PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/2/2017
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2017
Apr. 25, 2017
Entity Information [Line Items]
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
Entity Central Index Key
0000764622 
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2017 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
111,560,427 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q1 
 
APS
 
 
Entity Information [Line Items]
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY  
 
Entity Central Index Key
0000007286  
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2017 
 
Amendment Flag
false 
 
Current Fiscal Year End Date
--12-31 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
71,264,947 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q1 
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
OPERATING REVENUES
$ 677,728 
$ 677,167 
OPERATING EXPENSES
 
 
Fuel and purchased power
212,395 
221,285 
Operations and maintenance
219,976 
243,195 
Depreciation and amortization
127,627 
119,476 
Taxes other than income taxes
43,836 
42,501 
Other expenses
388 
548 
Total
604,222 
627,005 
OPERATING INCOME
73,506 
50,162 
OTHER INCOME (DEDUCTIONS)
 
 
Allowance for equity funds used during construction
9,482 
10,516 
Other income (Note 8)
480 
117 
Other expense (Note 8)
(3,680)
(4,038)
Total
6,282 
6,595 
INTEREST EXPENSE
 
 
Interest charges
51,864 
50,744 
Allowance for borrowed funds used during construction
(4,472)
(5,227)
Total
47,392 
45,517 
INCOME BEFORE INCOME TAXES
32,396 
11,240 
INCOME TAXES
4,211 
1,914 
NET INCOME
28,185 
9,326 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,873 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
23,312 
4,453 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
 
 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
111,728 
111,296 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
112,195 
111,847 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 0.21 
$ 0.04 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 0.21 
$ 0.04 
APS
 
 
ELECTRIC OPERATING REVENUES
676,869 
676,632 
OPERATING EXPENSES
 
 
Fuel and purchased power
217,104 
221,285 
Operations and maintenance
212,218 
238,711 
Depreciation and amortization
127,208 
119,446 
Income taxes
11,373 
5,850 
Taxes other than income taxes
43,498 
42,410 
Total
611,401 
627,702 
OPERATING INCOME
65,468 
48,930 
OTHER INCOME (DEDUCTIONS)
 
 
Income taxes
2,725 
1,815 
Allowance for equity funds used during construction
9,482 
10,516 
Other income (Note 8)
1,062 
610 
Other expense (Note 8)
(4,378)
(4,750)
Total
8,891 
8,191 
INTEREST EXPENSE
 
 
Interest on long-term debt
47,491 
46,819 
Interest on short-term borrowings
2,128 
2,077 
Debt discount, premium and expense
1,177 
1,139 
Allowance for borrowed funds used during construction
(4,472)
(5,040)
Total
46,324 
44,995 
NET INCOME
28,035 
12,126 
Less: Net income attributable to noncontrolling interests (Note 5)
4,873 
4,873 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 23,162 
$ 7,253 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
NET INCOME
$ 28,185 
$ 9,326 
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax expense
(770)
(693)
Reclassification of net realized loss, net of tax expense
1,207 
1,141 
Pension and other postretirement benefits activity, net of tax expense
522 
530 
Total other comprehensive income
959 
978 
COMPREHENSIVE INCOME
29,144 
10,304 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,873 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
24,271 
5,431 
APS
 
 
NET INCOME
28,035 
12,126 
Derivative instruments:
 
 
Net unrealized gain (loss), net of tax expense
(770)
(693)
Reclassification of net realized loss, net of tax expense
1,207 
1,141 
Pension and other postretirement benefits activity, net of tax expense
611 
611 
Total other comprehensive income
1,048 
1,059 
COMPREHENSIVE INCOME
29,083 
13,185 
Less: Comprehensive income attributable to noncontrolling interests
4,873 
4,873 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 24,210 
$ 8,312 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Net unrealized loss, tax expense
$ 674 
$ 546 
Reclassification of net realized loss, tax expense
356 
200 
Pension and other postretirement benefits activity, tax expense
704 
645 
Arizona Public Service Company
 
