PINNACLE WEST CAPITAL CORP, 10-K filed on 2/20/2015
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2014
Feb. 13, 2015
Jun. 30, 2014
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, 2014 
 
 
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
 
 
$ 6,356,930,539 
Entity Common Stock, Shares Outstanding
 
110,575,187 
 
Document Fiscal Year Focus
2014 
 
 
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, 2014 
 
 
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
2014 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
OPERATING REVENUES
$ 3,491,632 
$ 3,454,628 
$ 3,301,804 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,179,829 
1,095,709 
994,790 
Operations and maintenance
908,025 
924,727 
884,769 
Depreciation and amortization
417,358 
415,708 
404,336 
Taxes other than income taxes
172,295 
164,167 
159,323 
Other expenses
2,883 
7,994 
6,831 
Total
2,680,390 
2,608,305 
2,450,049 
OPERATING INCOME
811,242 
846,323 
851,755 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
30,790 
25,581 
22,436 
Other income (Note S-3)
9,608 
1,704 
1,606 
Other expense (Note S-3)
(21,746)
(16,024)
(19,842)
Total
18,652 
11,261 
4,200 
INTEREST EXPENSE
 
 
 
Interest charges
200,950 
201,888 
214,616 
Allowance for borrowed funds used during construction (Note 1)
(15,457)
(14,861)
(14,971)
Total
185,493 
187,027 
199,645 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
644,401 
670,557 
656,310 
INCOME TAXES (Note 4)
220,705 
230,591 
237,317 
INCOME FROM CONTINUING OPERATIONS
423,696 
439,966 
418,993 
Net of income tax benefit of $(3,813) (Note 1)
(5,829)
NET INCOME
423,696 
439,966 
413,164 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,622 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
397,595 
406,074 
381,542 
Average common shares outstanding — basic (in shares)
110,626 
109,984 
109,510 
Average common shares outstanding — diluted (in shares)
111,178 
110,806 
110,527 
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Income from continuing operations attributable to common shareholders — basic (in dollars per share)
$ 3.59 
$ 3.69 
$ 3.54 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.59 
$ 3.69 
$ 3.48 
Income from continuing operations attributable to common shareholders — diluted (in dollars per share)
$ 3.58 
$ 3.66 
$ 3.50 
Net income attributable to common shareholders — diluted (in dollars per share)
$ 3.58 
$ 3.66 
$ 3.45 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
Income from continuing operations, net of tax
397,595 
406,074 
387,380 
Discontinued operations, net of tax
(5,838)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
ELECTRIC OPERATING REVENUES
3,488,946 
3,451,251 
3,293,489 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,179,829 
1,095,709 
994,790 
Operations and maintenance
882,442 
897,824 
873,916 
Depreciation and amortization
417,264 
415,612 
404,242 
Taxes other than income taxes
171,583 
163,377 
158,412 
Income taxes (Notes 4 and S-1)
245,036 
256,864 
256,600 
Total
2,896,154 
2,829,386 
2,687,960 
OPERATING INCOME
592,792 
621,865 
605,529 
OTHER INCOME (DEDUCTIONS)
 
 
 
Income taxes (Notes 4 and S-1)
7,676 
11,769 
12,204 
Allowance for equity funds used during construction (Note 1)
30,790 
25,581 
22,436 
Other income (Note S-3)
11,295 
3,896 
2,868 
Other expense (Note S-3)
(13,403)
(20,449)
(21,150)
Total
36,358 
20,797 
16,358 
INTEREST EXPENSE
 
 
 
Interest on long-term debt
186,323 
188,011 
198,398 
Interest on short-term borrowings
6,796 
6,605 
7,135 
Debt discount, premium and expense
4,168 
4,046 
4,215 
Allowance for borrowed funds used during construction (Note 1)
(15,457)
(14,861)
(14,971)
Total
181,830 
183,801 
194,777 
INCOME TAXES (Note 4)
237,360 
245,095 
244,396 
NET INCOME
447,320 
458,861 
427,110 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,613 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 421,219 
$ 424,969 
$ 395,497 
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Income Statement [Abstract]
 
 
 
