615,910 
OPERATING INCOME
61,333 
69,635 
OTHER INCOME (DEDUCTIONS)
 
 
Income taxes
2,151 
1,210 
Allowance for equity funds used during construction
9,224 
7,442 
Other income
639 
2,762 
Other expense
(5,354)
(5,056)
Total
6,660 
6,358 
INTEREST EXPENSE
 
 
Interest on long-term debt
45,428 
48,896 
Interest on short-term borrowings
1,174 
1,413 
Debt discount, premium and expense
1,134 
1,011 
Allowance for borrowed funds used during construction
(4,216)
(3,770)
Total
43,520 
47,550 
NET INCOME
24,473 
28,443 
Less: Net income attributable to noncontrolling interests (Note 6)
4,605 
8,925 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 19,868 
$ 19,518 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
NET INCOME
$ 20,727 
$ 24,691 
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(800)
(422)
Reclassification of net realized loss, net of tax benefit
1,976 
3,116 
Pension and other postretirement benefits activity, net of tax benefit (expense)
583 
457 
Total other comprehensive income
1,759 
3,151 
COMPREHENSIVE INCOME
22,486 
27,842 
Less: Comprehensive income attributable to noncontrolling interests
4,605 
8,925 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
17,881 
18,917 
Arizona Public Service Company
 
 
NET INCOME
24,473 
28,443 
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(800)
(421)
Reclassification of net realized loss, net of tax benefit
1,976 
3,116 
Pension and other postretirement benefits activity, net of tax benefit (expense)
681 
566 
Total other comprehensive income
1,857 
3,261 
COMPREHENSIVE INCOME
26,330 
31,704 
Less: Comprehensive income attributable to noncontrolling interests
4,605 
8,925 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 21,725 
$ 22,779 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Net unrealized gain (loss), tax benefit (expense)
$ (473)
$ (599)
Reclassification of net realized loss, tax benefit
367 
1,323 
Pension and other postretirement benefits activity, tax benefit (expense)
(867)
(718)
Arizona Public Service Company
 
 
Net unrealized gain (loss), tax benefit (expense)
(473)
(599)
Reclassification of net realized loss, tax benefit
367 
1,323 
Pension and other postretirement benefits activity, tax benefit (expense)
$ (769)
$ (606)
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 11,664 
$ 7,604 
Customer and other receivables
242,457 
297,740 
Accrued unbilled revenues
94,400 
100,533 
Allowance for doubtful accounts
(2,560)
(3,094)
Materials and supplies (at average cost)
221,276 
218,889 
Fossil fuel (at average cost)
44,705 
37,097 
Deferred income taxes
113,521 
122,232 
Income tax receivable (Note 5)
3,317 
3,098 
Assets from risk management activities (Note 7)
13,658 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
Other regulatory assets (Note 3)
147,869 
129,808 
Other current assets
45,135 
38,817 
Total current assets
935,442 
973,435 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
18,444 
17,620 
Nuclear decommissioning trust (Note 12)
727,342 
713,866 
Other assets
51,449 
54,047 
Total investments and other assets
797,235 
785,533 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
15,551,726 
15,543,063 
Accumulated depreciation and amortization
(5,452,860)
(5,397,751)
Net
10,098,866 
10,145,312 
Construction work in progress
841,426 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
120,287 
121,255 
Intangible assets, net of accumulated amortization
127,620 
119,755 
Nuclear fuel, net of accumulated amortization
136,557 
125,201 
Total property, plant and equipment
11,324,756 
11,194,330 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,067,830 
1,054,087 
Assets for other postretirement benefits (Note 4)
156,192 
152,290 
Other
154,248 
153,857 
Total deferred debits
1,378,270 
1,360,234 
TOTAL ASSETS
14,435,703 
14,313,532 
CURRENT LIABILITIES
 