 
Net unrealized loss, tax expense
674 
546 
Reclassification of net realized loss, tax expense
356 
200 
Pension and other postretirement benefits activity, tax expense
$ 590 
$ 558 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 3,028 
$ 8,881 
Customer and other receivables
191,175 
250,491 
Accrued unbilled revenues
101,226 
107,949 
Allowance for doubtful accounts
(1,946)
(3,037)
Materials and supplies (at average cost)
252,598 
253,979 
Fossil fuel (at average cost)
30,656 
28,608 
Income tax receivable
9,531 
3,751 
Assets from risk management activities (Note 6)
4,222 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
17,625 
12,465 
Other regulatory assets (Note 3)
138,316 
94,410 
Other current assets
48,565 
45,028 
Total current assets
794,996 
822,219 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
Nuclear decommissioning trust (Note 11)
805,048 
779,586 
Other assets
70,025 
69,063 
Total investments and other assets
875,073 
848,650 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,436,720 
17,341,888 
Accumulated depreciation and amortization
(6,060,254)
(5,970,100)
Net
11,376,466 
11,371,788 
Construction work in progress
1,005,797 
1,019,947 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
112,548 
113,515 
Intangible assets, net of accumulated amortization
251,208 
90,022 
Nuclear fuel, net of accumulated amortization
135,821 
119,004 
Total property, plant and equipment
12,881,840 
12,714,276 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,321,473 
1,313,428 
Assets for other postretirement benefits (Note 4)
175,414 
166,206 
Other
144,029 
139,474 
Total deferred debits
1,640,916 
1,619,108 
TOTAL ASSETS
16,192,825 
16,004,253 
CURRENT LIABILITIES
 
 
Accounts payable
250,197 
264,631 
Accrued taxes
182,812 
138,964 
Accrued interest
48,576 
52,835 
Common dividends payable
72,926 
Short-term borrowings (Note 2)
207,297 
177,200 
Current maturities of long-term debt (Note 2)
125,000 
125,000 
Customer deposits
76,149 
82,520 
Liabilities from risk management activities (Note 6)
41,932 
25,836 
Liabilities for asset retirements
8,627 
9,135 
Regulatory liabilities (Note 3)
101,208 
99,899 
Other current liabilities
152,015 
244,000 
Total current liabilities
1,193,813 
1,292,946 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
4,273,890 
4,021,785 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,955,441 
2,945,232 
Regulatory liabilities (Note 3)
948,293 
948,916 
Liabilities for asset retirements
623,394 
615,340 
Liabilities for pension benefits (Note 4)
469,746 
509,310 
Liabilities from risk management activities (Note 6)
63,213 
47,238 
Customer advances
92,113 
88,672 
Coal mine reclamation
224,516 
221,910 
Deferred investment tax credit
209,818 
210,162 
Unrecognized tax benefits
10,172 
10,046 
Other
162,476 
156,784 
Total deferred credits and other
5,759,182 
5,753,610 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,587,048 and 111,392,053 issued at respective dates
2,595,042 
2,596,030 
Treasury stock at cost; 29,195 and 55,317 shares at respective dates
(2,270)
(4,133)
Total common stock
2,592,772 
2,591,897 
Retained earnings
2,278,867 
2,255,547 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(38,548)
(39,070)
Derivative instruments
(4,315)
(4,752)
Total accumulated other comprehensive loss
(42,863)
(43,822)
Total shareholders’ equity
4,828,776 
4,803,622 
Noncontrolling interests (Note 5)
137,164 
132,290 
Total equity
4,965,940 
4,935,912 
TOTAL LIABILITIES AND EQUITY
16,192,825 
16,004,253 
Arizona Public Service Company
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
2,933 
8,840 
Customer and other receivables
190,898 
262,611 
Accrued unbilled revenues
101,226 
107,949 
Allowance for doubtful accounts
(1,946)
(3,037)
Materials and supplies (at average cost)
251,360 
252,777 
Fossil fuel (at average cost)
30,656 
28,608 
Income tax receivable
11,195 
11,174 
Assets from risk management activities (Note 6)
4,222 
19,694 
Deferred fuel and purchased power regulatory asset (Note 3)
17,625 
12,465 
Other regulatory assets (Note 3)
138,316 
94,410 
Other current assets
43,040 
41,849 
Total current assets
789,525 
837,340 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 6)
Nuclear decommissioning trust (Note 11)
805,048 
779,586 
Other assets
49,094 
48,320 
Total investments and other assets
854,142 
827,907 
PROPERTY, PLANT AND EQUIPMENT
 
