PINNACLE WEST CAPITAL CORP, 10-K filed on 2/19/2016
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2015
Feb. 12, 2016
Jun. 30, 2015
Entity Information [Line Items]
 
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
 
Entity Central Index Key
0000764622 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2015 
 
 
Amendment Flag
false 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Public Float
 
 
$ 6,271,269,171 
Entity Common Stock, Shares Outstanding
 
111,004,916 
 
Document Fiscal Year Focus
2015 
 
 
Document Fiscal Period Focus
FY 
 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Entity Information [Line Items]
 
 
 
Entity Registrant Name
ARIZONA PUBLIC SERVICE COMPANY 
 
 
Entity Central Index Key
0000007286 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2015 
 
 
Amendment Flag
false 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Non-accelerated Filer 
 
 
Entity Public Float
 
 
$ 0 
Entity Common Stock, Shares Outstanding
 
71,264,947 
 
Document Fiscal Year Focus
2015 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
OPERATING REVENUES
$ 3,495,443 
$ 3,491,632 
$ 3,454,628 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,101,298 
1,179,829 
1,095,709 
Operations and maintenance
868,377 
908,025 
924,727 
Depreciation and amortization
494,422 
417,358 
415,708 
Taxes other than income taxes
171,812 
172,295 
164,167 
Other expenses
4,932 
2,883 
7,994 
Total
2,640,841 
2,680,390 
2,608,305 
OPERATING INCOME
854,602 
811,242 
846,323 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
35,215 
30,790 
25,581 
Other income (Note 17)
621 
9,608 
1,704 
Other expense (Note 17)
(17,823)
(21,746)
(16,024)
Total
18,013 
18,652 
11,261 
INTEREST EXPENSE
 
 
 
Interest charges
194,964 
200,950 
201,888 
Allowance for borrowed funds used during construction (Note 1)
(16,259)
(15,457)
(14,861)
Total
178,705 
185,493 
187,027 
INCOME BEFORE INCOME TAXES
693,910 
644,401 
670,557 
INCOME TAXES (Note 4)
237,720 
220,705 
230,591 
NET INCOME
456,190 
423,696 
439,966 
Less: Net income attributable to noncontrolling interests (Note 18)
18,933 
26,101 
33,892 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
437,257 
397,595 
406,074 
Weighted Average common shares outstanding — basic (in shares)
111,026 
110,626 
109,984 
Weighted Average common shares outstanding — diluted (in shares)
111,552 
111,178 
110,806 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.94 
$ 3.59 
$ 3.69 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 3.92 
$ 3.58 
$ 3.66 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
ELECTRIC OPERATING REVENUES
3,492,357 
3,488,946 
3,451,251 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,101,298 
1,179,829 
1,095,709 
Operations and maintenance
853,135 
882,442 
897,824 
Depreciation and amortization
494,298 
417,264 
415,612 
Taxes other than income taxes
171,499 
171,583 
163,377 
Income taxes (Note 4)
260,143 
245,036 
256,864 
Total
2,880,373 
2,896,154 
2,829,386 
OPERATING INCOME
611,984 
592,792 
621,865 
OTHER INCOME (DEDUCTIONS)
 
 
 
Income taxes (Note 4)
14,302 
7,676 
11,769 
Allowance for equity funds used during construction (Note 1)
35,215 
30,790 
25,581 
Other income (Note 17)
2,834 
11,295 
3,896 
Other expense (Note 17)
(19,019)
(13,403)
(20,449)
Total
33,332 
36,358 
20,797 
INTEREST EXPENSE
 
 
 