 
Accounts payable
271,489 
295,211 
Accrued taxes (Note 5)
188,724 
140,613 
Accrued interest
42,096 
52,603 
Common dividends payable
65,790 
Short-term borrowings (Note 2)
44,500 
147,400 
Current maturities of long-term debt (Note 2)
383,570 
383,570 
Customer deposits
72,561 
72,307 
Liabilities from risk management activities (Note 7)
62,303 
59,676 
Deferred fuel and purchased power regulatory liability (Note 3)
16,359 
Liabilities for asset retirements (Note 15)
28,918 
32,462 
Other regulatory liabilities (Note 3)
113,024 
130,549 
Other current liabilities
150,432 
178,962 
Total current liabilities
1,373,976 
1,559,143 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,281,319 
3,031,215 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,586,180 
2,582,636 
Regulatory liabilities (Note 3)
1,070,106 
1,051,196 
Liabilities for asset retirements (Note 15)
379,263 
358,288 
Liabilities for pension benefits (Note 4)
412,552 
453,736 
Liabilities from risk management activities (Note 7)
73,827 
50,602 
Customer advances
122,259 
123,052 
Coal mine reclamation
199,218 
198,292 
Deferred investment tax credit
178,313 
178,607 
Unrecognized tax benefits (Note 5)
14,196 
19,377 
Other
191,487 
188,286 
Total deferred credits and other
5,227,401 
5,204,072 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 110,809,492 and 110,649,762 issued at respective dates
2,523,247 
2,512,970 
Treasury stock at cost; 61,784 and 78,400 shares at respective dates
(2,266)
(3,401)
Total common stock
2,520,981 
2,509,569 
Retained earnings
1,942,194 
1,926,065 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(57,173)
(57,756)
Derivative instruments
(9,209)
(10,385)
Total accumulated other comprehensive loss
(66,382)
(68,141)
Total shareholders’ equity
4,396,793 
4,367,493 
Noncontrolling interests (Note 6)
156,214 
151,609 
Total equity
4,553,007 
4,519,102 
TOTAL LIABILITIES AND EQUITY
14,435,703 
14,313,532 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
6,083 
4,515 
Customer and other receivables
238,863 
297,712 
Accrued unbilled revenues
94,400 
100,533 
Allowance for doubtful accounts
(2,560)
(3,094)
Materials and supplies (at average cost)
221,276 
218,889 
Fossil fuel (at average cost)
44,705 
37,097 
Assets from risk management activities (Note 7)
13,658 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
Other regulatory assets (Note 3)
147,869 
129,808 
Deferred income taxes
54,789 
55,253 
Other current assets
44,496 
38,693 
Total current assets
863,579 
900,117 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 7)
18,444 
17,620 
Nuclear decommissioning trust (Note 12)
727,342 
713,866 
Other assets
33,832 
33,362 
Total investments and other assets
779,618 
764,848 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
15,548,474 
15,539,811 
Accumulated depreciation and amortization
(5,449,753)
(5,394,650)
Net
10,098,721 
10,145,161 
Construction work in progress
840,928 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)
120,287 
121,255 
Intangible assets, net of accumulated amortization
127,465 
119,600 
Nuclear fuel, net of accumulated amortization
136,557 
125,201 
Total property, plant and equipment
11,323,958 
11,194,024 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,067,830 
1,054,087 
Assets for other postretirement benefits (Note 4)
153,156 
149,260 
Unamortized debt issue costs
25,948 
24,642 
Other
127,190 
128,026 
Total deferred debits
1,374,124 
1,356,015 
TOTAL ASSETS
14,341,279 
14,215,004 
CURRENT LIABILITIES
 