Income tax expense (benefit) on discontinued operations
$ 0 
$ 0 
$ (3,813)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Net income
$ 423,696 
$ 439,966 
$ 413,164 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(810)
(213)
(22,763)
Reclassification of net realized loss, net of tax benefit
13,483 
26,747 
59,887 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(2,761)
9,421 
1,031 
Total other comprehensive income
9,912 
35,955 
38,155 
COMPREHENSIVE INCOME
433,608 
475,921 
451,319 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,622 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
407,507 
442,029 
419,697 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net income
447,320 
458,861 
427,110 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit (expense)
(809)
(214)
(22,775)
Reclassification of net realized loss, net of tax benefit
13,483 
26,747 
59,888 
Pension and other postretirement benefits activity, net of tax benefit (expense)
(7,635)
9,190 
(617)
Total other comprehensive income
5,039 
35,723 
36,496 
COMPREHENSIVE INCOME
452,359 
494,584 
463,606 
Less: Net income attributable to noncontrolling interests (Note 18)
26,101 
33,892 
31,613 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 426,258 
$ 460,692 
$ 431,993 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Net unrealized loss, tax benefit
$ (438)
$ 140 
$ 14,900 
Reclassification of net realized loss, tax benefit
7,932 
17,472 
39,120 
Pension and other postretirement benefits activity, tax (expense) benefit
1,307 
(6,156)
(651)
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
Net unrealized loss, tax benefit
(438)
140 
14,888 
Reclassification of net realized loss, tax benefit
7,932 
17,472 
39,119 
Pension and other postretirement benefits activity, tax (expense) benefit
$ 4,655 
$ (6,003)
$ 408 
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 7,604 
$ 9,526 
Customer and other receivables
297,740 
299,904 
Accrued unbilled revenues
100,533 
96,796 
Allowance for doubtful accounts
(3,094)
(3,203)
Materials and supplies (at average cost)
218,889 
221,682 
Fossil fuel (at average cost)
37,097 
38,028 
Income tax receivable (Note 4)
3,098 
135,517 
Assets from risk management activities (Note 16)
13,785 
17,169 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
20,755 
Other regulatory assets (Note 3)
129,808 
76,388 
Deferred income taxes (Notes 4 and S-1)
122,232 
91,152 
Other current assets
38,817 
39,895 
Total current assets
973,435 
1,043,609 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
17,620 
23,815 
Nuclear decommissioning trust (Notes 13 and 19)
713,866 
642,007 
Other assets
54,047 
60,875 
Total investments and other assets
785,533 
726,697 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
15,543,063 
15,200,464 
Accumulated depreciation and amortization
(5,397,751)
(5,300,219)
Net
10,145,312 
9,900,245 
Construction work in progress
682,807 
581,369 
Palo Verde sale leaseback, net of accumulated depreciation of $229,795 and $225,925 (Note 18)
121,255 
125,125 
Intangible assets, net of accumulated amortization of $489,538 and $439,703
119,755 
157,689 
Nuclear fuel, net of accumulated amortization of $143,554 and $146,057
125,201 
124,557 
Total property, plant and equipment
11,194,330 
10,888,985 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,054,087 
711,712 
Assets for other postretirement benefits (Note 7)
152,290 
Other
153,857 
137,683 
Total deferred debits
1,360,234 
849,395 
Total Assets
14,313,532 
13,508,686 
CURRENT LIABILITIES
 
 
Accounts payable
295,211 
284,516 
Accrued taxes (Note 4)
140,613 
130,998 
Accrued interest
52,603 
48,351 
Common dividends payable
65,790 
62,528 
Short-term borrowings (Note 5)
147,400 
153,125 
Current maturities of long-term debt (Note 6)
383,570 
540,424 
Customer deposits
72,307 
76,101 
Liabilities from risk management activities (Note 16)
59,676 
31,892 
Liability for asset retirements (Note 11)
32,462 
32,896 
Regulatory liabilities (Note 3)
130,549 
99,273 
Other current liabilities
178,962 
158,540 
Total current liabilities
1,559,143 
1,618,644 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
3,031,215 
2,796,465 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,582,636 
2,351,882 
Regulatory liabilities (Notes 1, 3, 4 and 7)
1,051,196 
801,297 
Liability for asset retirements (Note 11)
358,288 
313,833 
Liabilities for pension and other postretirement benefits (Note 7)
453,736 
513,628 
Liabilities from risk management activities (Note 16)
50,602 
70,315 
Customer advances
123,052 
114,480 
Coal mine reclamation
198,292 
207,453 
Deferred investment tax credit
178,607 
152,361 
Unrecognized tax benefits (Note 4)
19,377 
42,209 
Other
188,286 
185,659 
Total deferred credits and other
5,204,072 
4,753,117 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY
 