Interest on long-term debt
180,123 
186,323 
188,011 
Interest on short-term borrowings
7,376 
6,796 
6,605 
Debt discount, premium and expense
4,793 
4,168 
4,046 
Allowance for borrowed funds used during construction (Note 1)
(16,183)
(15,457)
(14,861)
Total
176,109 
181,830 
183,801 
INCOME TAXES (Note 4)
245,841 
237,360 
245,095 
NET INCOME
469,207 
447,320 
458,861 
Less: Net income attributable to noncontrolling interests (Note 18)
18,933 
26,101 
33,892 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 450,274 
$ 421,219 
$ 424,969 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
NET INCOME
$ 456,190 
$ 423,696 
$ 439,966 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(957)
(810)
(213)
Reclassification of net realized loss, net of tax benefit
4,187 
13,483 
26,747 
Pension and other postretirement benefits activity, net of tax (expense) benefit
20,163 
(2,761)
9,421 
Total other comprehensive income
23,393 
9,912 
35,955 
COMPREHENSIVE INCOME
479,583 
433,608 
475,921 
Less: Comprehensive income attributable to noncontrolling interests
18,933 
26,101 
33,892 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
460,650 
407,507 
442,029 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
NET INCOME
469,207 
447,320 
458,861 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(957)
(809)
(214)
Reclassification of net realized loss, net of tax benefit
4,187 
13,483 
26,747 
Pension and other postretirement benefits activity, net of tax (expense) benefit
18,006 
(7,635)
9,190 
Total other comprehensive income
21,236 
5,039 
35,723 
COMPREHENSIVE INCOME
490,443 
452,359 
494,584 
Less: Comprehensive income attributable to noncontrolling interests
18,933 
26,101 
33,892 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 471,510 
$ 426,258 
$ 460,692 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Net unrealized loss, tax benefit (expense)
$ (342)
$ (438)
$ 140 
Reclassification of net realized loss, tax benefit
1,801 
7,932 
17,472 
Pension and other postretirement benefits activity, tax (expense) benefit
(13,302)
1,307 
(6,156)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net unrealized loss, tax benefit (expense)
(342)
(438)
140 
Reclassification of net realized loss, tax benefit
1,801 
7,932 
17,472 
Pension and other postretirement benefits activity, tax (expense) benefit
$ (11,776)
$ 4,655 
$ (6,003)
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 39,488 
$ 7,604 
Customer and other receivables
274,691 
297,740 
Accrued unbilled revenues
96,240 
100,533 
Allowance for doubtful accounts
(3,125)
(3,094)
Materials and supplies (at average cost)
234,234 
218,889 
Fossil fuel (at average cost)
45,697 
37,097 
Deferred income taxes (Note 4)
122,232 
Income tax receivable (Note 4)
589 
3,098 
Assets from risk management activities (Note 16)
15,905 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
Other regulatory assets (Note 3)
149,555 
129,808 
Other current assets
37,242 
38,817 
Total current assets
890,516 
973,435 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
12,106 
17,620 
Nuclear decommissioning trust (Notes 13 and 19)
735,196 
713,866 
Other assets
52,518 
54,047 
Total investments and other assets
799,820 
785,533 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
16,222,232 
15,543,063 
Accumulated depreciation and amortization
(5,594,094)
(5,397,751)
Net
10,628,138 
10,145,312 
Construction work in progress
816,307 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation of $233,665 and $229,795 (Note 18)
117,385 
121,255 
Intangible assets, net of accumulated amortization of $546,038 and $489,538
123,975 
119,755 
Nuclear fuel, net of accumulated amortization of $146,228 and $143,554
123,139 
125,201 
Total property, plant and equipment
11,808,944 
11,194,330 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,214,146 
1,054,087 
Assets for other postretirement benefits (Note 7)
185,997 
152,290 
Other
128,835 
129,215 
Total deferred debits
1,528,978 
1,335,592 
Total Assets
15,028,258 
14,288,890 
CURRENT LIABILITIES
 