 
Accounts payable
265,779 
289,930 
Accrued taxes (Note 5)
190,167 
131,110 
Accrued interest
41,919 
52,358 
Common dividends payable
65,800 
Short-term borrowings (Note 2)
44,500 
147,400 
Current maturities of long-term debt (Note 2)
383,570 
383,570 
Customer deposits
72,561 
72,307 
Liabilities from risk management activities (Note 7)
62,303 
59,676 
Deferred fuel and purchased power regulatory liability (Note 3)
16,359 
Liabilities for asset retirements (Note 15)
28,918 
32,462 
Other regulatory liabilities (Note 3)
113,024 
130,549 
Other current liabilities
130,161 
167,302 
Total current liabilities
1,349,261 
1,532,464 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,573,876 
2,571,365 
Regulatory liabilities (Note 3)
1,070,106 
1,051,196 
Liabilities for asset retirements (Note 15)
379,263 
358,288 
Liabilities for pension benefits (Note 4)
384,215 
424,508 
Liabilities from risk management activities (Note 7)
73,827 
50,602 
Customer advances
122,259 
123,052 
Coal mine reclamation
199,218 
198,292 
Deferred investment tax credit
178,313 
178,607 
Unrecognized tax benefits (Note 5)
45,190 
45,740 
Other
153,249 
144,823 
Total deferred credits and other
5,179,516 
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
1,988,587 
1,968,718 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(37,267)
(37,948)
Derivative instruments
(9,209)
(10,385)
Total accumulated other comprehensive loss
(46,476)
(48,333)
Total shareholders’ equity
4,499,969 
4,478,243 
Noncontrolling interests (Note 6)
156,214 
151,609 
Total equity
4,656,183 
4,629,852 
Long-term debt less current maturities (Note 2)
3,156,319 
2,906,215 
Total capitalization
7,812,502 
7,536,067 
TOTAL LIABILITIES AND EQUITY
$ 14,341,279 
$ 14,215,004 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Mar. 31, 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
110,809,492 
110,649,762 
Treasury stock at cost, shares
61,784 
78,400 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 20,727 
$ 24,691 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
141,494 
122,394 
Deferred fuel and purchased power
17,671 
31,630 
Deferred fuel and purchased power amortization
5,614 
8,022 
Allowance for equity funds used during construction
(9,224)
(7,442)
Deferred income taxes
6,978 
8,810 
Deferred investment tax credit
(294)
(247)
Change in derivative instruments fair value
(104)
(13)
Changes in current assets and liabilities:
 
 
Customer and other receivables
39,174 
25,986 
Accrued unbilled revenues
6,133 
7,889 
Materials, supplies and fossil fuel
(9,995)
(187)
Income tax receivable
(219)
130,870 
Other current assets
(9,631)
(10,669)
Accounts payable
(35,673)
(50,990)
Accrued taxes
48,111 
48,139 
Other current liabilities
(56,747)
(15,864)
Change in margin and collateral accounts — assets
(276)
(290)
Change in margin and collateral accounts — liabilities
(13,420)
(29,075)
Change in other long-term assets
(14,432)
(9,636)
Change in other long-term liabilities
8,261 
(34,861)
Net cash flow provided by operating activities
144,148 
249,157 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(251,041)
(207,459)
Contributions in aid of construction
27,222 
7,736 
Allowance for borrowed funds used during construction
(4,216)
(3,770)
Proceeds from nuclear decommissioning trust sales
115,282 
103,157 
Investment in nuclear decommissioning trust
(119,594)
(107,470)
Other
(470)
(702)
Net cash flow used for investing activities
(232,817)
(208,508)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
250,000 
250,000 
Short-term borrowings and payments — net
(102,900)
(143,625)
Dividends paid on common stock
(64,061)
(62,520)
Dividends paid on common stock
9,690 
9,390 
Other
Net cash flow provided by financing activities
92,729 
53,246 
NET INCREASE IN CASH AND CASH EQUIVALENTS
4,060 
93,895 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
7,604 
9,526 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
11,664 
103,421 
Cash paid (received) during the period for:
 
 
Income taxes, net of refunds
1,832 
(131,078)
Interest, net of amounts capitalized
53,555 
49,147 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
56,165 
24,908 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
24,473 
28,443 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
141,471 
122,370 
Deferred fuel and purchased power
17,671 
31,630 
Deferred fuel and purchased power amortization
5,614 
8,022 
Allowance for equity funds used during construction
(9,224)
(7,442)
Deferred income taxes
2,427 
8,696 
Deferred investment tax credit
(294)
(247)
Change in derivative instruments fair value
(104)
(13)
Changes in current assets and liabilities:
 
