PINNACLE WEST CAPITAL CORP, 10-Q filed on 4/29/2016
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2016
Apr. 22, 2016
Entity Information [Line Items]
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2016 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
111,139,995 
Document Fiscal Year Focus
2016 
 
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, 2016 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
71,264,947 
Document Fiscal Year Focus
2016 
 
Document Fiscal Period Focus
Q1 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
OPERATING REVENUES
$ 677,167 
$ 671,219 
OPERATING EXPENSES
 
 
Fuel and purchased power
221,285 
223,237 
Operations and maintenance
243,195 
214,944 
Depreciation and amortization
119,476 
120,949 
Taxes other than income taxes
42,501 
43,216 
Other expenses
548 
1,189 
Total
627,005 
603,535 
OPERATING INCOME
50,162 
67,684 
OTHER INCOME (DEDUCTIONS)
 
 
Allowance for equity funds used during construction
10,516 
9,224 
Other income (Note 8)
117 
235 
Other expense (Note 8)
(4,038)
(4,286)
Total
6,595 
5,173 
INTEREST EXPENSE
 
 
Interest charges
50,744 
48,399 
Allowance for borrowed funds used during construction
(5,227)
(4,216)
Total
45,517 
44,183 
INCOME BEFORE INCOME TAXES
11,240 
28,674 
INCOME TAXES
1,914 
7,947 
NET INCOME
9,326 
20,727 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,605 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
4,453 
16,122 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
111,296 
110,916 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
111,847 
111,377 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.04 
$ 0.15 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 0.04 
$ 0.14 
Arizona Public Service Company
 
 
ELECTRIC OPERATING REVENUES
676,632 
670,668 
OPERATING EXPENSES
 
 
Fuel and purchased power
221,285 
223,237 
Operations and maintenance
238,711 
209,947 
Depreciation and amortization
119,446 
120,926 
Income taxes
5,850 
12,239 
Taxes other than income taxes
42,410 
42,986 
Total
627,702 
609,335 
OPERATING INCOME
48,930 
61,333 
OTHER INCOME (DEDUCTIONS)
 
 
Income taxes
1,815 
2,151 
Allowance for equity funds used during construction
10,516 
9,224 
Other income (Note 8)
610 
639 
Other expense (Note 8)
(4,750)
(5,354)
Total
8,191 
6,660 
INTEREST EXPENSE
 
 
Interest on long-term debt
46,819 
45,428 
Interest on short-term borrowings
2,077 
1,174 
Debt discount, premium and expense
1,139 
1,134 
Allowance for borrowed funds used during construction
(5,040)
(4,216)
Total
44,995 
43,520 
NET INCOME
12,126 
24,473 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,605 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 7,253 
$ 19,868 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
NET INCOME
$ 9,326 
$ 20,727 
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(693)
(800)
Reclassification of net realized loss, net of tax benefit
1,141 
1,976 
Pension and other postretirement benefits activity, net of tax benefit (expense)
530 
583 
Total other comprehensive income
978 
1,759 
COMPREHENSIVE INCOME
10,304 
22,486 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,605 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
5,431 
17,881 
Arizona Public Service Company
 
 
NET INCOME
12,126 
24,473 
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax benefit (expense)
(693)
(800)
Reclassification of net realized loss, net of tax benefit
1,141 
1,976 
Pension and other postretirement benefits activity, net of tax benefit (expense)
611 
681 
Total other comprehensive income
1,059 
1,857 
COMPREHENSIVE INCOME
13,185 
26,330 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,605 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 8,312 
$ 21,725 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Net unrealized loss, tax expense
$ 546 
$ 473 
Reclassification of net realized loss, tax (expense) benefit
(200)
367 
Pension and other postretirement benefits activity, tax expense
645 
867 
Arizona Public Service Company
 