 
Plant in service and held for future use
17,324,182 
17,228,787 
Accumulated depreciation and amortization
(5,974,360)
(5,881,941)
Net
11,349,822 
11,346,846 
Construction work in progress
970,880 
989,497 
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)
112,548 
113,515 
Intangible assets, net of accumulated amortization
251,045 
89,868 
Nuclear fuel, net of accumulated amortization
135,821 
119,004 
Total property, plant and equipment
12,820,116 
12,658,730 
DEFERRED DEBITS
 
 
Regulatory assets (Note 3)
1,321,473 
1,313,428 
Assets for other postretirement benefits (Note 4)
172,071 
162,911 
Other
130,327 
130,859 
Total deferred debits
1,623,871 
1,607,198 
TOTAL ASSETS
16,087,654 
15,931,175 
CURRENT LIABILITIES
 
 
Accounts payable
245,774 
259,161 
Accrued taxes
178,393 
130,576 
Accrued interest
48,349 
52,525 
Common dividends payable
72,900 
Short-term borrowings (Note 2)
116,497 
135,500 
Customer deposits
76,149 
82,520 
Liabilities from risk management activities (Note 6)
41,932 
25,836 
Liabilities for asset retirements
8,182 
8,703 
Regulatory liabilities (Note 3)
101,208 
99,899 
Other current liabilities
149,486 
226,417 
Total current liabilities
965,970 
1,094,037 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
3,008,075 
2,999,295 
Regulatory liabilities (Note 3)
948,293 
948,916 
Liabilities for asset retirements
615,230 
607,234 
Liabilities for pension benefits (Note 4)
449,222 
488,253 
Liabilities from risk management activities (Note 6)
63,213 
47,238 
Customer advances
92,113 
88,672 
Coal mine reclamation
209,126 
206,645 
Deferred investment tax credit
209,818 
210,162 
Unrecognized tax benefits
37,534 
37,408 
Other
148,118 
143,560 
Total deferred credits and other
5,780,742 
5,777,383 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
   
   
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,421,696 
2,421,696 
Retained earnings
2,354,405 
2,331,245 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits
(20,060)
(20,671)
Derivative instruments
(4,315)
(4,752)
Total accumulated other comprehensive loss
(24,375)
(25,423)
Total shareholders’ equity
4,929,888 
4,905,680 
Noncontrolling interests (Note 5)
137,164 
132,290 
Total equity
5,067,052 
5,037,970 
Long-term debt less current maturities (Note 2)
4,273,890 
4,021,785 
Total capitalization
9,340,942 
9,059,755 
TOTAL LIABILITIES AND EQUITY
$ 16,087,654 
$ 15,931,175 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)
Mar. 31, 2017
Dec. 31, 2016
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
 
 
Common stock, par value (in dollars per share)
   
   
Common stock, authorized shares (in shares)
150,000,000 
150,000,000 
Common stock, issued shares (in shares)
111,587,048 
111,392,053 
Treasury stock at cost, shares (in shares)
29,195 
55,317 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
$ 28,185 
$ 9,326 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
147,861 
140,759 
Deferred fuel and purchased power
(988)
1,007 
Deferred fuel and purchased power amortization
(4,172)
2,388 
Allowance for equity funds used during construction
(9,482)
(10,516)
Deferred income taxes
10,357 
3,468 
Deferred investment tax credit
(344)
(114)
Change in derivative instruments fair value
(101)
(111)
Stock compensation
9,997 
16,687 
Changes in current assets and liabilities:
 