 
Accounts payable
297,480 
295,211 
Accrued taxes (Note 4)
138,600 
140,613 
Accrued interest
56,305 
52,603 
Common dividends payable
69,363 
65,790 
Short-term borrowings (Note 5)
147,400 
Current maturities of long-term debt (Note 6)
357,580 
383,570 
Customer deposits
73,073 
72,307 
Liabilities from risk management activities (Note 16)
77,716 
59,676 
Liabilities for asset retirements (Note 11)
28,573 
32,462 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
Other regulatory liabilities (Note 3)
136,078 
130,549 
Other current liabilities
197,861 
178,962 
Total current liabilities
1,442,317 
1,559,143 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
3,462,391 
3,006,573 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,723,425 
2,582,636 
Regulatory liabilities (Notes 1, 3, 4 and 7)
994,152 
1,051,196 
Liabilities for asset retirements (Note 11)
415,003 
358,288 
Liabilities for pension benefits (Note 7)
480,998 
453,736 
Liabilities from risk management activities (Note 16)
89,973 
50,602 
Customer advances
115,609 
123,052 
Coal mine reclamation
201,984 
198,292 
Deferred investment tax credit
187,080 
178,607 
Unrecognized tax benefits (Note 4)
9,524 
19,377 
Other
186,345 
188,286 
Total deferred credits and other
5,404,093 
5,204,072 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, 111,095,402 and 110,649,762 issued at respective dates
2,541,668 
2,512,970 
Treasury stock at cost; 115,030 shares at end of 2015 and 78,400 shares at end of 2014
(5,806)
(3,401)
Total common stock
2,535,862 
2,509,569 
Retained earnings
2,092,803 
1,926,065 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(37,593)
(57,756)
Derivative instruments (Note 16)
(7,155)
(10,385)
Total accumulated other comprehensive loss
(44,748)
(68,141)
Total shareholders’ equity
4,583,917 
4,367,493 
Noncontrolling interests (Note 18)
135,540 
151,609 
Total equity
4,719,457 
4,519,102 
Total Liabilities and Equity
15,028,258 
14,288,890 
ARIZONA PUBLIC SERVICE COMPANY
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
22,056 
4,515 
Customer and other receivables
274,428 
297,712 
Accrued unbilled revenues
96,240 
100,533 
Allowance for doubtful accounts
(3,125)
(3,094)
Materials and supplies (at average cost)
234,234 
218,889 
Fossil fuel (at average cost)
45,697 
37,097 
Deferred income taxes (Note 4)
55,253 
Assets from risk management activities (Note 16)
15,905 
13,785 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
Other regulatory assets (Note 3)
149,555 
129,808 
Other current assets
35,765 
38,693 
Total current assets
870,755 
900,117 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
12,106 
17,620 
Nuclear decommissioning trust (Notes 13 and 19)
735,196 
713,866 
Other assets
34,455 
33,362 
Total investments and other assets
781,757 
764,848 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
16,218,724 
15,539,811 
Accumulated depreciation and amortization
(5,590,937)
(5,394,650)
Net
10,627,787 
10,145,161 
Construction work in progress
812,845 
682,807 
Palo Verde sale leaseback, net of accumulated depreciation of $233,665 and $229,795 (Note 18)
117,385 
121,255 
Intangible assets, net of accumulated amortization of $546,038 and $489,538
123,820 
119,600 
Nuclear fuel, net of accumulated amortization of $146,228 and $143,554
123,139 
125,201 
Total property, plant and equipment
11,804,976 
11,194,024 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,214,146 
1,054,087 
Assets for other postretirement benefits (Note 7)
182,625 
149,260 
Other
127,923 
128,026 
Total deferred debits
1,524,694 
1,331,373 
Total Assets
14,982,182 
14,190,362 
CURRENT LIABILITIES
 
 
Accounts payable
291,574 
289,930 
Accrued taxes (Note 4)
144,488 
131,110 
Accrued interest
56,003 
52,358 
Common dividends payable
69,400 
65,800 
Short-term borrowings (Note 5)
147,400 
Current maturities of long-term debt (Note 6)
357,580 
383,570 
Customer deposits
73,073 
72,307 
Liabilities from risk management activities (Note 16)
77,716 
59,676 
Liabilities for asset retirements (Note 11)
28,573 
32,000 
Deferred fuel and purchased power regulatory liability (Note 3)
9,688 
Other regulatory liabilities (Note 3)
136,078 
130,549 
Other current liabilities
180,535 
167,302 
Total current liabilities
1,424,708 
1,532,464 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,764,489 
2,571,365 
Regulatory liabilities (Notes 1, 3, 4 and 7)
994,152 
1,051,196 
Liabilities for asset retirements (Note 11)
415,003 
358,288 
Liabilities for pension benefits (Note 7)
459,065 
424,508 
Liabilities from risk management activities (Note 16)
89,973 
50,602 
Customer advances
115,609 
123,052 
Coal mine reclamation
201,984 
198,292 
Deferred investment tax credit
187,080 
178,607 
Unrecognized tax benefits (Note 4)
35,251 
45,740 
Other
142,683 
144,823 
Total deferred credits and other
5,405,289 
5,146,473 
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
2,148,493 
1,968,718 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(19,942)
(37,948)
Derivative instruments (Note 16)
(7,155)
(10,385)
Total accumulated other comprehensive loss
(27,097)
(48,333)
Total shareholders’ equity
4,679,254 
4,478,243 
Noncontrolling interests (Note 18)
135,540 
151,609 
Total equity
4,814,794 
4,629,852 
Long-term debt less current maturities (Note 6)
3,337,391 
2,881,573 
Total capitalization
8,152,185 
7,511,425 
Total Liabilities and Equity
$ 14,982,182 
$ 14,190,362 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 233,665 
$ 229,795 
Accumulated amortization on intangible assets
546,038 
489,538 
Accumulated amortization on nuclear fuel
146,228 
143,554 
EQUITY
 
 
Common stock, par value
$ 0 
$ 0 
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
111,095,402 
110,649,762 
Treasury stock at cost, shares
115,030 
78,400 
ARIZONA PUBLIC SERVICE COMPANY
 