 
Common stock, no par value; authorized 150,000,000 shares, issued 110,649,762 at end of 2014 and 110,280,703 at end of 2013
2,512,970 
2,491,558 
Treasury stock at cost; 78,400 shares at end of 2014 and 98,944 shares at end of 2013
(3,401)
(4,308)
Total common stock
2,509,569 
2,487,250 
Retained earnings
1,926,065 
1,785,273 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(57,756)
(54,995)
Derivative instruments (Note 16)
(10,385)
(23,058)
Total accumulated other comprehensive loss
(68,141)
(78,053)
Total shareholders’ equity
4,367,493 
4,194,470 
Noncontrolling interests (Note 18)
151,609 
145,990 
Total equity
4,519,102 
4,340,460 
Total Liabilities and Equity
14,313,532 
13,508,686 
ARIZONA PUBLIC SERVICE COMPANY
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
4,515 
3,725 
Customer and other receivables
297,712 
299,055 
Accrued unbilled revenues
100,533 
96,796 
Allowance for doubtful accounts
(3,094)
(3,203)
Materials and supplies (at average cost)
218,889 
221,682 
Fossil fuel (at average cost)
37,097 
38,028 
Income tax receivable (Note 4)
135,179 
Assets from risk management activities (Note 16)
13,785 
17,169 
Deferred fuel and purchased power regulatory asset (Note 3)
6,926 
20,755 
Other regulatory assets (Note 3)
129,808 
76,388 
Deferred income taxes (Notes 4 and S-1)
55,253 
Other current assets
38,693 
39,153 
Total current assets
900,117 
944,727 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 16)
17,620 
23,815 
Nuclear decommissioning trust (Notes 13 and 19)
713,866 
642,007 
Other assets
33,362 
33,709 
Total investments and other assets
764,848 
699,531 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Plant in service and held for future use
15,539,811 
15,196,598 
Accumulated depreciation and amortization
(5,394,650)
(5,296,501)
Net
10,145,161 
9,900,097 
Construction work in progress
682,807 
581,369 
Palo Verde sale leaseback, net of accumulated depreciation of $229,795 and $225,925 (Note 18)
121,255 
125,125 
Intangible assets, net of accumulated amortization of $489,538 and $439,703
119,600 
157,534 
Nuclear fuel, net of accumulated amortization of $143,554 and $146,057
125,201 
124,557 
Total property, plant and equipment
11,194,024 
10,888,682 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,054,087 
711,712 
Assets for other postretirement benefits (Note 7)
149,260 
Unamortized debt issue costs
24,642 
21,860 
Other
128,026 
114,865 
Total deferred debits
1,356,015 
848,437 
Total Assets
14,215,004 
13,381,377 
CURRENT LIABILITIES
 
 
Accounts payable
289,930 
281,237 
Accrued taxes (Note 4)
131,110 
122,460 
Accrued interest
52,358 
48,132 
Common dividends payable
65,800 
62,500 
Short-term borrowings (Note 5)
147,400 
153,125 
Current maturities of long-term debt (Note 6)
383,570 
540,424 
Customer deposits
72,307 
76,101 
Deferred income taxes
2,033 
Liabilities from risk management activities (Note 16)
59,676 
31,892 
Liability for asset retirements (Note 11)
32,462 
32,896 
Regulatory liabilities (Note 3)
130,549 
99,273 
Other current liabilities
167,302 
130,774 
Total current liabilities
1,532,464 
1,580,847 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes
2,571,365 
2,347,724 
Regulatory liabilities (Notes 1, 3, 4 and 7)
1,051,196 
801,297 
Liability for asset retirements (Note 11)
358,288 
313,833 
Liabilities for pension and other postretirement benefits (Note 7)
424,508 
476,017 
Liabilities from risk management activities (Note 16)
50,602 
70,315 
Customer advances
123,052 
114,480 
Coal mine reclamation
198,292 
207,453 
Deferred investment tax credit
178,607 
152,361 
Unrecognized tax benefits (Note 4)
45,740 
42,209 
Other
144,823 
148,502 
Total deferred credits and other
5,146,473 
4,674,191 
EQUITY
 
 
Total common stock
178,162 
178,162 
Additional paid-in capital
2,379,696 
2,379,696 
Retained earnings
1,968,718 
1,804,398 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 7)
(37,948)
(30,313)
Derivative instruments (Note 16)
(10,385)
(23,059)
Total accumulated other comprehensive loss
(48,333)
(53,372)
Total shareholders’ equity
4,478,243 
4,308,884 
Noncontrolling interests (Note 18)
151,609 
145,990 
Total equity
4,629,852 
4,454,874 
Long-term debt less current maturities (Note 6)
2,906,215 
2,671,465 
Total capitalization
7,536,067 
7,126,339 
Total Liabilities and Equity
$ 14,215,004 
$ 13,381,377 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 229,795 
$ 225,925 
Accumulated amortization on intangible assets
489,538 
439,703 
Accumulated amortization on nuclear fuel
143,554 
146,057 
EQUITY
 