 
Customer and other receivables
47,007 
47,282 
Accrued unbilled revenues
6,723 
6,445 
Materials, supplies and fossil fuel
(667)
1,525 
Income tax receivable
(5,780)
(4,048)
Other current assets
(17,353)
(8,131)
Accounts payable
22,147 
(38,443)
Accrued taxes
43,706 
43,289 
Other current liabilities
(101,801)
(38,040)
Change in margin and collateral accounts — assets
(12)
681 
Change in margin and collateral accounts — liabilities
410 
Change in other long-term assets
(36,836)
(17,504)
Change in other long-term liabilities
1,604 
(12,151)
Net cash flow provided by operating activities
140,051 
144,209 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(348,824)
(378,500)
Contributions in aid of construction
5,975 
12,464 
Allowance for borrowed funds used during construction
(4,472)
(5,227)
Proceeds from nuclear decommissioning trust sales
151,126 
141,809 
Investment in nuclear decommissioning trust
(151,696)
(142,379)
Other
(793)
(472)
Net cash flow used for investing activities
(348,684)
(372,305)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
255,441 
Short-term borrowing and payments — net
22,097 
261,800 
Short-term debt borrowings under revolving credit facility
8,000 
Dividends paid on common stock
(71,177)
(67,611)
Common stock equity issuance - net of purchases
(11,580)
8,902 
Other
(1)
Net cash flow provided by financing activities
202,780 
203,092 
NET DECREASE IN CASH AND CASH EQUIVALENTS
(5,853)
(25,004)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,881 
39,488 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
3,028 
14,484 
Cash paid during the period for:
 
 
Income taxes, net of refunds
(2)
2,502 
Interest, net of amounts capitalized
54,280 
56,139 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
79,306 
59,707 
Arizona Public Service Company
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
NET INCOME
28,035 
12,126 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization including nuclear fuel
147,443 
140,729 
Deferred fuel and purchased power
(988)
1,007 
Deferred fuel and purchased power amortization
(4,172)
2,388 
Allowance for equity funds used during construction
(9,482)
(10,516)
Deferred income taxes
8,899 
3,394 
Deferred investment tax credit
(344)
(114)
Change in derivative instruments fair value
(101)
(111)
Changes in current assets and liabilities:
 
 
Customer and other receivables
60,782 
47,575 
Accrued unbilled revenues
6,723 
6,445 
Materials, supplies and fossil fuel
(631)
1,525 
Other current assets
(15,007)
(8,172)
Accounts payable
22,847 
(34,999)
Accrued taxes
47,817 
38,784 
Other current liabilities
(88,990)
(28,748)
Change in margin and collateral accounts — assets
(12)
681 
Change in margin and collateral accounts — liabilities
410 
Change in other long-term assets
(31,172)
(17,375)
Change in other long-term liabilities
1,888 
(1,102)
Net cash flow provided by operating activities
173,535 
153,927 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures
(343,139)
(369,861)
Contributions in aid of construction
5,975 
12,464 
Allowance for borrowed funds used during construction
(4,472)
(5,040)
Proceeds from nuclear decommissioning trust sales
151,126 
141,809 
Investment in nuclear decommissioning trust
(151,696)
(142,379)
Other
(774)
(472)
Net cash flow used for investing activities
(342,980)
(363,479)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Issuance of long-term debt
255,441 
Short-term borrowing and payments — net
(19,003)
261,800 
Dividends paid on common stock
(72,900)
(69,400)
Net cash flow provided by financing activities
163,538 
192,400 
NET DECREASE IN CASH AND CASH EQUIVALENTS
(5,907)
(17,152)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
8,840 
22,056 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
2,933 
4,904 
Cash paid during the period for:
 
 
Income taxes, net of refunds
8,772 
Interest, net of amounts capitalized
53,129 
55,580 
Significant non-cash investing and financing activities:
 
 
Accrued capital expenditures
$ 78,977 
$ 59,707 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Arizona Public Service Company
Arizona Public Service Company
Common Stock
Arizona Public Service Company
Additional Paid-In Capital
Arizona Public Service Company
Retained Earnings
Arizona Public Service Company
Accumulated Other Comprehensive Income (Loss)
Arizona Public Service Company
Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2015
$ 4,719,457 
$ 2,541,668 
$ (5,806)
$ 2,092,803 
$ (44,748)
$ 135,540 
$ 4,814,794 
$ 178,162 
$ 2,379,696 
$ 2,148,493 
$ (27,097)
$ 135,540 
Beginning balance (in shares) at Dec. 31, 2015
 
111,095,402 
115,030 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
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 end 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 
7,936 
 
 
 
 
71,264,947 
 
 
 
 
Balance at beginning of period at Dec. 31, 2016
4,935,912 
2,596,030 
(4,133)
2,255,547 
(43,822)
132,290 
5,037,970 
178,162 
2,421,696 
2,331,245 
(25,423)
132,290 
Beginning balance (in shares) at Dec. 31, 2016
111,392,053 
111,392,053 
55,317 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
28,185 
 
 
23,312 
 
4,873 
28,035 
 
 
23,162 
 
4,873 
Other comprehensive income
959 
 
 
 
959 
 
1,048 
 
 
 
1,048 
 
Other
 
 
 
 
 
 
(1)
 
 
(2)
 
Issuance of common stock (in shares)
 
194,995 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
(988)
(988)
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(153,470)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(12,141)
 
(12,141)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
179,592 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
14,013 
 
14,004 
 
 
 
 
 
 
 
Balance at end of period at Mar. 31, 2017
$ 4,965,940 
$ 2,595,042 
$ (2,270)
$ 2,278,867 
$ (42,863)
$ 137,164 
$ 5,067,052 
$ 178,162 
$ 2,421,696 
$ 2,354,405 
$ (24,375)
$ 137,164 
Ending balance (in shares) at Mar. 31, 2017
111,587,048 
111,587,048 
29,195 
 
 
 
 
71,264,947 
 
 
 
 
Consolidation and Nature of Operations
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC ("4CA"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado").  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 5 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
 
Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
 
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2016 Form 10-K.

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

Statements of Cash Flows for the
Three Months Ended March 31, 2016
As previously
reported
 
Reclassifications to conform to current year presentation
 
Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
 
 
 
 
 
Stock compensation
$

 
$
16,687

 
$
16,687

Change in other long-term liabilities
4,536

 
(16,687
)
 
(12,151
)

 
 
Supplemental Cash Flow Information
 
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2017
 
2016
Cash paid (received) during the period for:
 
 
 
Income taxes, net of refunds
$
(2
)
 
$
2,502

Interest, net of amounts capitalized
54,280

 
56,139

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
79,306

 
$
59,707

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, 2017, Pinnacle West had a $200 million facility that matures in May 2021. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At March 31, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $42.8 million of commercial paper borrowings.

At March 31, 2017, Pinnacle West had a $75 million 364-day unsecured revolving credit facility that matures in August 2017.  Borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At March 31, 2017, Pinnacle West had $48 million outstanding under the facility.
 
APS

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

At March 31, 2017, 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 2021.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2017, APS had $116.5 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 7 for a discussion of APS’s other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

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

 
$
125,000

 
$
125,000

 
$
125,000

APS
4,273,890

 
4,558,285

 
4,021,785

 
4,300,789

Total
$
4,398,890

 
$
4,683,285

 
$
4,146,785

 
$
4,425,789

 
Debt Provisions
 
An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At March 31, 2017, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.4 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.8 billion, assuming APS’s total capitalization remains the same.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). The principal provisions of the application are described in detail in Note 3 of our 2016 Form 10-K.

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

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

On April 27, 2017, Commissioner Burns filed a motion requesting that the ALJ suspend and continue the rate case proceedings and facilitate an investigation to determine whether certain commissioners should be disqualified from further participation in the matter.
The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61 million due to changes in depreciation schedules.

Other key provisions of the agreement include the following:

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

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

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

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

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

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

Demand Side Management Adjustor Charge ("DSMAC").  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") 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 Lost Fixed Cost Recovery Mechanism (“LFCR”) mechanism.

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

On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on the Company’s 2017 DSM Plan.
 
Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.
 
PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):
 
 
Three Months Ended 
 March 31,
 
2017
 
2016
Beginning balance
$
12,465

 
$
(9,688
)
Deferred fuel and purchased power costs — current period
988

 
(1,007
)
Amounts charged to customers
4,172

 
(2,388
)
Ending balance
$
17,625

 
$
(13,083
)

 
The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh.
 
Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters In July 2008, the United States Federal Energy Regulatory Commission ("FERC") approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC staff.  Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.
 
Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2015.

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

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

APS's formula rate implementation protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate implementation protocols and may require companies to make changes to their protocols in the future. As a result, APS made an administrative filing to update its formula rate implementation protocols on March 3, 2017, which was accepted by FERC with an effective date of May 1, 2017.
 
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 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 16, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective for the first billing cycle of March 2017. On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, to be effective with the first billing cycle of April 2017. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Net Metering

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

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

In addition, the ACC made the following determinations:

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

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

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

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case.  APS cannot predict the outcome of this determination.

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

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

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

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.

System Benefits Charge

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

Subpoena from Arizona Corporation Commissioner Robert Burns

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

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

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. APS did not produce the information requested and instead objected to the subpoena. Also, as part of the docket a workshop was held on March 24, 2017. On March 10, 2017, Commissioner Burns filed suit against APS and PNW in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns suit against APS and PNW. APS and Pinnacle West cannot predict the outcome of this matter.

Four Corners
 
On December 30, 2013, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $62 million as of March 31, 2017 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter will be resolved.
 
As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which was published in the Federal Register on March 27, 2017. Parties have until May 26, 2017 (60 days from publication in the Federal Register) to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict whether such petitions will be filed or if they will be successful.
Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates. The 2017 Settlement Agreement described above contemplates continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($114 million as of March 31, 2017), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
Navajo Plant
On February 13, 2017, the co-owners of the Navajo Generating Station (the "Navajo Plant") voted not to pursue continued operation of the plant beyond December 2019, the expiration of the current lease term, and to pursue a new lease or lease extension with the Navajo Nation that would allow decommissioning activities to begin after December 2019 instead of later this year. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. We cannot predict whether any alternate solutions will be found that would be acceptable to all of the stakeholders and feasible to implement. APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($106 million as of March 31, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. While we believe such costs are probable of recovery, we cannot predict whether or to what degree APS would obtain such recovery.
    
On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.
Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
March 31, 2017
 
December 31, 2016
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
699,817

 
$

 
$
711,059

Retired power plant costs
2033
 
9,913

 
115,110

 
9,913

 
117,591

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

 
150,629

 
6,305

 
152,118

Deferred fuel and purchased power — mark-to-market (Note 6)
2020
 
30,203

 
59,428

 

 
42,963

Deferred fuel and purchased power (b) (e)
2018
 
17,625

 

 
12,465

 

Four Corners cost deferral
2024
 
6,689

 
55,221

 
6,689

 
56,894

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

 
54,265

 
2,120

 
54,356

Lost fixed cost recovery (b)
2018
 
70,762

 

 
61,307

 

Palo Verde VIEs (Note 5)
2046
 

 
18,930

 

 
18,775

Deferred compensation
2036
 

 
36,846

 

 
35,595

Deferred property taxes
(c)
 

 
79,447

 

 
73,200

Loss on reacquired debt
2038
 
1,637

 
16,533

 
1,637

 
16,942

Tax expense of Medicare subsidy
2024
 
1,503

 
10,458

 
1,513

 
10,589

Demand Side Management
2018
 
5,491

 

 
3,744

 

AG-1 deferral
2018
 

 
6,976

 

 
5,868

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,625

 
332

 
10,708

Transmission cost adjustor (b)
2018
 
2,071

 
2,460

 

 
1,588

Coal reclamation
2026
 
418

 
4,728

 
418

 
5,182

Other
Various
 
975

 

 
432

 

Total regulatory assets (d)
 
 
$
155,941

 
$
1,321,473

 
$
106,875

 
$
1,313,428


(a)
See Note 4 for further discussion.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Per the provision of the 2012 Settlement Agreement.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."
(e)
Subject to a carrying charge.


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

 
$
298,796

 
$

 
$
279,976

Removal costs
(a)
 
37,194

 
211,348

 
29,899

 
223,145

Other postretirement benefits
(c)
 
32,662

 
115,950

 
32,662

 
123,913

Income taxes — deferred investment tax credit
2046
 
4,315

 
108,691

 
4,368

 
108,827

Income taxes — change in rates
2046
 
2,565

 
69,497

 
1,771

 
70,898

Spent nuclear fuel
2047
 

 
72,755

 

 
71,726

Renewable energy standard (b)
2018
 
22,367

 

 
26,809

 

Demand side management (b)
2019
 

 
19,921

 

 
20,472

Sundance maintenance
2030
 

 
15,690

 

 
15,287

Deferred gains on utility property
2019
 
2,062

 
8,439

 
2,063

 
8,895

Four Corners coal reclamation
2031
 

 
19,684

 

 
18,248

Other
Various
 
43

 
7,522

 
2,327

 
7,529

Total regulatory liabilities
 
 
$
101,208

 
$
948,293

 
$
99,899

 
$
948,916


(a)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
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. Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $145 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. While we do not expect to transfer any funds prior to 2018, as of March 31, 2017, such methodology would result in an amount of approximately $145 million being transferred to the new trust account.