 
Customer and other receivables
43,070 
25,749 
Accrued unbilled revenues
6,133 
7,889 
Materials, supplies and fossil fuel
(9,995)
(187)
Income tax receivable
134,890 
Other current assets
(9,116)
(10,807)
Accounts payable
(35,604)
(52,621)
Accrued taxes
59,057 
50,580 
Other current liabilities
(65,290)
(5,257)
Change in margin and collateral accounts — assets
(276)
(290)
Change in margin and collateral accounts — liabilities
(13,421)
(29,075)
Change in other long-term assets
(17,559)
(10,439)
Change in other long-term liabilities
13,941 
(28,083)
Net cash flow provided by operating activities
152,974 
273,808 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(250,930)
(207,459)
Contributions in aid of construction
27,222 
7,736 
Allowance for borrowed funds used during construction
(4,216)
(3,770)
Proceeds from nuclear decommissioning trust sales
115,282 
103,157 
Investment in nuclear decommissioning trust
(119,594)
(107,470)
Other
(470)
(702)
Net cash flow used for investing activities
(232,706)
(208,508)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
250,000 
250,000 
Short-term borrowings and payments — net
(102,900)
(153,125)
Dividends paid on common stock
(65,800)
(62,500)
Net cash flow provided by financing activities
81,300 
34,375 
NET INCREASE IN CASH AND CASH EQUIVALENTS
1,568 
99,675 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
4,515 
3,725 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
6,083 
103,400 
Cash paid (received) during the period for:
 
 
Income taxes, net of refunds
184 
(134,323)
Interest, net of amounts capitalized
52,825 
47,464 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 56,165 
$ 24,908 
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) Statement (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
24,691 
 
 
15,766 
 
8,925 
28,443 
 
 
19,518 
 
8,925 
Other comprehensive income
3,151 
 
 
 
3,151 
 
3,261 
 
 
 
3,261 
 
Issuance of common stock (in shares)
 
108,362 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
5,927 
5,927 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(82,474)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,535)
 
(4,535)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
146,590 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
8,007 
 
7,999 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
(2)
 
 
(2)
 
 
Ending balance at Mar. 31, 2014
4,377,701 
2,497,485 
(844)
1,801,047 
(74,902)
154,915 
4,486,576 
178,162 
2,379,696 
1,823,914 
(50,111)
154,915 
Ending balance (in shares) at Mar. 31, 2014
 
110,389,065 
34,828 
 
 
 
 
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
20,727 
 
 
16,122 
 
4,605 
24,473 
 
 
19,868 
 
4,605 
Other comprehensive income
1,759 
 
 
 
1,759 
 
1,857 
 
 
 
1,857 
 
Issuance of common stock (in shares)
 
159,730 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
10,277 
10,277 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(93,280)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(6,095)
 
(6,095)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
109,896 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
7,237 
 
7,230 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
 
 
 
Ending balance at Mar. 31, 2015
$ 4,553,007 
$ 2,523,247 
$ (2,266)
$ 1,942,194 
$ (66,382)
$ 156,214 
$ 4,656,183 
$ 178,162 
$ 2,379,696 
$ 1,988,587 
$ (46,476)
$ 156,214 
Ending balance (in shares) at Mar. 31, 2015
110,809,492 
110,809,492 
61,784 
 
 
 
 
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):
 
Three Months Ended 
 March 31,
 
2015
 
2014
Cash paid (received) during the period for:
 
 
 
Income taxes, net of refunds
$
1,832

 
$
(131,078
)
Interest, net of amounts capitalized
53,555

 
49,147

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
56,165

 
$
24,908

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 March 31, 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 March 31, 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.
 
At March 31, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and the $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 March 31, 2015, APS had $45 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 March 31, 2015
 
As of December 31, 2014
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125

 
$
125

 
$
125

 
$
125

APS
3,540

 
4,045

 
3,290

 
3,714

Total
$
3,665

 
$
4,170

 
$
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 March 31, 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
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.
 
APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016.  The 2012 Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest.  Nor is APS precluded from seeking rate relief, or any other party to the 2012 Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the 2012 Settlement Agreement.
 
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") discussed below;
 
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 are expected to become effective in the second quarter of 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 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 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.
 
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.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015. 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.
 
On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules 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 Utility 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):
 
 
Three Months Ended 
 March 31,
 
2015
 
2014
Beginning balance
$
7

 
$
21

Deferred fuel and purchased power costs — current period
(18
)
 
(32
)
Amounts charged to customers
(5
)
 
(8
)
Ending balance
$
(16
)
 
$
(19
)

 
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.
 
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 filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  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.

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 or another proceeding.

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 $75 million as of March 31, 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 intends to intervene and 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 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 ($127 million as of March 31, 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
 
March 31, 2015
 
December 31, 2014
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension benefits
(a)
 
$

 
$
479

 
$

 
$
485

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

 
117

 
5

 
118

Deferred fuel and purchased power — mark-to-market (Note 7)
2018
 
66

 
72

 
51

 
46

Transmission vegetation management
2016
 
9

 
2

 
9

 
5

Coal reclamation
2026
 

 
6

 

 
7

Palo Verde VIEs (Note 6)
2046
 

 
30

 

 
35

Deferred compensation
2036
 

 
36

 

 
34

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

 

 
7

 

Tax expense of Medicare subsidy
2024
 
2

 
14

 
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
 
2

 

 
4

 

Four Corners cost deferral
2024
 
7

 
68

 
7

 
70

Lost fixed cost recovery (b)
2016
 
43

 

 
38

 

Retired power plant costs
2033
 
10

 
134

 
10

 
136

Deferred property taxes
(d)
 

 
36

 

 
30

Other
Various
 
1

 
12

 
2

 
12

Total regulatory assets (e)
 
 
$
148

 
$
1,068

 
$
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
 
March 31, 2015
 
December 31, 2014
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
37

 
$
264

 
$
31

 
$
273

Asset retirement obligations
2044
 

 
302

 

 
296

Renewable energy standard (b)
2017
 
25

 
25

 
25

 
23

Income taxes — change in rates
2043
 
1

 
71

 

 
72

Spent nuclear fuel
2047
 
5

 
66

 
5

 
66

Deferred gains on utility property
2019
 
2

 
8

 
2

 
8

Income taxes — deferred investment tax credit
2043
 
3

 
93

 
4

 
93

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

 

 

 

Demand side management (b)
2017
 
5

 
27

 
31

 

Other postretirement benefits
(d)
 
32

 
191

 
32

 
199

Other
Various
 
3

 
23

 
1

 
21

Total regulatory liabilities
 
 
$
129

 
$
1,070

 
$
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 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 for the three months ended March 31, 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 
 March 31,
 
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
 
2015
 
2014
Service cost — benefits earned during the period
$
16

 
$
15

 
 
$
4

 
$
5

Interest cost on benefit obligation
31

 
32

 
 
7

 
11

Expected return on plan assets
(45
)
 
(40
)
 
 
(9
)
 
(12
)
Amortization of:
 

 
 

 
 
 

 
 

Prior service cost

 

 
 
(10
)
 

Net actuarial loss
8

 
2

 
 
2

 

Net periodic benefit cost
$
10

 
$
9

 
 
$
(6
)
 
$
4

Portion of cost charged to expense
$
6

 
$
5

 
 
$
(2
)
 
$
3


 
Contributions
 
We have made voluntary contributions of $60 million to our pension plan in 2015. The minimum 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 March 31, 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 months ended March 31, 2015 of $5 million and for the three months ended March 31, 2014 of $9 million, 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 March 31, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):
 
 
March 31, 2015
 
December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
120

 
$
121

Current maturities of long-term debt
13

 
13

Equity — Noncontrolling interests
156

 
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 March 31, 2015, APS would have been required to pay the noncontrolling equity participants approximately $123 million and assume $13 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 March 31, 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
 
4,186

 
GWh
Gas
 
157

 
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 months ended March 31, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2015
 
2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
(327
)
 
$
177

Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(2,343
)
 
(4,439
)

(a)
During the three months ended March 31, 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 $5 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, substantially all 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 months ended March 31, 2015 and 2014 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2015
 
2014
Net loss recognized in income
 
Operating revenues (a)
 
$
(48
)
 
$
(92
)
Net gain (loss) recognized in income
 
Fuel and purchased power (a)
 
(44,803
)
 
18,107

Total
 
 
 
$
(44,851
)
 
$
18,015


(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 March 31, 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 March 31, 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 March 31, 2015:
(Dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance  Sheet
Current assets
 
$
26,414

 
$
(13,382
)
 