 
Common stock, par value
   
   
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
110,649,762 
110,280,703 
Treasury stock at cost, shares
78,400 
98,944 
ARIZONA PUBLIC SERVICE COMPANY
 
 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
 
 
Accumulated depreciation of Palo Verde sale leaseback
229,795 
225,925 
Accumulated amortization on intangible assets
483,538 
439,703 
Accumulated amortization on nuclear fuel
$ 143,554 
$ 146,057 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net Income
$ 423,696,000 
$ 439,966,000 
$ 413,164,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
496,487,000 
492,322,000 
481,262,000 
Deferred fuel and purchased power
(26,927,000)
21,678,000 
71,573,000 
Deferred fuel and purchased power amortization
40,757,000 
31,190,000 
(116,716,000)
Allowance for equity funds used during construction
(30,790,000)
(25,581,000)
(22,436,000)
Deferred income taxes
159,023,000 
249,296,000 
187,023,000 
Deferred investment tax credit
26,246,000 
52,542,000 
41,579,000 
Change in derivative instruments fair value
339,000 
534,000 
(749,000)
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(52,672,000)
(44,991,000)
14,587,000 
Accrued unbilled revenues
(3,737,000)
(1,951,000)
30,394,000 
Materials, supplies and fossil fuel
3,724,000 
(11,878,000)
(23,043,000)
Income tax receivable
132,419,000 
(133,094,000)
(4,043,000)
Other current assets
4,384,000 
(17,913,000)
(27,352,000)
Accounts payable
(353,000)
45,414,000 
(96,600,000)
Accrued taxes
9,615,000 
6,059,000 
12,736,000 
Other current liabilities
17,892,000 
(7,513,000)
23,869,000 
Change in margin and collateral accounts — assets
(343,000)
993,000 
2,216,000 
Change in margin and collateral accounts — liabilities
(24,975,000)
12,355,000 
137,785,000 
Change in unrecognized tax benefits
2,778,000 
(91,425,000)
(2,583,000)
Change in long-term regulatory liabilities
59,618,000 
64,473,000 
13,539,000 
Change in long-term income tax receivable
137,270,000 
(1,756,000)
Change in other long-term assets
(59,344,000)
(41,757,000)
6,872,000 
Change in other long-term liabilities
(78,210,000)
(24,682,000)
29,801,000 
Net cash flow provided by operating activities
1,099,627,000 
1,153,307,000 
1,171,122,000 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(910,634,000)
(1,016,322,000)
(889,551,000)
Contributions in aid of construction
20,325,000 
41,090,000 
49,876,000 
Allowance for borrowed funds used during construction
(15,457,000)
(14,861,000)
(14,971,000)
Proceeds from nuclear decommissioning trust sales
356,195,000 
446,025,000 
417,603,000 
Investment in nuclear decommissioning trust
(373,444,000)
(463,274,000)
(434,852,000)
Other
347,000 
(2,059,000)
(1,099,000)
Net cash flow used for investing activities
(922,668,000)
(1,009,401,000)
(872,994,000)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
731,126,000 
136,307,000 
476,081,000 
Repayment of long-term debt
(652,578,000)
(122,828,000)
(654,286,000)
Short-term borrowings and payments — net
(5,725,000)
60,950,000 
92,175,000 
Dividends paid on common stock
(246,671,000)
(235,244,000)
(225,075,000)
Common stock equity issuance
15,288,000 
17,319,000 
15,955,000 
Distributions to noncontrolling interests
(20,482,000)
(17,385,000)
(10,529,000)
Other
161,000 
299,000 
170,000 
Net cash flow used for financing activities
(178,881,000)
(160,582,000)
(305,509,000)
NET DECREASE IN CASH AND CASH EQUIVALENTS
(1,922,000)
(16,676,000)
(7,381,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
9,526,000 
26,202,000 
33,583,000 
CASH AND CASH EQUIVALENTS AT END OF YEAR
7,604,000 
9,526,000 
26,202,000 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
(102,154,000)
18,537,000 
2,543,000 
Interest, net of amounts capitalized
177,074,000 
184,010,000 
200,923,000 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
44,712,000 
33,184,000 
26,208,000 
Dividends declared but not paid
65,790,000 
62,528,000 
59,789,000 
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)
145,609,000 
ARIZONA PUBLIC SERVICE COMPANY
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net Income
447,320,000 
458,861,000 
427,110,000 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization including nuclear fuel
496,393,000 
492,226,000 
481,168,000 
Deferred fuel and purchased power
(26,927,000)
21,678,000 
71,573,000 
Deferred fuel and purchased power amortization
40,757,000 
31,190,000 
(116,716,000)
Allowance for equity funds used during construction
(30,790,000)
(25,581,000)
(22,436,000)
Deferred income taxes
155,401,000 
278,101,000 
202,159,000 
Deferred investment tax credit
26,246,000 
52,542,000 
41,579,000 
Change in derivative instruments fair value
339,000 
534,000 
(749,000)
Change in derivative instruments fair value
 