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

 
Pension Benefits
 
Other Benefits
 
Three Months Ended 
 March 31,
 
Three Months Ended 
 March 31,
 
2017
 
2016
 
2017
 
2016
Service cost — benefits earned during the period
$
13,760

 
$
14,266

 
$
4,358

 
$
3,937

Interest cost on benefit obligation
32,701

 
32,945

 
7,565

 
7,341

Expected return on plan assets
(43,710
)
 
(43,792
)
 
(13,350
)
 
(9,122
)
Amortization of:
 

 
 
 
 

 
 

Prior service cost (credit)
20

 
132

 
(9,461
)
 
(9,471
)
Net actuarial loss
12,489

 
9,731

 
1,454

 
946

Net periodic benefit cost
$
15,260

 
$
13,282

 
$
(9,434
)
 
$
(6,369
)
Portion of cost charged to expense
$
7,568

 
$
6,519

 
$
(4,678
)
 
$
(3,126
)

 
Contributions
 
We have made voluntary contributions of $60 million to our pension plan year-to-date in 2017. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2017-2019 period. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans.
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
 
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three months ended March 31, 2017 and 2016 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, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
 
 
March 31, 2017
 
December 31, 2016
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
112,548

 
$
113,515

Equity — Noncontrolling interests
137,164

 
132,290


 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 million over the lease terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
Derivative Accounting
Derivative Accounting
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value.  See Note 10 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
 
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, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Commodity
 
Quantity
Power
 
1,123

 
GWh
Gas
 
226

 
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, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2017
 
2016
Loss Recognized in OCI on Derivative Instruments (Effective Portion)
 
OCI — derivative instruments
 
$
(96
)
 
$
(147
)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
(851
)
 
(941
)

(a)
During the three months ended March 31, 2017 and 2016, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $3 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2017 and 2016 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2017
 
2016
Net Loss Recognized in Income
 
Operating revenues
 
$
(288
)
 
$
(102
)
Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
(52,627
)
 
(30,936
)
Total
 
 
 
$
(52,915
)
 
$
(31,038
)

(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 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, 2017 and December 31, 2016, include gross liabilities of $1 million and $2 million, respectively, of derivative instruments designated as hedging instruments.
 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, 2017 and December 31, 2016.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of March 31, 2017:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheet
Current assets
 
$
28,193

 
$
(23,983
)
 
$
4,210

 
$
12

 
$
4,222

Investments and other assets
 
1,654

 
(1,654
)
 

 

 

Total assets
 
29,847

 
(25,637
)
 
4,210

 
12

 
4,222

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(61,861
)
 
23,983

 
(37,878
)
 
(4,054
)
 
(41,932
)
Deferred credits and other
 
(64,867
)
 
1,654

 
(63,213
)
 

 
(63,213
)
Total liabilities
 
(126,728
)
 
25,637

 
(101,091
)
 
(4,054
)
 
(105,145
)
Total
 
$
(96,881
)
 
$

 
$
(96,881
)
 
$
(4,042
)
 
$
(100,923
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,054.
 
As of December 31, 2016:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheet
Current assets
 
$
48,094

 
$
(28,400
)
 
$
19,694

 
$

 
$
19,694

Investments and other assets
 
6,704

 
(6,703
)
 
1

 

 
1

Total assets
 
54,798

 
(35,103
)
 
19,695

 

 
19,695

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(50,182
)
 
28,400

 
(21,782
)
 
(4,054
)
 
(25,836
)
Deferred credits and other
 
(53,941
)
 
6,703

 
(47,238
)
 

 
(47,238
)
Total liabilities
 
(104,123
)
 
35,103

 
(69,020
)
 
(4,054
)
 
(73,074
)
Total
 
$
(49,325
)
 
$

 
$
(49,325
)
 
$
(4,054
)
 
$
(53,379
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,054.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of March 31, 2017, we have no counterparties with positive exposures of greater than 10% of risk management assets. 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, 2017 (dollars in thousands):
 
March 31, 2017
Aggregate fair value of derivative instruments in a net liability position
$
126,728

Cash collateral posted

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
63,646


(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 $130 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, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 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-wide 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 approximately $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.0 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $19 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million.
 
The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments 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 $24 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 $64.8 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

During the first quarter of 2017 our fuel and purchased power commitments decreased approximately $600 million primarily due to updated estimated renewable energy purchases. The majority of these changes relate to the years 2022 and thereafter.
Other than the items described above, there have been no material changes, as of March 31, 2017, outside the normal course of business in contractual obligations from the information provided in our 2016 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 ("RI/FS").  The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by November 2017. 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. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. The court's order is interlocutory and subject to a pending motion for reconsideration. 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.
  
Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, 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 and the Navajo Plant. EPA 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. EPA recently approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the recent Cholla rule approval.

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required 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. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. 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. On March 20, 2017, the Court denied this petition for review and upheld the legality of EPA's final BART rule for the Navajo Plant. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million, is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.  Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  Briefing in the case was completed in February 2014.

In September 2014, APS met with EPA to propose a compromise BART strategy. 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 a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program.  EPA signed the final rule approving the Agency's proposal on January 13, 2017. Under the terms of an executive memorandum issued on January 20, 2017, this final rule was held back from publication in the Federal Register pending review by incoming EPA leadership. On March 16, 2017, the new EPA Administrator re-signed the final rule, thereby allowing for publication in the Federal Register, which occurred on March 27, 2017. Parties have until May 26, 2017 (60 days from publication in the Federal Register) to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict whether such actions will be filed or if they will be successful.
 
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.
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.
On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds. Because EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act, and Arizona has yet to determine whether it will develop a state-specific permitting program, it is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR.

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. APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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, the majority of which has already been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must collect sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by October 12, 2018. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for electric generating units ("EGUs"). Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. 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. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit to hold the ongoing litigation over the August 2015 pollution standards in abeyance pending EPA action in accordance with the Executive Order. At this time we cannot predict the outcome of EPA's review of the August 2015 carbon pollution standards and whether EPA will take action to suspend, rescind or revise these regulations. The carbon pollution standards for EGUs on state and tribal lands are described in detail in Note 10 of our 2016 Form 10-K.

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, RCRA, Superfund, 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 April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("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.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners.
    
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, 2017, standby letters of credit totaled $35 million and will expire in 2017. As of March 31, 2017, surety bonds expiring through 2019 totaled $61 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, 2017. Effective July 6, 2016, Pinnacle West has issued two parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.
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, 2017 and 2016 (dollars in thousands):

 
Three Months Ended 
 March 31,
 
2017
 
2016
Other income:
 

 
 

Interest income
$
477

 
$
117

Miscellaneous
3

 

Total other income
$
480

 
$
117

Other expense:
 

 
 

Non-operating costs
$
(1,959
)
 
$
(2,049
)
Investment losses — net
(301
)
 
(518
)
Miscellaneous
(1,420
)
 
(1,471
)
Total other expense
$
(3,680
)
 
$
(4,038
)
The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2017 and 2016 (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2017
 
2016
Other income:
 

 
 

Interest income
$
338

 
$
73

Gain on disposition of property
308

 
332

Miscellaneous
416

 
205

Total other income
$
1,062

 
$
610

Other expense:
 

 
 

Non-operating costs (a)
$
(2,166
)
 
$
(1,966
)
Loss on disposition of property
(88
)
 
(426
)
Miscellaneous
(2,124
)
 
(2,358
)
Total other expense
$
(4,378
)
 
$
(4,750
)

(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, 2017 and 2016 (in thousands, except per share amounts):
 
Three Months Ended 
 March 31,
 
 
2017
 
2016
 
Net income attributable to common shareholders
$
23,312

 
$
4,453

 
Weighted average common shares outstanding — basic
111,728

 
111,296

 
Net effect of dilutive securities:
 

 
 

 
Contingently issuable performance shares and restricted stock units
467

 
551

 
Weighted average common shares outstanding — diluted
112,195

 
111,847

 
Earnings per weighted-average common share outstanding
 
 
 
 
Net income attributable to common shareholders — basic
$
0.21

 
$
0.04

 
Net income attributable to common shareholders — diluted
$
0.21

 
$
0.04

 
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. Instruments valued using NAV, as a practical expedient, are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments.  See Note 7 in the 2016 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.

Coal Reclamation Trust Investments