 
Net unrealized loss, tax expense
546 
473 
Reclassification of net realized loss, tax (expense) benefit
(200)
367 
Pension and other postretirement benefits activity, tax expense
$ 558 
$ 769 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 14,484 
$ 39,488 
Customer and other receivables
215,808 
274,691 
Accrued unbilled revenues
89,795 
96,240 
Allowance for doubtful accounts
(2,427)
(3,125)
Materials and supplies (at average cost)
234,179 
234,234 
Fossil fuel (at average cost)
44,227 
45,697 
Income tax receivable
4,637 
589 
Assets from risk management activities (Note 6)
16,089 
15,905 
Regulatory assets (Note 3)
168,753 
149,555 
Other current assets
40,480 
37,242 
Total current assets
826,025 
890,516 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
8,612 
12,106 
Nuclear decommissioning trust (Note 11)
751,954 
735,196 
Other assets
52,679 
52,518 
Total investments and other assets
813,245 
799,820 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
16,285,916 
16,222,232 
Accumulated depreciation and amortization
(5,670,884)
(5,594,094)
Net
10,615,032 
10,628,138 
Construction work in progress
1,038,046 
816,307 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
116,418 
117,385 
Intangible assets, net of accumulated amortization
116,014 
123,975 
Nuclear fuel, net of accumulated amortization
138,424 
123,139 
Total property, plant and equipment
12,023,934 
11,808,944 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,203,474 
1,214,146 
Assets for other postretirement benefits (Note 4)
190,458 
185,997 
Other
127,965 
128,835 
Total deferred debits
1,521,897 
1,528,978 
TOTAL ASSETS
15,185,101 
15,028,258 
CURRENT LIABILITIES
 
 
Accounts payable
234,946 
297,480 
Accrued taxes
181,889 
138,600 
Accrued interest
44,489 
56,305 
Common dividends payable
69,363 
Short-term borrowings (Note 2)
261,800 
Current maturities of long-term debt (Note 2)
357,580 
357,580 
Customer deposits
78,825 
73,073 
Liabilities from risk management activities (Note 6)
93,283 
77,716 
Liabilities for asset retirements
17,217 
28,573 
Deferred fuel and purchased power regulatory liability (Note 3)
13,083 
9,688 
Other regulatory liabilities (Note 3)
122,471 
136,078 
Other current liabilities
180,319 
197,861 
Total current liabilities
1,585,902 
1,442,317 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
3,463,032 
3,462,391 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,726,220 
2,723,425 
Regulatory liabilities (Note 3)
1,009,418 
994,152 
Liabilities for asset retirements
429,626 
415,003 
Liabilities for pension benefits (Note 4)
441,605 
480,998 
Liabilities from risk management activities (Note 6)
85,603 
89,973 
Customer advances
110,056 
115,609 
Coal mine reclamation
202,069 
201,984 
Deferred investment tax credit
186,966 
187,080 
Unrecognized tax benefits
9,631 
9,524 
Other
194,560 
186,345 
Total deferred credits and other
5,395,754 
5,404,093 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,147,524 and 111,095,402 issued at respective dates
2,547,065 
2,541,668 
Treasury stock at cost; 7,936 and 115,030 shares at respective dates
(542)
(5,806)
Total common stock
2,546,523 
2,535,862 
Retained earnings
2,097,246 
2,092,803 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(37,063)
(37,593)
Derivative instruments
(6,707)
(7,155)
Total accumulated other comprehensive loss
(43,770)
(44,748)
Total shareholders’ equity
4,599,999 
4,583,917 
Noncontrolling interests (Note 5)
140,414 
135,540 
Total equity
4,740,413 
4,719,457 
TOTAL LIABILITIES AND EQUITY
15,185,101 
15,028,258 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
4,904 
22,056 
Customer and other receivables
215,351 
274,428 
Accrued unbilled revenues
89,795 
96,240 
Allowance for doubtful accounts
(2,427)
(3,125)
Materials and supplies (at average cost)
234,179 
234,234 
Fossil fuel (at average cost)
44,227 
45,697 
Assets from risk management activities (Note 6)
16,089 
15,905 
Regulatory assets (Note 3)
168,753 
149,555 
Other current assets
39,043 
35,765 
Total current assets
809,914 
870,755 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
8,612 
12,106 
Nuclear decommissioning trust (Note 11)
751,954 
735,196 
Other assets
34,927 
34,455 
Total investments and other assets
795,493 
781,757 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
16,282,405 
16,218,724 
Accumulated depreciation and amortization
(5,667,713)
(5,590,937)
Net
10,614,692 
10,627,787 
Construction work in progress
1,025,868 
812,845 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
116,418 
117,385 
Intangible assets, net of accumulated amortization
115,859 
123,820 
Nuclear fuel, net of accumulated amortization
138,424 
123,139 
Total property, plant and equipment
12,011,261 
11,804,976 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,203,474 
1,214,146 
Assets for other postretirement benefits (Note 4)
187,069 
182,625 
Other
127,086 
127,923 
Total deferred debits
1,517,629 
1,524,694 
TOTAL ASSETS
15,134,297 
14,982,182 
CURRENT LIABILITIES
 