 
 
Customer and other receivables
(52,466,000)
(46,552,000)
12,914,000 
Accrued unbilled revenues
(3,737,000)
(1,951,000)
30,394,000 
Materials, supplies and fossil fuel
3,724,000 
(11,878,000)
(23,043,000)
Income tax receivable
135,179,000 
(134,590,000)
(2,280,000)
Other current assets
3,766,000 
(17,112,000)
(27,745,000)
Accounts payable
(2,355,000)
47,870,000 
(97,395,000)
Accrued taxes
8,650,000 
5,760,000 
7,330,000 
Other current liabilities
33,970,000 
(9,005,000)
6,070,000 
Change in margin and collateral accounts — assets
(343,000)
993,000 
2,216,000 
Change in margin and collateral accounts — liabilities
(24,975,000)
12,355,000 
137,785,000 
Change in unrecognized tax benefits
2,778,000 
(91,244,000)
(2,583,000)
Change in long-term regulatory liabilities
59,618,000 
64,473,000 
13,539,000 
Change in long-term income tax receivable
137,665,000 
(1,756,000)
Change in other long-term assets
(65,521,000)
(46,043,000)
1,391,000 
Change in other long-term liabilities
(82,860,000)
(25,601,000)
34,854,000 
Net cash flow provided by operating activities
1,124,167,000 
1,194,691,000 
1,175,379,000 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(910,084,000)
(1,016,322,000)
(889,551,000)
Contributions in aid of construction
20,325,000 
41,090,000 
49,876,000 
Allowance for borrowed funds used during construction
(15,457,000)
(14,861,000)
(14,971,000)
Proceeds from nuclear decommissioning trust sales
356,195,000 
446,025,000 
417,603,000 
Investment in nuclear decommissioning trust
(373,444,000)
(463,274,000)
(434,852,000)
Other
347,000 
(2,067,000)
(1,099,000)
Net cash flow used for investing activities
(922,118,000)
(1,009,409,000)
(872,994,000)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
606,126,000 
136,307,000 
351,081,000 
Repayment of long-term debt
(527,578,000)
(122,828,000)
(529,286,000)
Short-term borrowings and payments — net
(5,725,000)
60,950,000 
92,175,000 
Dividends paid on common stock
(253,600,000)
(242,100,000)
(222,200,000)
Distributions to noncontrolling interests
(20,482,000)
(17,385,000)
(10,529,000)
Net cash flow used for financing activities
(201,259,000)
(185,056,000)
(318,759,000)
NET DECREASE IN CASH AND CASH EQUIVALENTS
790,000 
226,000 
(16,374,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
3,725,000 
3,499,000 
19,873,000 
CASH AND CASH EQUIVALENTS AT END OF YEAR
4,515,000 
3,725,000 
3,499,000 
Supplemental disclosure of cash flow information:
 
 
 
Income taxes, net of refunds
(86,054,000)
7,524,000 
1,196,000 
Interest, net of amounts capitalized
173,436,000 
180,757,000 
196,038,000 
Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
44,712,000 
33,184,000 
26,208,000 
Dividends declared but not paid
65,800,000 
62,500,000 
59,800,000 
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)
$ 0 
$ 145,609,000 
$ 0 
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
Balance at Dec. 31, 2011
$ 3,930,586 
$ 2,444,247 
$ (4,717)
$ 1,534,483 
$ (152,163)
$ 108,736 
$ 4,051,406 
$ 178,162 
$ 2,379,696 
$ 1,510,740 
$ (125,591)
$ 108,399 
Balance (in shares) at Dec. 31, 2011
 
109,356,974 
111,161 
 
 
 
 
71,264,947 
 
 
 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
Net income
413,164 
 
 
381,542 
 
31,622 
427,110 
 
 
395,497 
 
31,613 
Other comprehensive income
38,155 
 
 
 
38,155 
 
36,496 
 
 
 