 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
233,665 
229,795 
Accumulated amortization on intangible assets
546,038 
489,538 
Accumulated amortization on nuclear fuel
$ 146,228 
$ 143,554 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$ 456,190 
$ 423,696 
$ 439,966 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
571,664 
496,487 
492,322 
Deferred fuel and purchased power
14,997 
(26,927)
21,678 
Deferred fuel and purchased power amortization
1,617 
40,757 
31,190 
Allowance for equity funds used during construction
(35,215)
(30,790)
(25,581)
Deferred income taxes
236,819 
159,023 
249,296 
Deferred investment tax credit
8,473 
26,246 
52,542 
Change in derivative instruments fair value
(381)
339 
534 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(22,219)
(52,672)
(44,991)
Accrued unbilled revenues
4,293 
(3,737)
(1,951)
Materials, supplies and fossil fuel
(23,945)
3,724 
(11,878)
Income tax receivable
2,509 
132,419 
(133,094)
Other current assets
3,145 
4,384 
(17,913)
Accounts payable
(34,266)
(353)
45,414 
Accrued taxes
(2,013)
9,615 
6,059 
Other current liabilities
603 
17,892 
(7,513)
Change in margin and collateral accounts — assets
(324)
(343)
993 
Change in margin and collateral accounts — liabilities
22,776 
(24,975)
12,355 
Change in long-term income tax receivable
137,270 
Change in unrecognized tax benefits
(10,328)
2,778 
(91,425)
Change in long-term regulatory liabilities
(20,535)
59,618 
64,473 
Change in other long-term assets
2,426 
(56,561)
(42,389)
Change in other long-term liabilities
(81,959)
(80,993)
(24,050)
Net cash flow provided by operating activities
1,094,327 
1,099,627 
1,153,307 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,076,087)
(910,634)
(1,016,322)
Contributions in aid of construction
46,546 
20,325 
41,090 
Allowance for borrowed funds used during construction
(16,259)
(15,457)
(14,861)
Proceeds from nuclear decommissioning trust sales
478,813 
356,195 
446,025 
Investment in nuclear decommissioning trust
(496,062)
(373,444)
(463,274)
Other
(3,184)
347 
(2,059)
Net cash flow used for investing activities
(1,066,233)
(922,668)
(1,009,401)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
842,415 
731,126 
136,307 
Repayment of long-term debt
(415,570)
(652,578)
(122,828)
Short-term borrowings and payments — net
(147,400)
(5,725)
60,950 
Dividends paid on common stock
(260,027)
(246,671)
(235,244)
Common stock equity issuance - net of purchases
19,373 
15,288 
17,319 
Distributions to noncontrolling interests
(35,002)
(20,482)
(17,385)
Other
161 
299 
Net cash flow provided by (used for) financing activities
3,790 
(178,881)
(160,582)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
31,884 
(1,922)
(16,676)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
7,604 
9,526 
26,202 
CASH AND CASH EQUIVALENTS AT END OF YEAR
39,488 
7,604 
9,526 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
6,550 
(102,154)
18,537 
Interest, net of amounts capitalized
170,209 
177,074 
184,010 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
83,798 
44,712 
33,184 
Dividends declared but not paid
69,363 
65,790 
62,528 
Liabilities assumed related to acquisition of SCE’s Four Corners’ interest
145,609 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
469,207 
447,320 
458,861 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
571,540 
496,393 
492,226 
Deferred fuel and purchased power
14,997 
(26,927)
21,678 
Deferred fuel and purchased power amortization
1,617 
40,757 
31,190 
Allowance for equity funds used during construction
(35,215)
(30,790)
(25,581)
Deferred income taxes
223,069 
155,401 
278,101 
Deferred investment tax credit
8,473 
26,246 
52,542 
Change in derivative instruments fair value
(381)
339 
534 
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(21,040)
(52,466)
(46,552)
Accrued unbilled revenues
4,293 
(3,737)
(1,951)
Materials, supplies and fossil fuel
(23,945)
3,724 
(11,878)
Income tax receivable
135,179 
(134,590)
Other current assets
4,498 
3,766 
(17,112)
Accounts payable
(34,891)
(2,355)
47,870 
Accrued taxes
13,378 
8,650 
5,760 
Other current liabilities
(3,718)
33,970 
(9,005)
Change in margin and collateral accounts — assets
(324)
(343)
993 
Change in margin and collateral accounts — liabilities
22,776 
(24,975)
12,355 
Change in long-term income tax receivable
137,665 
Change in unrecognized tax benefits
(10,328)
2,778 
(91,244)
Change in long-term regulatory liabilities
(20,535)
59,618 
64,473 
Change in other long-term assets
(813)
(62,739)
(46,675)
Change in other long-term liabilities
(82,628)
(85,642)
(24,969)
Net cash flow provided by operating activities
1,100,030 
1,124,167 
1,194,691 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,072,053)
(910,084)
(1,016,322)
Contributions in aid of construction
46,546 
20,325 
41,090 
Allowance for borrowed funds used during construction
(16,183)
(15,457)
(14,861)
Proceeds from nuclear decommissioning trust sales
478,813 
356,195 
446,025 
Investment in nuclear decommissioning trust
(496,062)
(373,444)
(463,274)
Other
(1,093)
347 
(2,067)
Net cash flow used for investing activities
(1,060,032)
(922,118)
(1,009,409)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
842,415 
606,126 
136,307 
Repayment of long-term debt
(415,570)
(527,578)
(122,828)
Short-term borrowings and payments — net
(147,400)
(5,725)
60,950 
Dividends paid on common stock
(266,900)
(253,600)
(242,100)
Distributions to noncontrolling interests
(35,002)
(20,482)
(17,385)
Net cash flow provided by (used for) financing activities
(22,457)
(201,259)
(185,056)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
17,541 
790 
226 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
4,515 
3,725 
3,499 
CASH AND CASH EQUIVALENTS AT END OF YEAR
22,056 
4,515 
3,725 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
14,831 
(86,054)
7,524 
Interest, net of amounts capitalized
167,670 
173,436 
180,757 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
83,798 
44,712 
33,184 
Dividends declared but not paid
69,400 
65,800 
62,500 
Liabilities assumed related to acquisition of SCE’s Four Corners’ interest
$ 0 
$ 0 
$ 145,609 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
ARIZONA PUBLIC SERVICE COMPANY
ARIZONA PUBLIC SERVICE COMPANY
Common Stock
ARIZONA PUBLIC SERVICE COMPANY
Additional Paid-In Capital
ARIZONA PUBLIC SERVICE COMPANY
Retained Earnings
ARIZONA PUBLIC SERVICE COMPANY
Accumulated Other Comprehensive Income (Loss)
ARIZONA PUBLIC SERVICE COMPANY
Noncontrolling Interests
Beginning Balance at Dec. 31, 2012
$ 4,102,289 
$ 2,466,923 
$ (4,211)
$ 1,624,102 
$ (114,008)
$ 129,483 
$ 4,222,483 
$ 178,162 
$ 2,379,696 
$ 1,624,237 
$ (89,095)
$ 129,483 
Beginning Balance (in shares) at Dec. 31, 2012
 