 
Accounts payable
232,484 
291,574 
Accrued taxes
183,272 
144,488 
Accrued interest
44,224 
56,003 
Common dividends payable
69,400 
Short-term borrowings (Note 2)
261,800 
Current maturities of long-term debt (Note 2)
357,580 
357,580 
Customer deposits
78,825 
73,073 
Liabilities from risk management activities (Note 6)
93,283 
77,716 
Liabilities for asset retirements
13,083 
9,688 
Deferred fuel and purchased power regulatory liability (Note 3)
17,217 
28,573 
Other regulatory liabilities (Note 3)
122,471 
136,078 
Other current liabilities
172,249 
180,535 
Total current liabilities
1,576,488 
1,424,708 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,767,124 
2,764,489 
Regulatory liabilities (Note 3)
1,009,418 
994,152 
Liabilities for asset retirements
429,626 
415,003 
Liabilities for pension benefits (Note 4)
420,110 
459,065 
Liabilities from risk management activities (Note 6)
85,603 
89,973 
Customer advances
110,056 
115,609 
Coal mine reclamation
202,069 
201,984 
Deferred investment tax credit
186,966 
187,080 
Unrecognized tax benefits
35,356 
35,251 
Other
145,469 
142,683 
Total deferred credits and other
5,391,797 
5,405,289 
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
2,155,746 
2,148,493 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(19,331)
(19,942)
Derivative instruments
(6,707)
(7,155)
Total shareholders’ equity
4,687,566 
4,679,254 
Noncontrolling interests (Note 5)
140,414 
135,540 
Total equity
4,827,980 
4,814,794 
Long-term debt less current maturities (Note 2)
3,338,032 
3,337,391 
Total capitalization
8,166,012 
8,152,185 
TOTAL LIABILITIES AND EQUITY
$ 15,134,297 
$ 14,982,182 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Mar. 31, 2016
Dec. 31, 2015
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
 
 
Common stock, par value (in dollars per share)
   
   
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
111,147,524 
111,095,402 
Treasury stock at cost, shares
7,936 
115,030 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 9,326 
$ 20,727 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
140,759 
141,494 
Deferred fuel and purchased power
1,007 
17,671 
Deferred fuel and purchased power amortization
2,388 
5,614 
Allowance for equity funds used during construction
(10,516)
(9,224)
Deferred income taxes
3,468 
6,978 
Deferred investment tax credit
(114)
(294)
Change in derivative instruments fair value
(111)
(104)
Changes in current assets and liabilities:
 
 
Customer and other receivables
47,282 
39,174 
Accrued unbilled revenues
6,445 
6,133 
Materials, supplies and fossil fuel
1,525 
(9,995)
Income tax receivable
(4,048)
(219)
Other current assets
(8,131)
(9,631)
Accounts payable
(38,443)
(35,673)
Accrued taxes
43,289 
48,111 
Other current liabilities
(38,040)
(56,747)
Change in margin and collateral accounts — assets
681 
(276)
Change in margin and collateral accounts — liabilities
410 
(13,420)
Change in other long-term assets
(17,504)
(13,126)
Change in other long-term liabilities
4,536 
6,955 
Net cash flow provided by operating activities
144,209 
144,148 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(378,500)
(251,041)
Contributions in aid of construction
12,464 
27,222 
Allowance for borrowed funds used during construction
(5,227)
(4,216)
Proceeds from nuclear decommissioning trust sales
141,809 
115,282 
Investment in nuclear decommissioning trust
(142,379)
(119,594)
Other
(472)
(470)
Net cash flow used for investing activities
(372,305)
(232,817)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
250,000 
Short-term borrowings and payments — net
261,800 
(102,900)
Dividends paid on common stock
(67,611)
(64,061)
Common stock equity issuance - net of purchases
8,902 
9,690 
Other
Net cash flow provided by financing activities
203,092 
92,729 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(25,004)
4,060 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
39,488 
7,604 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
14,484 
11,664 
Cash paid during the period for:
 