36,496 
 
Dividends, common stock
(291,923)
 
 
(291,923)
 
 
(282,000)
 
 
(282,000)
 
 
Issuance of common stock
22,676 
22,676 
 
 
 
 
 
 
 
 
 
 
Issuance of common stock (in shares)
 
480,983 
 
 
 
 
 
 
 
 
 
 
Purchase of treasury stock1
(4,607)
 
(4,607)
 
 
 
 
 
 
 
 
 
Purchase of treasury stock (in shares)1
 
 
(89,629)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
5,113 
 
5,113 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
105,598 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(10,875)
 
 
 
 
(10,875)
(10,529)
 
 
 
 
(10,529)
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 
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, 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)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
9,630 
 
9,630 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
170,538 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(17,385)
 
 
 
 
(17,385)
(17,385)
 
 
 
 
(17,385)
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 
Balance (in shares) at Dec. 31, 2013
110,280,703 
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, 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)
 
 
 
 
 
 
 
 
 
Stock-based compensation and other
8,800 
 
8,800 
 
 
 
 
 
 
 
 
 
Stock-based compensation and other (in shares)
 
 
160,290 
 
 
 
 
 
 
 
 
 
Net capital activities by noncontrolling interests
(20,482)
 
 
 
 
(20,482)
(20,482)
 
 
 
 
(20,482)
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 
Balance (in shares) at Dec. 31, 2014
110,649,762 
110,649,762 
78,400 
 
 
 
 
71,264,947 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.33 
$ 2.23 
$ 2.67 
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, BCE, and formerly SunCor. 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 new subsidiary 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. SunCor was a developer of residential, commercial and industrial real estate projects and essentially all of these assets were sold in 2009 and 2010.  In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  All activities for SunCor are reported as discontinued operations. 
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE, and formerly SunCor. 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.
 
For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 3).  Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.
 
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.

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, 2014 were as follows:
 
Fossil plant — 19 years;
Nuclear plant — 28 years;
Other generation — 25 years;
Transmission — 38 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 will be amortized on the depreciation line of the Consolidated Statements of Income.
 
For the years 2012 through 2014, the depreciation rates ranged from a low of 0.30% to a high of 12.08%.  The weighted-average rate was 2.77% for 2014, 3.00% for 2013, and 2.71% for 2012.
 
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 8.47% for 2014, 8.56% for 2013, and 8.60% for 2012.  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 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 August 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,
 
2014
 
2013
 
2012
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
(102,154
)
 
$
18,537

 
$
2,543

Interest, net of amounts capitalized
177,074

 
184,010

 
200,923

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
44,712

 
$
33,184

 
$
26,208

Dividends declared but not paid
65,790

 
62,528

 
59,789

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 $53 million in 2014, $53 million in 2013, and $50 million in 2012.  Estimated amortization expense on existing intangible assets over the next five years is $42 million in 2015, $32 million in 2016, $21 million in 2017, $9 million in 2018, and $3 million in 2019.  At December 31, 2014, the weighted-average remaining amortization period for intangible assets was 6 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, 2014, 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
 
During 2014, we adopted, on a prospective basis, new guidance relating to the presentation of unrecognized tax benefits.  This guidance generally requires entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  Prior to adopting this guidance, we presented unrecognized tax benefits on a gross basis.  The adoption of this new guidance changed our balance sheet presentation of unrecognized tax benefits, but did not impact our operating results or cash flows.  See Note 4 for details regarding the impacts of adopting this guidance.
 
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, including industry-specific guidance.  The new guidance is effective for us on January 1, 2017, and may be adopted using 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.
Regulatory Matters
Regulatory Matters
Regulatory Matters
 
Retail Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into 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.
 
APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016.  The 2012 Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest.  Nor is APS precluded from seeking rate relief, or any other party to the 2012 Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the 2012 Settlement Agreement.
 
Other key provisions of the 2012 Settlement Agreement include the following:
An authorized return on common equity of 10.0%;
A capital structure comprised of 46.1% debt and 53.9% common equity;
A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;
Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows: 
Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and
Deferral of 100% in all years if Arizona property tax rates decrease;
A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of 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 discussed below;
Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;
Modification of the TCA to streamline the process for future transmission-related rate changes; and
Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.
 
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
 
On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014.  The revised rules are expected to become effective in the second quarter of 2015.

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

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.
 
Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan for review by and approval of the ACC.
 
On June 1, 2012, APS filed its 2013 DSM Plan.  In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.
 
On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015.
 
On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards.  The draft proposed substantial changes to the rules and energy efficiency standards.    The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014.  A formal rule making has not been initiated and there has been no additional action on the draft to date.
 
PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The 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 for 2014 and 2013 (dollars in millions):
 
 
Year Ended December 31,
 
2014
 
2013
Beginning balance
$
21

 
$
73

Deferred fuel and purchased power costs - current period
27

 
(21
)
Amounts charged to customers
(41
)
 
(31
)
Ending balance
$
7

 
$
21


 
The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh.  Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”).  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC staff.  Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014.
 
Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.
 
APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million effective March 1, 2015.
 
Deregulation
 
On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and another is currently scheduled for February 26, 2015.

Net Metering
 
On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. 
 
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.  The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement.
 
In May 2014, the ACC began conducting a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.
 
On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015.  The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design. On August 12, 2014, the ACC Commissioners voted to lift the requirement that APS file its next general rate case by June 2015. On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.

Four Corners
 
On December 30, 2013, APS purchased 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 $77 million as of December 31, 2014 and is being amortized in rates over 10 years. 

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.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  Both requests for rehearing were denied on August 14, 2014. Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control. As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration. If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Cholla

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Cholla Unit 2 by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case.
If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($128 million as of December 31, 2014), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted. 
Regulatory Assets and Liabilities
 
The detail of regulatory assets is as follows (dollars in millions):
 
Remaining
Amortization
 
December 31, 2014
 
December 31, 2013
 
Period
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension and other postretirement benefits
(a)
 
$

 
$
485

 
$

 
$
314

Income taxes — AFUDC equity
2044
 
5

 
118

 
4

 
105

Deferred fuel and purchased power — mark-to-market (Note 16)
2017
 
51

 
46

 
5

 
29

Transmission vegetation management
2016
 
9

 
5

 
9

 
14

Coal reclamation
2026
 

 
7

 
8

 
18

Palo Verde VIEs (Note 18)
2046
 

 
35

 

 
41

Deferred compensation
2036
 

 
34

 

 
34

Deferred fuel and purchased power (b) (c)
2015
 
7

 

 
21

 

Tax expense of Medicare subsidy
2024
 
2

 
14

 
2

 
15

Loss on reacquired debt
2034
 
1

 
16

 
1

 
17

Income taxes — investment tax credit basis adjustment
2044
 
2

 
46

 
1

 
39

Pension and other postretirement benefits deferral
2015
 
4

 

 
8

 
4

Four Corners cost deferral
2024
 
7

 
70

 

 
37

Lost fixed cost recovery
2015
 
38

 

 
25

 

Transmission cost adjustor
2014
 

 

 
8

 
2

Retired power plant costs
2033
 
10

 
136

 
3

 
18

Deferred property taxes
(d)
 

 
30

 

 
11

Other
Various
 
2

 
12

 
2

 
14

Total regulatory assets (e)
 
 
$
138

 
$
1,054

 
$
97

 
$
712


(a)
This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to 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 millions):
 
Remaining
Amortization
 
December 31, 2014
 
December 31, 2013
 
Period
 
Current
 
Non-Current
 
Current
 
Non-Current
Removal costs
(a)
 
$
31

 
$
273

 
$
28

 
$
303

Asset retirement obligations
2044
 

 
296

 

 
266

Renewable energy standard (b)
2017
 
25

 
23

 
33

 
15

Income taxes — change in rates
2043
 

 
72

 

 
74

Spent nuclear fuel
2047
 
5

 
66

 
6

 
36

Deferred gains on utility property
2019
 
2

 
8

 
2

 
10

Income taxes — deferred investment tax credit
2043
 
4

 
93

 
3

 
79

Demand side management (b)
2015
 
31

 

 
27

 

Other postretirement benefits
(c)
 
32

 
199

 

 

Other
Various
 
1

 
21

 

 
18

Total regulatory liabilities
 
 
$
131

 
$
1,051

 
$
99

 
$
801


(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)
See Note 7.
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 and pension and other postretirement benefits.  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.
 
During the year ended December 31, 2013, 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 were materially offset by an increase in deferred tax liabilities.

Included in the current income tax receivable on the Consolidated Balance Sheets as of December 31, 2013 was $133 million that represented an anticipated IRS refund related to the finalized examinations of tax years ended December 31, 2008 and 2009. Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations has been accounted for in the Consolidated Balance Sheets as of December 31, 2013 and 2014.
 
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 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):
 
2014
 
2013
 
2012
Total unrecognized tax benefits, January 1
$
41,997

 
$
133,422

 
$
136,005

Additions for tax positions of the current year
4,309

 
3,516

 
5,167

Additions for tax positions of prior years
751

 
13,158

 

Reductions for tax positions of prior years for:
 

 
 

 
 

Changes in judgment
(2,282
)
 
(108,099
)
 
(7,729
)
Settlements with taxing authorities

 

 

Lapses of applicable statute of limitations

 

 
(21
)
Total unrecognized tax benefits, December 31
$
44,775

 
$
41,997

 
$
133,422


 
Included in the balances of unrecognized tax benefits at December 31, 2014, 2013 and 2012 were approximately $11 million, $10 million and $10 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
 
As of the balance sheet date, the tax year ended December 31, 2011 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 2008.
 
In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  As a result of this guidance, $26 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Consolidated Balance Sheets as of December 31, 2014.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense.  The amount of interest recognized in the Consolidated Statements of Income related to unrecognized tax benefits was a pre-tax expense of $1 million for 2014, a pre-tax benefit of $4 million for 2013, and a pre-tax expense of $4 million for 2012.
 
The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2014 and December 31, 2013 and $13 million as of December 31, 2012.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2014, 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):
 
Year Ended December 31,
 
2014
 
2013
 
2012
Current:
 

 
 

 
 

Federal
$
25,054

 
$
(81,784
)
 
$
(3,493
)
State
10,382

 
10,537

 
8,395

Total current
35,436

 
(71,247
)
 
4,902

Deferred:
 

 
 

 
 

Federal
167,365

 
279,973

 
200,322

State
17,904

 
21,865

 
28,280

Total deferred
185,269

 
301,838

 
228,602

Total income tax expense
220,705

 
230,591

 
233,504

Less: income tax benefit on discontinued operations

 

 
(3,813
)
Income tax expense — continuing operations
$
220,705

 
$
230,591

 
$
237,317


 
The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Federal income tax expense at 35% statutory rate
$
225,540

 
$
234,695

 
$
229,709

Increases (reductions) in tax expense resulting from:
 

 
 

 
 

State income tax net of federal income tax benefit
18,149

 
21,387

 
23,819

Credits and favorable adjustments related to prior years resolved in current year

 
(3,356
)
 

Medicare Subsidy Part-D
830

 
823

 
483

Allowance for equity funds used during construction (see Note 1)
(8,523
)
 
(6,997
)
 
(6,158
)
Palo Verde VIE noncontrolling interest (see Note 18)
(9,135
)
 
(11,862
)
 
(11,065
)
Investment tax credit amortization
(4,928
)
 
(3,548
)
 
(2,030
)
Other
(1,228
)
 
(551
)
 
2,559

Income tax expense — continuing operations
$
220,705

 
$
230,591

 
$
237,317


 
The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
 
December 31,
 
2014
 
2013
Current asset
$
122,232

 
$
91,152

Long-term liability
(2,582,636
)
 
(2,351,882
)
Deferred income taxes — net
$
(2,460,404
)
 
$
(2,260,730
)

 
On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2014, APS has recorded a regulatory liability of $74 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
 
On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2014, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
 
The components of the net deferred income tax liability were as follows (dollars in thousands):
 
 
December 31,
 
2014
 
2013
DEFERRED TAX ASSETS
 

 
 

Risk management activities
$
57,505

 
$
44,920

Regulatory liabilities:
 

 
 

Asset retirement obligation and removal costs
229,772

 
235,959

Unamortized investment tax credits
96,232

 
82,116

Other postretirement benefits
90,496

 

Other
60,409

 
42,609

Pension liabilities
205,227

 
140,773

Other postretirement liabilities

 
57,869

Renewable energy incentives
65,169

 
65,434

Credit and loss carryforwards
68,347

 
133,070

Other
138,729

 
148,492

Total deferred tax assets
1,011,886

 
951,242

DEFERRED TAX LIABILITIES
 

 
 

Plant-related
(2,958,369
)
 
(2,903,730
)
Risk management activities
(12,171
)
 
(16,191
)
Other postretirement assets
(59,170
)
 

Regulatory assets:
 

 
 

Allowance for equity funds used during construction
(48,286
)
 
(43,058
)
Deferred fuel and purchased power
(2,498
)
 
(8,282
)
Deferred fuel and purchased power — mark-to-market
(38,187
)
 
(13,343
)
Pension and other postretirement benefits
(191,747
)
 
(129,250
)
Retired power plant costs (see Note 3)
(57,255
)
 
(8,199
)
Other
(99,123
)
 
(85,003
)
Other
(5,484
)
 
(4,916
)
Total deferred tax liabilities
(3,472,290
)