109,837,957 
95,192 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
439,966 
 
 
406,074 
 
33,892 
458,861 
 
 
424,969 
 
33,892 
Other comprehensive income
35,955 
 
 
 
35,955 
 
35,723 
 
 
 
35,723 
 
Dividends on common stock
(244,903)
 
 
(244,903)
 
 
(244,800)
 
 
(244,800)
 
 
Other
 
 
 
 
 
 
(8)
 
 
(8)
 
 
Issuance of common stock
24,635 
24,635 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
442,746 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(9,727)
 
(9,727)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(174,290)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
9,630 
 
9,630 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
170,538 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(17,385)
 
 
 
 
(17,385)
(17,385)
 
 
 
 
(17,385)
Ending Balance at Dec. 31, 2013
4,340,460 
2,491,558 
(4,308)
1,785,273 
(78,053)
145,990 
4,454,874 
178,162 
2,379,696 
1,804,398 
(53,372)
145,990 
Ending Balance (in shares) at Dec. 31, 2013
 
110,280,703 
98,944 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
423,696 
 
 
397,595 
 
26,101 
447,320 
 
 
421,219 
 
26,101 
Other comprehensive income
9,912 
 
 
 
9,912 
 
5,039 
 
 
 
5,039 
 
Dividends on common stock
(256,803)
 
 
(256,803)
 
 
(256,900)
 
 
(256,900)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
21,412 
21,412 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
369,059 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(7,893)
 
(7,893)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(139,746)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
8,800 
 
8,800 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
160,290 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(20,482)
 
 
 
 
(20,482)
(20,482)
 
 
 
 
(20,482)
Ending Balance at Dec. 31, 2014
4,519,102 
2,512,970 
(3,401)
1,926,065 
(68,141)
151,609 
4,629,852 
178,162 
2,379,696 
1,968,718 
(48,333)
151,609 
Ending Balance (in shares) at Dec. 31, 2014
110,649,762 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
456,190 
 
 
437,257 
 
18,933 
469,207 
 
 
450,274 
 
18,933 
Other comprehensive income
23,393 
 
 
 
23,393 
 
21,236 
 
 
 
21,236 
 
Dividends on common stock
(270,519)
 
 
(270,519)
 
 
(270,500)
 
 
(270,500)
 
 
Other
 
 
 
 
 
 
 
 
 
 
Issuance of common stock
28,698 
28,698 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
445,640 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(10,136)
 
(10,136)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(154,751)
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other
7,731 
 
7,731 
 
 
 
 
 
 
 
 
 
Reissuance of treasury stock for stock-based compensation and other (in shares)
 
 
118,121 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(35,002)
 
 
 
 
(35,002)
(35,002)
 
 
 
 
(35,002)
Ending Balance 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 
Ending Balance (in shares) at Dec. 31, 2015
111,095,402 
111,095,402 
115,030 
 
 
 
 
71,264,947 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.44 
$ 2.33 
$ 2.23 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies

Description of Business and Basis of Presentation
 
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, and BCE. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.  El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado and BCE. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).
 