 
Income taxes, net of refunds
2,502 
1,832 
Interest, net of amounts capitalized
56,139 
53,555 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
59,707 
56,165 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
12,126 
24,473 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
140,729 
141,471 
Deferred fuel and purchased power
1,007 
17,671 
Deferred fuel and purchased power amortization
2,388 
5,614 
Allowance for equity funds used during construction
(10,516)
(9,224)
Deferred income taxes
3,394 
2,427 
Deferred investment tax credit
(114)
(294)
Change in derivative instruments fair value
(111)
(104)
Changes in current assets and liabilities:
 
 
Customer and other receivables
47,575 
43,070 
Accrued unbilled revenues
6,445 
6,133 
Materials, supplies and fossil fuel
1,525 
(9,995)
Other current assets
(8,172)
(9,116)
Accounts payable
(34,999)
(35,604)
Accrued taxes
38,784 
59,057 
Other current liabilities
(28,748)
(65,290)
Change in margin and collateral accounts — assets
681 
(276)
Change in margin and collateral accounts — liabilities
410 
(13,421)
Change in other long-term assets
(17,375)
(16,253)
Change in other long-term liabilities
(1,102)
12,635 
Net cash flow provided by operating activities
153,927 
152,974 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(369,861)
(250,930)
Contributions in aid of construction
12,464 
27,222 
Allowance for borrowed funds used during construction
(5,040)
(4,216)
Proceeds from nuclear decommissioning trust sales
141,809 
115,282 
Investment in nuclear decommissioning trust
(142,379)
(119,594)
Other
(472)
(470)
Net cash flow used for investing activities
(363,479)
(232,706)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
250,000 
Short-term borrowings and payments — net
261,800 
(102,900)
Dividends paid on common stock
(69,400)
(65,800)
Net cash flow provided by financing activities
192,400 
81,300 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(17,152)
1,568 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
22,056 
4,515 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
4,904 
6,083 
Cash paid during the period for:
 
 
Income taxes, net of refunds
8,772 
184 
Interest, net of amounts capitalized
55,580 
52,825 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 59,707 
$ 56,165 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Arizona Public Service Company
Arizona Public Service Company
Common Stock
Arizona Public Service Company
Additional Paid-In Capital
Arizona Public Service Company
Retained Earnings
Arizona Public Service Company
Accumulated Other Comprehensive Income (Loss)
Arizona Public Service Company
Noncontrolling Interests
Balance at end of period at Dec. 31, 2014
$ 4,519,102 
$ 2,512,970 
$ (3,401)
$ 1,926,065 
$ (68,141)
$ 151,609 
$ 4,629,852 
$ 178,162 
$ 2,379,696 
$ 1,968,718 
$ (48,333)
$ 151,609 
Beginning balance (in shares) at Dec. 31, 2014
 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
20,727 
 
 
16,122 
 
4,605 
24,473 
 
 
19,868 
 
4,605 
Other comprehensive income
1,759 
 
 
 
1,759 
 
1,857 
 
 
 
1,857 
 
Other
 
 
 
 
 
 
 
 
 
 
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)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
109,896 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
7,237 
 
7,230 
 
 
 
 
 
 
 
 
Balance at beginning of period 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 
61,784 
 
 
 
 
71,264,947 
 
 
 
 
Balance at end of period at Dec. 31, 2015
4,719,457 
2,541,668 
(5,806)
2,092,803 
(44,748)
135,540 
4,814,794 
178,162 
2,379,696 
2,148,493 
(27,097)
135,540 
Beginning balance (in shares) at Dec. 31, 2015
111,095,402 
111,095,402 
115,030 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
9,326 
 
 
4,453 
 
4,873 
12,126 
 
 
7,253 
 
4,873 
Other comprehensive income
978 
 
 
 
978 
 
1,059 
 
 
 
1,059 
 
Other
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
52,122 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
5,397 
5,397 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(71,962)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,880)
 
(4,880)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
179,056 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
10,135 
 
10,144 
(10)
 
 
 
 
 
 
 
Balance at beginning of period at Mar. 31, 2016
$ 4,740,413 
$ 2,547,065 
$ (542)
$ 2,097,246 
$ (43,770)
$ 140,414 
$ 4,827,980 
$ 178,162 
$ 2,379,696 
$ 2,155,746 
$ (26,038)
$ 140,414 
Ending balance (in shares) at Mar. 31, 2016
111,147,524 
111,147,524 
7,936 
 
 
 