$
13,032

 
$
626

 
$
13,658

Investments and other assets
 
23,035

 
(4,591
)
 
18,444

 

 
18,444

Total assets
 
49,449

 
(17,973
)
 
31,476

 
626

 
32,102

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(97,349
)
 
42,069

 
(55,280
)
 
(7,023
)
 
(62,303
)
Deferred credits and other
 
(106,631
)
 
32,804

 
(73,827
)
 

 
(73,827
)
Total liabilities
 
(203,980
)
 
74,873

 
(129,107
)
 
(7,023
)
 
(136,130
)
Total
 
$
(154,531
)
 
$
56,900

 
$
(97,631
)
 
$
(6,397
)
 
$
(104,028
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $56,900.
(c)
Represents cash collateral and 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 $7,023 and cash margin provided to counterparties of $626.
 
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
)
 
$
43,900

 
$
(71,780
)
 
$
(7,093
)
 
$
(78,873
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $43,900.
(c)
Represents cash collateral and 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 $7,443, and cash margin provided to counterparties of $350.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties.  We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 94% of Pinnacle West’s $32 million of risk management assets as of March 31, 2015.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2015 (dollars in millions):
 
March 31, 2015
Aggregate fair value of derivative instruments in a net liability position
$
204

Cash collateral posted
57

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
104


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
 
We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $166 million if our debt credit ratings were to fall below investment grade.
Commitments and Contingencies
Commitments and Contingencies
and Contingencies
 
Palo Verde Nuclear Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit seeks to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

On March 11, 2015, the DOE notified APS that it had approved APS’s claim for damages incurred due to DOE’s breach of the Standard Contract for the period July 1, 2011 through June 30, 2014. The claim for this period was the first claim made pursuant to the terms of the August 18, 2014 settlement agreement. The amount claimed was $42.0 million; APS’s share of this amount is $12.2 million. The settlement payment will be received in the second quarter of 2015. APS’s $12.2 million share will be recorded as an adjustment to a regulatory liability and will have no impact on income.

Nuclear Insurance
 
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.6 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of $13.2 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments.  The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment of approximately $16.5 million.
 
The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination.  APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds.  The maximum amount APS could incur under the current NEIL policies totals approximately $23 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $62 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations
  
There have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2014 Form 10-K.
 
Superfund-Related Matters
 
The Comprehensive Environmental Response Compensation and Liability Act ("Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties ("PRPs").  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, the United States Environmental Protection Agency ("EPA") advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan.  We estimate that our costs related to this investigation and study will be approximately $2 million.  We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
 
Southwest Power Outage
 
On September 8, 2011 at approximately 3:30 PM, a 500 kilovolt ("kV") transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS.  Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.
 
On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service.  APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.  The appeal is now fully briefed and pending before the United States Court of Appeals for the Ninth Circuit.  We are unable to predict the outcome of this matter.
 
Clean Air Act Citizen Lawsuit
 
On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review ("NSR") provisions of the Clean Air Act.  Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards ("NSPS") program.  Among other things, the environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS.  The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project.  On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss.  We do not expect the outcome of this matter to have a material impact on our financial position, results of operations or cash flows.

Environmental Matters
 
APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs").  These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.  Associated capital expenditures or operating costs could be material.  APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery.  The following proposed and final rules involve material compliance costs to APS.
 
Regional Haze Rules.  APS has received the final rulemaking imposing new requirements on Four Corners, Cholla and the Navajo Generating Station ("Navajo Plant").  EPA and ADEQ will require these plants to install pollution control equipment that constitutes the "best available retrofit technology" ("BART") to lessen the impacts of emissions on visibility surrounding the plants. 

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $400 million.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. The cost of the controls related to the 7% interest is approximately $45 million.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million.  In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process.

Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million, is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.  Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  Briefing in the case was completed in February 2014. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015.
 
Mercury and Air Toxic Standards.  In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants.  APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS's compromise proposal discussed above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  Salt River Project Agricultural Improvement and Power District ("SRP"), the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.
 
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.
Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.
APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million.

Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, greenhouse gas ("GHG") emissions (such as the EPA’s proposed "Clean Power Plan" rule), and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

 New Mexico Tax Matter
 
On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment").  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013.  The New Mexico Taxation and Revenue Department denied the refund claim.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  We cannot predict the timing or outcome of this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
 
Financial Assurances
 
APS has entered into various agreements that require letters of credit for financial assurance purposes.  At March 31, 2015, approximately $109 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount.  The letters of credit are available to fund the payment of principal and interest of such debt obligations.  One of these letters of credit expires in 2015, two expire in 2016, and one expires in 2017.  APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $20 million at March 31, 2015.  Additionally, APS has issued a letter of credit to support collateral obligations under a natural gas tolling contract entered into with a third party.  At March 31, 2015, that letter of credit totaled $5 million and will expire in 2015.
 
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
 
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at March 31, 2015.
Other Income and Other Expense
ome and Other Expense
 
The following table provides detail of other income and other expense for the three months ended March 31, 2015 and 2014 (dollars in thousands):

 
Three Months Ended 
 March 31,
 
2015
 
2014
Other income:
 

 
 

Interest income
$
110

 
$
251

Miscellaneous
125

 
2,116

Total other income
$
235

 
$
2,367

Other expense:
 

 
 

Non-operating costs
$
(2,249
)
 
$
(2,372
)
Investment losses — net
(495
)
 
(140
)
Miscellaneous
(1,542
)
 
(2,172
)
Total other expense
$
(4,286
)
 
$
(4,684
)
Other Income and Other Expense
 
The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2015 and 2014 (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2015
 
2014
Other income:
 

 
 

Interest income
$
67

 
$
138

Miscellaneous
572

 
2,624

Total other income
$
639

 
$
2,762

Other expense:
 

 
 

Non-operating costs (a)
$
(2,517
)
 
$
(2,587
)
Asset dispositions
(643
)
 
(183
)
Miscellaneous
(2,194
)
 
(2,286
)
Total other expense
$
(5,354
)
 
$
(5,056
)

(a)  As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).
Earnings Per Share
Earnings Per Share
Earnings Per Share
 
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three months ended March 31, 2015 and 2014 (in thousands, except per share amounts):
 
Three Months Ended 
 March 31,
 
 
2015
 
2014
 
Net income attributable to common shareholders
$
16,122

 
$
15,766

 
Weighted average common shares outstanding — basic
110,916

 
110,257

 
Net effect of dilutive securities:
 

 
 

 
Contingently issuable performance shares and restricted stock units
461

 
631

 
Weighted average common shares outstanding — diluted
111,377

 
110,888

 
Earnings per average common share attributable to common shareholders — basic
$
0.15

 
$
0.14

 
Earnings per average common share attributable to common shareholders — diluted
$
0.14

 
$
0.14

 
Fair Value Measurements
Fair Value Measurements
ue Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.  This category includes exchange traded equities, exchange traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.

Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves).  This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities.  This category also includes investments that are redeemable and valued based on NAV, such as common and collective trusts and commingled funds.
 
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
 
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
 
Recurring Fair Value Measurements
 
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 7 in the 2014 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.
 
Cash Equivalents
 
Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.
 
Risk Management Activities — Derivative Instruments
 
Exchange traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value.  We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.  These include valuation adjustments for liquidity and credit risks.  The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged.  The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.
 
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions.  Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.
 
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.  Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.
 
Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies.  We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures.  The risk control function reports to the chief financial officer’s organization.
 
Investments Held in our Nuclear Decommissioning Trust
 
The nuclear decommissioning trust invests in fixed income securities and equity securities.  Equity securities are held indirectly through commingled funds.  The commingled funds are valued based on the concept of Net Asset Value ("NAV"), which is a value primarily derived from the quoted active market prices of the underlying equity securities.  We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2.  The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.  Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.
 
Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.
 
Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.
 
We price securities using information provided by our trustee for our nuclear decommissioning trust assets.  Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value.  We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.  See Note 12 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables
 
The following table presents the fair value at March 31, 2015, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs (a)
(Level 3)
 
Other
 
 
 
Balance at March 31, 2015
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$

 
$
16

 
$
33

 
$
(17
)
 
(b)
 
$
32

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

U.S. commingled equity funds

 
313