Our 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.
 
Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with 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.

Regulatory Accounting
 
APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates.  Regulatory liabilities generally represent expected future costs that have already been collected from customers.
 
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
 
See Note 3 for additional information.
 
Electric Revenues
 
We derive electric revenues primarily from sales of electricity to our regulated Native Load customers.  Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers.  The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month.  Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed.  Differences historically between the actual and estimated unbilled revenues are immaterial.  We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
 
Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income.  In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy.  This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow.  We net these book-outs, which reduces both revenues and fuel and purchased power costs.
 
Some of our cost recovery mechanisms are alternative revenue programs.  For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

Allowance for Doubtful Accounts
 
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible.  The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues.  The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.
 
Property, Plant and Equipment
 
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities.  We report utility plant at its original cost, which includes:
 
material and labor;
contractor costs;
capitalized leases;
construction overhead costs (where applicable); and
allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, 2015 and 2014 consolidated balance sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2015
 
2014
Generation
$
7,336,902

 
$
7,158,729

Transmission
2,494,744

 
2,247,309

Distribution
5,543,561

 
5,339,322

General plant
847,025

 
797,703

Plant in service and held for future use
16,222,232

 
15,543,063

Accumulated depreciation and amortization
(5,594,094
)
 
(5,397,751
)
Net
10,628,138

 
10,145,312

Construction work in progress
816,307

 
682,807

Palo Verde sale leaseback, net of accumulated depreciation
117,385

 
121,255

Intangible assets, net of accumulated amortization
123,975

 
119,755

Nuclear fuel, net of accumulated amortization
123,139

 
125,201

Total property, plant and equipment
$
11,808,944

 
$
11,194,330



Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 11.
 
APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations.  APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.
 
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2015 were as follows:
 
Fossil plant — 19 years;
Nuclear plant — 28 years;
Other generation — 25 years;
Transmission — 39 years;
Distribution — 33 years; and
Other — 7 years.
 
Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS's acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. See Note 3 for further discussion. These costs were deferred and are now being amortized on the depreciation line of the Consolidated Statements of Income.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $430 million in 2015, $396 million in 2014, and $400 million in 2013. For the years 2013 through 2015, the depreciation rates ranged from a low of 0.30% to a high of 12.37%.  The weighted-average depreciation rate was 2.74% in 2015, 2.77% in 2014, and 3.00% in 2013.
 
Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
 
AFUDC was calculated by using a composite rate of 8.02% for 2015, 8.47% for 2014, and 8.56% for 2013.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
 
Materials and Supplies
 
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
 
Fair Value Measurements
 
We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis.  Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).
 
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
 
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
 
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.
 
See Note 13 for additional information about fair value measurements.
 
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial 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.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  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 expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  See Note 16 for additional information about our derivative instruments.
 
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
 
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries.  We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.  See Note 7 for additional information on pension and other postretirement benefits.
 
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE suspended the fee.  In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2016. See Note 10 for information on spent nuclear fuel disposal costs.
 
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).
 
Cash and Cash Equivalents
 
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
 
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
 
 
Year ended December 31,
 
2015
 
2014
 
2013
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
6,550

 
$
(102,154
)
 
$
18,537

Interest, net of amounts capitalized
170,209

 
177,074

 
184,010

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
83,798

 
$
44,712

 
$
33,184

Dividends declared but not paid
69,363

 
65,790

 
62,528

Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)

 

 
145,609


Intangible Assets
 
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives.  Amortization expense was $58 million in 2015, $53 million in 2014, and $53 million in 2013.  Estimated amortization expense on existing intangible assets over the next five years is $48 million in 2016, $36 million in 2017, $18 million in 2018, $9 million in 2019, and $3 million in 2020.  At December 31, 2015, the weighted-average remaining amortization period for intangible assets was 5 years.
 
Investments
 
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments.
 
Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.

Preferred Stock

At December 31, 2015, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.
New Accounting Standards
New Accounting Standards
New Accounting Standards
 
In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The new revenue standard will be effective for us on January 1, 2018. The guidance may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We are currently evaluating this new guidance and the impacts it may have on our financial statements.