 
71,264,947 
 
 
 
 
Consolidation and Nature of Operations
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado").  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 5 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
 
Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
 
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2015 Form 10-K.
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2016
 
2015
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
2,502

 
$
1,832

Interest, net of amounts capitalized
56,139

 
53,555

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
59,707

 
$
56,165

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

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
 
Pinnacle West
 
At March 31, 2016, Pinnacle West had a $200 million revolving credit facility that matures in May 2019.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At March 31, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
 
APS

During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. Interest rates are based on APS's senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

At March 31, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and a $500 million facility that matures in May 2019.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2016, APS had $262 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 7 for a discussion of APS’s separate outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of March 31, 2016
 
As of December 31, 2015
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
125,000

 
$
125,000

 
$
125,000

 
$
125,000

APS
3,695,612

 
4,136,022

 
3,694,971

 
3,981,367

Total
$
3,820,612

 
$
4,261,022

 
$
3,819,971

 
$
4,106,367

 
Debt Provisions
 
An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At March 31, 2016, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.7 billion, and total capitalization was approximately $8.6 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.4 billion, assuming APS’s total capitalization remains the same.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filings with the Arizona Corporation Commission

Upcoming Rate Case Filing

On January 29, 2016, APS filed a notice of its intent to file a rate case ("NOI") informing the ACC that APS intends to submit a rate case application in June 2016 using an adjusted test year ending December 31, 2015.  The NOI provides an overview of the key issues APS expects to address in its formal request such as rate design changes (residential, commercial and industrial), permission to defer for potential future recovery costs associated with the Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items.  In its rate application, APS will request that its proposed pricing changes take effect in July 2017. APS is still developing the exact amount of the request.

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

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

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

Deferral of 100% in all years if Arizona property tax rates decrease;
 
A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);
 
Implementation of a Lost Fixed Cost Recovery ("LFCR") rate mechanism to support energy efficiency and distributed renewable generation;
 
Modifications to the Environmental Improvement Surcharge ("EIS") to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
 
Modifications to the Power Supply Adjustor ("PSA"), including the elimination of the 90/10 sharing provision;
 
A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge ("DSMAC") to recoup capital expenditures not required under the terms of APS’s 2009 retail rate case settlement agreement (the "2009 Settlement Agreement");
  
Modification of the Transmission Cost Adjustor ("TCA") to streamline the process for future transmission-related rate changes; and
 
Implementation of various changes to rate schedules, including the adoption of an experimental "buy-through" rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
 
The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.
 
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
  
In accordance with the ACC's decision on APS's 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 megawatts ("MW") of APS-owned grid scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of grid scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program, called the "Solar Partner Program", is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.
 
On July 1, 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 requested budget to approximately $152 million.

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.
 
Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. 

On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. On April 1, 2016, APS filed an Amended DSM Plan that sought minor modifications to its 2015 DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million.
 
Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rulemaking has not been initiated and there has been no additional action on the draft to date.
 
PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2016 and 2015 (dollars in thousands):
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
Beginning balance
$
(9,688
)
 
$
6,925

Deferred fuel and purchased power costs — current period
(1,007
)
 
(17,671
)
Amounts charged to customers
(2,388
)
 
(5,614
)
Ending balance
$
(13,083
)
 
$
(16,360
)

 
The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh.  On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, the United States Federal Energy Regulatory Commission ("FERC") approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC staff.  Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.
 
Effective June 1, 2015, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2015.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future.
 
Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units.
 
APS files for a LFCR adjustment every January. APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. To date the ACC has not yet approved this matter.

Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS's net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electric grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR.
 
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 
 
On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing commenced in April 2016. APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015 and February 23, 2016, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS actively participated in the related hearings held in March 2016. APS has also intervened in the upcoming Tucson Electric Power Company rate case. The outcomes of these proceedings will not directly impact our financial position.

Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB")

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument was conducted on March 22, 2016.   If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter.
 
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 $69 million as of March 31, 2016 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter will be resolved.
 
As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("EPA") approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and plans to seek recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its next retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($121 million as of March 31, 2016), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands):
 
 
Amortization Through
 
March 31, 2016
 
December 31, 2015
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
610,569

 
$

 
$
619,223

Retired power plant costs
2033
 
9,913

 
125,037

 
9,913

 
127,518

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

 
132,149

 
5,495

 
133,712

Deferred fuel and purchased power — mark-to-market (Note 6)
2019
 
86,160

 
69,708

 
71,852

 
69,697

Four Corners cost deferral (b)
2024
 
6,689

 
61,910

 
6,689

 
63,582

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

 
48,347

 
1,766

 
48,462

Lost fixed cost recovery (b)
2017
 
48,702

 

 
45,507

 

Palo Verde VIEs (Note 5)
2046
 

 
18,311

 

 
18,143

Deferred compensation
2036
 

 
35,871

 

 
34,751

Deferred property taxes
(c)
 

 
56,589

 

 
50,453

Loss on reacquired debt
2034
 
1,515

 
15,996

 
1,515

 
16,375

Tax expense of Medicare subsidy
2024
 
1,512

 
12,073

 
1,520

 
12,163

Transmission vegetation management
2016
 
2,272

 

 
4,543

 

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,957

 
332

 
11,040

Transmission cost adjustor (b)
2018
 
3,969

 
462

 

 
2,942

Coal reclamation
2026
 
418

 
5,495

 
418

 
6,085

Other
Various
 

 

 
5

 

Total regulatory assets (d)
 
 
$
168,753

 
$
1,203,474

 
$
149,555

 
$
1,214,146


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues.  See Note 4 for further discussion.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Per the provision of the 2012 Settlement Agreement.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."

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

 
$
289,485

 
$

 
$
277,554

Removal costs
(a)
 
32,473

 
244,724

 
39,746

 
240,367

Other postretirement benefits
(d)
 
34,100

 
171,029

 
34,100

 
179,521

Income taxes — deferred investment tax credit
2045
 
3,774

 
96,940

 
3,604

 
97,175

Income taxes — change in rates
2046
 
1,771

 
71,756

 
1,113

 
72,454

Spent nuclear fuel
2047
 
31

 
71,235

 
3,051

 
67,437

Renewable energy standard (b)
2017
 
41,518

 
3,274

 
43,773

 
4,365

Demand side management (b)
2017
 
6,628

 
19,115

 
6,079

 
19,115

Sundance maintenance
2030
 

 
14,080

 

 
13,678

Deferred fuel and purchased power (b) (c)
2017
 
13,083

 

 
9,688

 

Deferred gains on utility property
2019
 
2,062

 
5,501

 
2,062

 
6,001

Four Corners coal reclamation
2031
 

 
14,725

 

 
8,920

Other
Various
 
114

 
7,554

 
2,550

 
7,565

Total regulatory liabilities
 
 
$
135,554

 
$
1,009,418

 
$
145,766

 
$
994,152


(a)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Subject to a carrying charge.
(d)
See Note 4.
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of the plan changes, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $140 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs.
 
Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We completed amortizing these costs as of June 30, 2015. We amortized approximately $2 million for the three months ended March 31, 2015.

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

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 March 31,
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
2016
 
2015
Service cost — benefits earned during the period
$
14,266

 
$
15,824

 
$
3,937

 
$
4,346

Interest cost on benefit obligation
32,945

 
31,189

 
7,341

 
7,184

Expected return on plan assets
(43,792
)
 
(45,149
)
 
(9,122
)
 
(9,147
)
Amortization of:
 

 
 

 
 

 
 

Prior service cost
132

 
149

 
(9,471
)
 
(9,492
)
Net actuarial loss
9,731

 
7,761

 
946

 
1,561

Net periodic benefit cost
$
13,282

 
$
9,774

 
$
(6,369
)
 
$
(5,548
)
Portion of cost charged to expense
$
6,519

 
$
5,987

 
$
(3,126
)
 
$
(1,788
)

 
Contributions
 
We made voluntary contributions of $60 million to our pension plan year-to-date in 2016. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period. We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2016 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
 
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2016 and 2015 of $5 million, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at March 31, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):
 
 
March 31, 2016
 
December 31, 2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
116,418

 
$
117,385

Equity — Noncontrolling interests
140,414

 
135,540


 
Assets of the VIEs are restricted and may only be used 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 and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $288 million beginning in 2016, and up to $456 million over the lease terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
Derivative Accounting
Derivative Accounting
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value.  See Note 10 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
 
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time.  We assess hedge effectiveness both at inception and on a continuing basis.  These assessments exclude the time value of certain options.  For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings.  We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment.  As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of March 31, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
2,239

 
GWh
Gas
 
179

 
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, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2016
 
2015
Loss recognized in OCI on derivative instruments (effective portion)
 
OCI — derivative instruments
 
$
(147
)
 
$
(327
)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)
 
Fuel and purchased power (b)
 
(941
)
 
(2,343
)

(a)
During the three months ended March 31, 2016 and 2015, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $4 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2016 and 2015 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2016
 
2015
Net loss recognized in income
 
Operating revenues
 
$
(102
)
 
$
(48
)
Net loss recognized in income
 
Fuel and purchased power (a)
 
(30,936
)
 
(44,803
)
Total
 
 
 
$
(31,038
)
 
$
(44,851
)

(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, 2016 and December 31, 2015, each include gross liabilities of $3 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, 2016 and December 31, 2015.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.
As of March 31, 2016:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
25,365

 
$
(9,268
)
 
$
16,097

 
$
(8
)
 
$
16,089

Investments and other assets
 
11,248

 
(2,636
)
 
8,612

 

 
8,612

Total assets
 
36,613

 
(11,904
)
 
24,709

 
(8
)
 
24,701

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(115,822
)
 
26,868

 
(88,954
)
 
(4,329
)
 
(93,283
)
Deferred credits and other
 
(88,239
)
 
2,636

 
(85,603
)
 

 
(85,603
)
Total liabilities
 
(204,061
)
 
29,504

 
(174,557
)
 
(4,329
)
 
(178,886
)
Total
 
$
(167,448
)
 
$
17,600

 
$
(149,848
)
 
$
(4,337
)
 
$
(154,185
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $17,600.
(c)
Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,329, and cash margin provided to counterparties of $(8).
 
As of December 31, 2015:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
37,396

 
$
(22,163
)
 
$
15,233

 
$
672

 
$
15,905

Investments and other assets
 
15,960

 
(3,854
)
 
12,106

 

 
12,106

Total assets
 
53,356

 
(26,017
)
 
27,339

 
672

 
28,011

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(113,560
)
 
40,223

 
(73,337
)
 
(4,379
)
 
(77,716
)
Deferred credits and other
 
(93,827
)
 
3,854

 
(89,973
)
 

 
(89,973
)
Total liabilities
 
(207,387
)
 
44,077

 
(163,310
)
 
(4,379
)
 
(167,689
)
Total
 
$
(154,031
)
 
$
18,060

 
$
(135,971
)
 
$
(3,707
)
 
$
(139,678
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
Includes cash collateral provided to counterparties of $18,060.
(c)
Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,379, and cash margin provided to counterparties of $672.

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 87% of Pinnacle West’s $25 million of risk management assets as of March 31, 2016.  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, 2016 (dollars in thousands):
 
March 31, 2016
Aggregate fair value of derivative instruments in a net liability position
$
204,061

Cash collateral posted
17,600

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
133,688


(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 $153 million if our debt credit ratings were to fall below investment grade.
Commitments and Contingencies
Commitments and Contingencies
Commitments 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 second 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 sought 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's 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 the amount of reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016.

APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net 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 $13.5 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 $13.1 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 $16.6 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 $2.8 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 $23.1 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 $61.7 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, as of March 31, 2016, outside the normal course of business in contractual obligations from the information provided in our 2015 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

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, 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.  APS responded to ADEQ on May 4, 2015. 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.  On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016.
 

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 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 Electric Company ("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. When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. APS is negotiating a definitive purchase agreement with NTEC for the purchase of the 7% interest. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

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 $100 million (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015), 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 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/or 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. APS’s proposal involves state and federal rulemaking processes. 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. On October 16, 2015, ADEQ issued the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  APS is unable to predict when or whether APS's proposal may ultimately be approved by the EPA.
 
Mercury and Air Toxic Standards ("MATS").  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 $8 million for Cholla (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015). 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, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. The United States Supreme Court’s 2015 decision in Michigan vs. EPA reversed and remanded the MATS proceeding back to the DC Circuit Court. The Circuit Court then remanded the MATS rule back to EPA to address rulemaking deficiencies identified by the Supreme Court On April 14, 2016, EPA took action to resolve these deficiencies by issuing a revised "appropriate and necessary" finding, which is a prerequisite to regulating hazardous air pollutants emitted by power plants under the Clean Air Act, to expressly evaluate the costs of the MATS regulation. Further litigation concerning the propriety of this finding is expected. These proceedings do not materially impact APS.  Regardless of the results from further judicial or administrative proceedings concerning the MATS rulemaking, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla.
 
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 $40 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. Additionally, the CCR rule requires on-going groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions. Because the initial monitoring at these plants is not yet complete, at the present time expenditures related to potential corrective actions cannot be reasonably estimated.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for existing, new, modified, and reconstructed electric generating units ("EGUs"). EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal.

With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO2 emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below.

Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ reports that it is continuing to assess its options while completing outreach and soliciting feedback from stakeholders. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation.

The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such a delay.

With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances.

As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation.

Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material.

Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes.

In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output, as an alternative to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, and additional information or considerations may arise that change our expectations.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard 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 current and 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.

Federal Agency Environmental Lawsuit Related to Four Corners

On December 21, 2015, several environmental groups filed a notice of intent to sue with Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies under the Endangered Species Act (“ESA”) alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the United States Department of the Interior's ("DOI's") review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners.  This review process also required separate environmental impact evaluations under the National Environmental Policy Act (“NEPA”) and culminated in the issuance of a Record of Decision justifying the agency action extending the life of the plant and the adjacent mine. 

On April 20, 2016, the same environmental groups followed through with their notice of intent to sue by filing a lawsuit against OSM and other federal agencies in the District of Arizona.  Expanding upon the December 2015 ESA notice, the lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  We are monitoring the proceedings and intend to request the right to intervene in the litigation. We cannot predict the outcome of this matter or its potential effect on Four Corners.

 New Mexico Tax Matter
 
On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") 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 in the amount of $0.8 million and immediately filed a refund claim with respect to that partial payment in August 2013.  The NMTRD 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.  On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed an appeal of the decision on August 31, 2015.

On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above is approximately $0.8 million.
  
Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of March 31, 2016, standby letters of credit totaled $79 million and will expire in 2016. As of March 31, 2016, surety bonds expiring through 2018 totaled $150 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
 
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, 2016.
Other Income and Other Expense
Other Income and Other Expense
 
The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three months ended March 31, 2016 and 2015 (dollars in thousands):

 
Three Months Ended 
 March 31,
 
2016
 
2015
Other income:
 

 
 

Interest income
$
117

 
$
110

Miscellaneous

 
125

Total other income
$
117

 
$
235

Other expense:
 

 
 

Non-operating costs
$
(2,049
)
 
$
(2,249
)
Investment losses — net
(518
)
 
(495
)
Miscellaneous
(1,471
)
 
(1,542
)
Total other expense
$
(4,038
)
 
$
(4,286
)
The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2016 and 2015 (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2016
 
2015
Other income:
 

 
 

Interest income
$
73

 
$
67

Gain on disposition of property
332

 
207

Miscellaneous
205

 
365

Total other income
$
610

 
$
639

Other expense:
 

 
 

Non-operating costs (a)
$
(1,966
)
 
$
(2,517
)
Loss on disposition of property
(426
)
 
(643
)
Miscellaneous
(2,358
)
 
(2,194
)
Total other expense
$
(4,750
)
 
$
(5,354
)

(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, 2016 and 2015 (in thousands, except per share amounts):
 
Three Months Ended 
 March 31,
 
2016
 
2015
Net income attributable to common shareholders
$
4,453

 
$
16,122

Weighted average common shares outstanding — basic
111,296

 
110,916

Net effect of dilutive securities:
 

 
 

Contingently issuable performance shares and restricted stock units
551

 
461

Weighted average common shares outstanding — diluted
111,847

 
111,377

Earnings per weighted-average common share outstanding
 
 
 
Net income attributable to common shareholders — basic
$
0.04

 
$
0.15

Net income attributable to common shareholders — diluted
$
0.04

 
$
0.14

Fair Value Measurements
Fair Value Measurements
Fair Value 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, exchange traded mutual funds, 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.  
 
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.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires instruments valued using NAV, as a practical expedient, to no longer be classified within the fair value hierarchy. As such, instruments valued using NAV, as a practical expedient, are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.

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 2015 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 using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds.  We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled 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 funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.
 
Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper.
 
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 typically 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 11 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables
 
The following table presents the fair value at March 31, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
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, 2016
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$

 
$
12,613

 
$
23,847

 
$
(11,759
)
 
(b)
 
$
24,701