In February 2015, new consolidation accounting guidance was issued that amends many aspects of the guidance relating to the analysis and consolidation of variable interest entities. The new guidance  is effective for us, and will be adopted, during the first quarter of 2016; and may be adopted using either a full retrospective or modified retrospective approach. We do not expect the adoption of this guidance to have a material impact on our financial statements.

In January 2016, new guidance was issued relating to the recognition and measurement of financial instruments. The amended guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.
During the fourth quarter of 2015 we elected to early adopt the following accounting standard updates:
 
Balance sheet presentation of deferred income taxes. See Note 4.

Balance sheet presentation of debt issuance costs: Adopted on a retrospective basis, the new guidance requires debt issuance costs to be presented on the balance sheets as a direct reduction to the related debt liabilities. Prior to the adoption of this guidance we were required to present debt issuance costs as an asset on the balance sheets. As a result of adopting this guidance, our December 31, 2015 Consolidated Balance Sheet includes $28 million of debt issuance costs as a reduction to our long-term debt. Our December 31, 2014 Consolidated Balance Sheet presents $25 million of debt issuance costs as a reduction to long-term debt; this amount was previously presented as a component of non-current other deferred debits. The adoption of this guidance did not impact our results of operations or cash flows. Debt issuance costs continue to be amortized as interest expense. See Note 6.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filings with the Arizona Corporation Commission

Upcoming Rate Case Filing

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

Prior Rate Case Filing
 
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
Settlement Agreement
 
The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate 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 include the following:
An authorized return on common equity of 10.0%;
A capital structure comprised of 46.1% debt and 53.9% common equity;
A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;
Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows: 
Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and
Deferral of 100% in all years if Arizona property tax rates decrease;
A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);
Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;
Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
Modifications to the PSA, including the elimination of the 90/10 sharing provision;
A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2009 Settlement Agreement;
Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;
Modification of the TCA to streamline the process for future transmission-related rate changes; and
Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.
 
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
 
In 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014.  The revised rules went into effect on April 21, 2015.

In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program.  In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program, called the "Solar Partner Program", is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the requested budget to approximately $152 million.

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.
 
Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan for review by and approval of the ACC.

On June 1, 2012, APS filed its 2013 DSM Plan.  In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.
 
On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.

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

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.
 
Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rulemaking has not been initiated and there has been no additional action on the draft to date.
 
PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2015 and 2014 (dollars in thousands):
 
 
Year Ended December 31,
 
2015
 
2014
Beginning balance
$
6,926

 
$
20,755

Deferred fuel and purchased power costs - current period
(14,997
)
 
26,927

Amounts charged to customers
(1,617
)
 
(40,756
)
Ending balance
$
(9,688
)
 
$
6,926


 
The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh.  On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, 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, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014.

Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2015.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future.
 
Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units.
 
APS files for a LFCR adjustment every January.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016.

Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electric grid.   The fixed charge does not increase APS's revenue because it is credited to the LFCR.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 

                On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing has been scheduled to commence in April 2016.  APS cannot predict the outcome of this proceeding.

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

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

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument is set for March 22, 2016.   If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter.

Four Corners
 
On December 30, 2013, APS purchased 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 $70 million as of December 31, 2015 and is being amortized in rates over a total of 10 years.  On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter will be resolved.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement” that, upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group. However, this alternative arrangement was not approved by FERC.  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 has established a regulatory asset of $12 million at December 31, 2015 in connection with the expiration of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates.

Cholla
On September 11, 2014, APS announced that it would close Cholla Unit 2 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and plans to seek recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its next retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($122 million as of December 31, 2015), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

Regulatory Assets and Liabilities
 
The detail of regulatory assets is as follows (dollars in thousands):
 
Amortization Through
 
December 31, 2015
 
December 31, 2014
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
619,223

 
$

 
$
485,037

Retired power plant costs
2033
 
9,913

 
127,518

 
9,913

 
136,182

Income taxes - AFUDC equity
2045
 
5,495

 
133,712

 
4,813

 
118,396

Deferred fuel and purchased power — mark-to-market (Note 16)
2018
 
71,852

 
69,697

 
51,209

 
46,233

Four Corners cost deferral
2024
 
6,689

 
63,582

 
6,689

 
70,565

Income taxes — investment tax credit basis adjustment
2045
 
1,766

 
48,462

 
1,716

 
46,200

Lost fixed cost recovery
2016
 
45,507

 

 
37,612

 

Palo Verde VIEs (Note 18)
2046
 

 
18,143

 

 
34,440

Deferred compensation
2036
 

 
34,751

 

 
34,162

Deferred property taxes
(d)
 

 
50,453

 

 
30,283

Loss on reacquired debt
2034
 
1,515

 
16,375

 
1,435

 
16,410

Tax expense of Medicare subsidy
2024
 
1,520

 
12,163

 
1,528

 
13,756

Transmission vegetation management
2016
 
4,543

 

 
9,086

 
4,543

Mead-Phoenix transmission line CIAC
2050
 
332

 
11,040

 
332

 
11,372

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

 

 
6,926

 

Coal reclamation
2026
 
418

 
6,085

 
418

 
6,503

Pension and other postretirement benefits deferral
2015
 

 

 
4,238

 

Other
Various
 
5

 
2,942

 
819

 
5

Total regulatory assets (e)
 
 
$
149,555

 
$
1,214,146

 
$
136,734

 
$
1,054,087


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.  See Note 7 for further discussion.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
Per the provision of the 2012 Settlement Agreement.
(e)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
The detail of regulatory liabilities is as follows (dollars in thousands):
 
Amortization Through
 
December 31, 2015
 
December 31, 2014
 
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Asset retirement obligations
2057
 
$

 
$
277,554

 
$

 
$
295,546

Removal costs
(a)
 
39,746

 
240,367

 
31,033

 
272,825

Other postretirement benefits
(d)
 
34,100

 
179,521

 
32,317

 
198,599

Income taxes — deferred investment tax credit
2045
 
3,604

 
97,175

 
3,505

 
92,727

Income taxes - change in rates
2045
 
1,113

 
72,454

 
371

 
72,423

Spent nuclear fuel
2047
 
3,051

 
67,437

 
4,396

 
65,594

Renewable energy standard (b)
2017
 
43,773

 
4,365

 
24,596

 
22,677

Demand side management (b)
2017
 
6,079

 
19,115

 
31,335

 

Sundance maintenance
2030
 

 
13,678

 

 
12,069

Deferred fuel and purchased power (b) (c)
2016
 
9,688

 

 

 

Deferred gains on utility property
2019
 
2,062

 
6,001

 
2,062

 
8,001

Four Corners coal reclamation
2031
 

 
8,920

 

 
1,200

Other
Various
 
2,550

 
7,565

 
934

 
9,535

Total regulatory liabilities
 
 
$
145,766

 
$
994,152

 
$
130,549

 
$
1,051,196


(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 (see Note 11).
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
See Note 7.
Income Taxes
Income Taxes
Income Taxes
 
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates.
 
In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.
 
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18).  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income.
 
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Total unrecognized tax benefits, January 1
$
44,775

 
$
41,997

 
$
133,422

 
$
44,775

 
$
41,997

 
$
133,241

Additions for tax positions of the current year
2,175

 
4,309

 
3,516

 
2,175

 
4,309

 
3,516

Additions for tax positions of prior years

 
751

 
13,158

 

 
751

 
13,158

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(10,244
)
 
(2,282
)
 
(108,099
)
 
(10,244
)
 
(2,282
)
 
(107,918
)
Settlements with taxing authorities

 

 

 

 

 

Lapses of applicable statute of limitations
(2,259
)
 

 

 
(2,259
)
 

 

Total unrecognized tax benefits, December 31
$
34,447

 
$
44,775

 
$
41,997

 
$
34,447

 
$
44,775

 
$
41,997



During the year ended December 31, 2013, Internal Revenue Service ("IRS") guidance was released which provided clarification regarding an APS tax accounting method change approved by the IRS in the third quarter of 2009. As a result of this guidance, uncertain tax positions decreased $67 million. Additionally, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, which further reduced uncertain tax positions by approximately $41 million. These reductions in uncertain tax positions, materially offset by an increase in deferred tax liabilities, resulted in a cash refund that was received in the first quarter of 2014.

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Tax positions, that if recognized, would decrease our effective tax rate
$
9,523

 
$
11,207

 
$
9,827

 
$
9,523

 
$
11,207

 
$
9,827


 
As of the balance sheet date, the tax year ended December 31, 2012 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2011.
 
We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.  The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Unrecognized tax benefit interest expense/(benefit) recognized
$
(161
)
 
$
752

 
$
(3,716
)
 
$
(161
)
 
$
752

 
$
(3,716
)

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Unrecognized tax benefit interest accrued
$
804

 
$
965

 
$
213

 
$
804

 
$
965

 
$
213



Additionally, as of December 31, 2015, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of income tax expense are as follows (dollars in thousands):
 
Pinnacle West Consolidated
 
APS Consolidated
 
Year Ended December 31,
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Current:
 

 
 

 
 

 
 
 
 
 
 
Federal
$
(12,335
)
 
$
25,054

 
$
(81,784
)
 
$
6,485

 
$
40,115

 
$
(97,531
)
State
4,763

 
10,382

 
10,537

 
7,813

 
15,598

 
11,983

Total current
(7,572
)
 
35,436

 
(71,247
)
 
14,298

 
55,713

 
(85,548
)
Deferred: