PINNACLE WEST CAPITAL CORP, 10-K filed on 2/24/2012
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2011
Feb. 15, 2012
Jun. 30, 2011
Document and Entity Information
 
 
 
Entity Registrant Name
PINNACLE WEST CAPITAL CORP 
 
 
Entity Central Index Key
0000764622 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2011 
 
 
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
 
 
$ 4,848,522,427 
Entity Common Stock, Shares Outstanding
 
109,254,312 
 
Document Fiscal Year Focus
2011 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
OPERATING REVENUES
 
 
 
Regulated electricity
$ 3,237,194 
$ 3,180,678 
$ 3,149,187 
Other revenues
4,185 
8,521 
4,469 
Total
3,241,379 
3,189,199 
3,153,656 
OPERATING EXPENSES
 
 
 
Regulated electricity fuel and purchased power
1,009,464 
1,046,815 
1,178,620 
Operations and maintenance
904,286 
870,185 
822,300 
Depreciation and amortization
427,054 
414,479 
407,354 
Taxes other than income taxes
147,408 
135,328 
123,270 
Other expenses
6,659 
7,509 
5,984 
Total
2,494,871 
2,474,316 
2,537,528 
OPERATING INCOME
746,508 
714,883 
616,128 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
23,707 
22,066 
14,999 
Other income (Note 19)
3,111 
6,387 
5,159 
Other expense (Note 19)
(10,451)
(9,921)
(14,300)
Total
16,367 
18,532 
5,858 
INTEREST EXPENSE
 
 
 
Interest charges
241,995 
244,174 
237,766 
Allowance for borrowed funds used during construction (Note 1)
(18,358)
(16,479)
(10,379)
Total
223,637 
227,695 
227,387 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
539,238 
505,720 
394,599 
INCOME TAXES (Note 4)
183,604 
160,869 
138,551 
INCOME FROM CONTINUING OPERATIONS
355,634 
344,851 
256,048 
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
 
 
 
Net of income tax expense (benefit) of $7,418, $16,260 and $(109,641) (Note 21)
11,306 
25,358 
(183,284)
NET INCOME
366,940 
370,209 
72,764 
Less: Net income attributable to noncontrolling interests (Note 20)
27,467 
20,156 
4,434 
Net income attributable to common shareholders
339,473 
350,053 
68,330 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
109,053 
106,573 
101,161 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
109,864 
107,138 
101,264 
EARNINGS PER WEIGHTED - AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Income from continuing operations attributable to common shareholders - basic (in dollars per share)
$ 3.01 
$ 3.05 
$ 2.34 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.11 
$ 3.28 
$ 0.68 
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)
$ 2.99 
$ 3.03 
$ 2.34 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 3.09 
$ 3.27 
$ 0.67 
DIVIDENDS DECLARED PER SHARE (in dollars per share)
$ 2.10 
$ 2.10 
$ 2.10 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
Income from continuing operations, net of tax
328,110 
324,688 
236,839 
Discontinued operations, net of tax
11,363 
25,365 
(168,509)
Net income attributable to common shareholders
$ 339,473 
$ 350,053 
$ 68,330 
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
CONSOLIDATED STATEMENTS OF INCOME
 
 
 
Income tax expense (benefit) on discontinued operations
$ 7,418 
$ 16,260 
$ (109,641)
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 33,583 
$ 110,188 
Customer and other receivables
284,183 
324,207 
Accrued unbilled revenues
125,239 
103,292 
Allowance for doubtful accounts
(3,748)
(7,981)
Materials and supplies (at average cost)
204,387 
181,414 
Fossil fuel (at average cost)
22,000 
21,575 
Deferred income taxes (Note 4)
130,571 
124,897 
Income tax receivable (Note 4)
6,466 
2,483 
Assets from risk management activities (Note 18)
30,264 
73,788 
Deferred fuel and purchased power regulatory asset (Note 3)
27,549 
 
Other regulatory assets (Note 3)
69,072 
62,286 
Other current assets
26,904 
28,362 
Total current assets
956,470 
1,024,511 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 18)
49,322 
39,032 
Nuclear decommissioning trust (Notes 14 and 23)
513,733 
469,886 
Other assets
64,588 
116,216 
Total investments and other assets
627,643 
625,134 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
 
 
Plant in service and held for future use
13,753,971 
13,201,960 
Accumulated depreciation and amortization
(4,709,991)
(4,514,204)
Net
9,043,980 
8,687,756 
Construction work in progress
496,745 
459,361 
Palo Verde sale leaseback, net of accumulated depreciation of $218,186 and $213,094 (Note 20)
132,864 
137,956 
Intangible assets, net of accumulated amortization of $373,706 and $330,584
170,571 
184,952 
Nuclear fuel, net of accumulated amortization of $113,375 and $85,270
118,098 
108,794 
Total property, plant and equipment
9,962,258 
9,578,819 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
1,352,079 
986,370 
Income tax receivable (Note 4)
68,633 
65,103 
Other
143,935 
113,061 
Total deferred debits
1,564,647 
1,164,534 
TOTAL ASSETS
13,111,018 
12,392,998 
CURRENT LIABILITIES
 
 
Accounts payable
326,987 
236,354 
Accrued taxes
120,289 
104,711 
Accrued interest
54,872 
54,831 
Short-term borrowings (Note 5)
 
16,600 
Current maturities of long-term debt (Note 6)
477,435 
631,879 
Customer deposits
72,176 
68,322 
Liabilities from risk management activities (Note 18)
53,968 
58,976 
Deferred fuel and purchased power regulatory liability (Note 3)
 
58,442 
Other regulatory liabilities (Note 3)
88,362 
80,526 
Other current liabilities
148,616 
139,063 
Total current liabilities
1,342,705 
1,449,704 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
 
 
Long-term debt less current maturities
2,953,507 
2,948,991 
Palo Verde sale leaseback lessor notes less current maturities (Note 20)
65,547 
96,803 
Total long-term debt less current maturities
3,019,054 
3,045,794 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes (Note 4)
1,925,388 
1,863,861 
Regulatory liabilities (Notes 1 and 3)
737,332 
614,063 
Liability for asset retirements (Note 12)
279,643 
328,571 
Liabilities for pension and other postretirement benefits (Note 8)
1,268,910 
813,121 
Liabilities from risk management activities (Note 18)
82,495 
65,390 
Customer advances
116,805 
121,645 
Coal mine reclamation
117,896 
117,243 
Unrecognized tax benefits (Note 4)
72,270 
66,349 
Other
217,934 
132,031 
Total deferred credits and other
4,818,673 
4,122,274 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 7)
 
 
Common stock, no par value; authorized 150,000,000 shares, issued 109,356,974 at end of 2011 and 108,820,067 at end of 2010
2,444,247 
2,421,372 
Treasury stock at cost; 111,161 shares at end of 2011 and 50,410 at end of 2010
(4,717)
(2,239)
Total common stock
2,439,530 
2,419,133 
Retained earnings
1,534,483 
1,423,961 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 8)
(65,447)
(59,420)
Derivative instruments
(86,716)
(100,347)
Total accumulated other comprehensive loss
(152,163)
(159,767)
Total shareholders' equity
3,821,850 
3,683,327 
Noncontrolling interests (Note 20)
108,736 
91,899 
Total equity
3,930,586 
3,775,226 
TOTAL LIABILITIES AND EQUITY
$ 13,111,018 
$ 12,392,998 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 218,186 
$ 213,094 
Accumulated amortization on intangible assets
373,706 
330,584 
Accumulated amortization on nuclear fuel
$ 113,375 
$ 85,270 
EQUITY (Note 7)
 
 
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
109,356,974 
108,820,067 
Treasury stock at cost, shares
111,161 
50,410 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net Income
$ 366,940 
$ 370,209 
$ 72,764 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Gain on sale of energy-related products and services business
(10,404)
 
 
Gain on sale of district cooling business
 
(41,973)
 
Depreciation and amortization including nuclear fuel
493,784 
472,807 
450,864 
Deferred fuel and purchased power
69,166 
93,631 
(51,742)
Deferred fuel and purchased power amortization
(155,157)
(122,481)
147,018 
Allowance for equity funds used during construction
(23,707)
(22,066)
(14,999)
Real estate impairment charges
 
16,731 
280,188 
Gain on real estate debt restructuring
 
(16,755)
 
Deferred income taxes
176,192 
260,411 
105,492 
Change in mark-to-market valuations
4,064 
2,688 
(6,939)
Changes in current assets and liabilities:
 
 
 
Customer and other receivables
40,626 
(67,943)
12,292 
Accrued unbilled revenues
(21,947)
7,679 
(10,882)
Materials, supplies and fossil fuel
(23,398)
12,276 
(12,261)
Other current assets
(3,079)
9,375 
38,406 
Accounts payable
58,346 
9,125 
(27,328)
Accrued taxes and income tax receivable - net
12,068 
24,222 
(31,792)
Other current liabilities
20,358 
2,921 
57,280 
Change in margin and collateral accounts - assets
33,349 
(9,937)
(12,806)
Change in margin and collateral accounts - liabilities
29,731 
(88,315)
35,654 
Change in long term income tax receivable
(3,530)
 
(131,984)
Change in unrecognized tax benefits
8,410 
(73,621)
137,898 
Change in other regulatory liabilities
37,009 
56,801 
82,650 
Change in other long-term assets
(41,722)
(47,940)
(64,629)
Change in other long-term liabilities
58,484 
(97,388)
12,161 
Net cash flow provided by operating activities
1,125,583 
750,457 
1,067,305 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(884,350)
(748,374)
(764,609)
Contributions in aid of construction
38,096 
32,754 
53,525 
Allowance for borrowed funds used during construction
(18,358)
(16,778)
(10,745)
Proceeds from sale of district cooling business
 
100,300 
 
Proceeds from sale of energy-related products and services business
45,111 
 
 
Proceeds from nuclear decommissioning trust sales
497,780 
560,469 
441,242 
Investment in nuclear decommissioning trust
(513,799)
(584,885)
(463,033)
Proceeds from sale of commercial real estate investments
1,375 
72,038 
43,370 
Proceeds from sale of life insurance policies
55,444 
 
 
Other
(3,306)
8,576 
(4,667)
Net cash flow used for investing activities
(782,007)
(575,900)
(704,917)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
470,353 
 
867,469 
Repayment of long-term debt
(655,169)
(106,572)
(456,882)
Short-term borrowings and payments - net
(16,600)
(137,115)
(516,754)
Dividends paid on common stock
(221,728)
(216,979)
(205,076)
Common stock equity issuance
15,841 
255,971 
3,302 
Distributions to noncontrolling interests
(10,210)
(11,403)
(14,485)
Other
(2,668)
6,351 
171 
Net cash flow used for financing activities
(420,181)
(209,747)
(322,255)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(76,605)
(35,190)
40,133 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
110,188 
145,378 
105,245 
CASH AND CASH EQUIVALENTS AT END OF YEAR
33,583 
110,188 
145,378 
Cash paid during the period for:
 
 
 
Income taxes, net of (refunds)
10,324 
(23,447)
(52,776)
Interest, net of amounts capitalized
$ 217,789 
$ 221,728 
$ 216,608 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)
In Thousands, unless otherwise specified
Total
COMMON STOCK (Note 7)
TREASURY STOCK (Note 7)
RETAINED EARNINGS
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
NONCONTROLLING INTERESTS
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
Balance at Dec. 31, 2008
 
$ 2,151,323 
$ (2,854)
$ 1,444,208 
$ (146,698)
$ 124,990 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
Issuance of common stock
 
10,620 
 
 
 
 
 
Purchase of treasury stock
 
 
(2,156)
 
 
 
 
Reissuance of treasury stock used for stock compensation
 
 
1,198 
 
 
 
 
Net income attributable to common shareholders
68,330 
 
 
68,330 
 
 
68,330 
Common stock dividends
 
 
 
(212,386)
 
 
 
Pension and other postretirement benefits (Note 8):
 
 
 
 
 
 
 
Unrealized actuarial loss, net of tax benefit of $(6,067), $(7,738) and $(4,223)
 
 
 
 
(6,350)
 
 
Amortization to income:
 
 
 
 
 
 
 
Actuarial loss, net of tax benefit of $1,950, $1,870 and $1,705
 
 
 
 
2,615 
 
 
Prior service cost, net of tax benefit of $179, $201 and $215
 
 
 
 
329 
 
 
Transition obligation, net of tax benefit of $3, $59 and $39
 
 
 
 
61 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Net unrealized loss, net of tax benefit of $(37,389), $(61,348) and $(61,329)
 
 
 
 
(93,996)
 
 
Reclassification of net realized loss to income, net of tax benefit of $46,288, $48,453 and $72,877
 
 
 
 
112,452 
 
 
Net income attributable to noncontrolling interests
(4,434)
 
 
 
 
4,434 
 
Net capital activities by noncontrolling interests
 
 
 
 
 
(17,529)
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
Other comprehensive income (loss)
15,111 
 
 
 
 
 
15,111 
Comprehensive income attributable to common shareholders
83,441 
 
 
 
 
 
83,441 
Other
 
(8,648)
 
(1,939)
 
 
 
Balance at Dec. 31, 2009
3,428,004 
2,153,295 
(3,812)
1,298,213 
(131,587)
111,895 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
Issuance of common stock
 
263,297 
 
 
 
 
 
Purchase of treasury stock
 
 
(82)
 
 
 
 
Reissuance of treasury stock used for stock compensation
 
 
1,655 
 
 
 
 
Net income attributable to common shareholders
350,053 
 
 
350,053 
 
 
350,053 
Common stock dividends
 
 
 
(224,305)
 
 
 
Pension and other postretirement benefits (Note 8):
 
 
 
 
 
 
 
Unrealized actuarial loss, net of tax benefit of $(6,067), $(7,738) and $(4,223)
 
 
 
 
(11,795)
 
 
Amortization to income:
 
 
 
 
 
 
 
Actuarial loss, net of tax benefit of $1,950, $1,870 and $1,705
 
 
 
 
2,868 
 
 
Prior service cost, net of tax benefit of $179, $201 and $215
 
 
 
 
308 
 
 
Transition obligation, net of tax benefit of $3, $59 and $39
 
 
 
 
91 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Net unrealized loss, net of tax benefit of $(37,389), $(61,348) and $(61,329)
 
 
 
 
(93,939)
 
 
Reclassification of net realized loss to income, net of tax benefit of $46,288, $48,453 and $72,877
 
 
 
 
74,287 
 
 
Net income attributable to noncontrolling interests
(20,156)
 
 
 
 
20,156 
 
Net capital activities by noncontrolling interests
 
 
 
 
 
(40,152)
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
Other comprehensive income (loss)
(28,180)
 
 
 
 
 
(28,180)
Comprehensive income attributable to common shareholders
321,873 
 
 
 
 
 
321,873 
Other
 
4,780 
 
 
 
 
 
Balance at Dec. 31, 2010
3,775,226 
2,421,372 
(2,239)
1,423,961 
(159,767)
91,899 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
Issuance of common stock
 
11,057 
 
 
 
 
 
Purchase of treasury stock
 
 
(3,720)
 
 
 
 
Reissuance of treasury stock used for stock compensation
 
 
1,242 
 
 
 
 
Net income attributable to common shareholders
339,473 
 
 
339,473 
 
 
339,473 
Common stock dividends
 
 
 
(228,951)
 
 
 
Pension and other postretirement benefits (Note 8):
 
 
 
 
 
 
 
Unrealized actuarial loss, net of tax benefit of $(6,067), $(7,738) and $(4,223)
 
 
 
 
(9,296)
 
 
Amortization to income:
 
 
 
 
 
 
 
Actuarial loss, net of tax benefit of $1,950, $1,870 and $1,705
 
 
 
 
2,990 
 
 
Prior service cost, net of tax benefit of $179, $201 and $215
 
 
 
 
275 
 
 
Transition obligation, net of tax benefit of $3, $59 and $39
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Net unrealized loss, net of tax benefit of $(37,389), $(61,348) and $(61,329)
 
 
 
 
(57,271)
 
 
Reclassification of net realized loss to income, net of tax benefit of $46,288, $48,453 and $72,877
 
 
 
 
70,901 
 
 
Net income attributable to noncontrolling interests
(27,467)
 
 
 
 
27,467 
 
Net capital activities by noncontrolling interests
 
 
 
 
 
(10,630)
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
 
 
 
 
 
 
 
Other comprehensive income (loss)
7,605 
 
 
 
 
 
7,605 
Comprehensive income attributable to common shareholders
347,078 
 
 
 
 
 
347,078 
Other
 
11,818 
 
 
 
 
 
Balance at Dec. 31, 2011
$ 3,930,586 
$ 2,444,247 
$ (4,717)
$ 1,534,483 
$ (152,163)
$ 108,736 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Pension and other postretirement benefits (Note 8):
 
 
 
Unrealized actuarial loss, net of tax benefit
$ (6,067)
$ (7,738)
$ (4,223)
Amortization to income:
 
 
 
Actuarial loss, net of tax benefit
1,950 
1,870 
1,705 
Prior service cost, tax benefit
179 
201 
215 
Transition obligation, tax benefit
59 
39 
Derivative instruments:
 
 
 
Net unrealized gain (loss), net of tax
(37,389)
(61,348)
(61,329)
Reclassification of net realized (gain) loss to income, net of tax (expense) benefit
$ 46,288 
$ 48,453 
$ 72,877 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies

 

 

1.             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, SunCor, El Dorado, and formerly APSES.  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.  SunCor was a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah but in 2009 and 2010, essentially all of these assets were sold.  All activities for SunCor are now reported as discontinued operations (see Note 21). APSES provided energy-related projects to commercial and industrial retail customers in competitive markets in the western United States.  APSES was sold in 2011 and is now reported as discontinued operations (see Note 21). El Dorado is an investment firm.

 

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, and El Dorado. 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 20).

 

In preparing the consolidated financial statements, we have evaluated the events that have occurred after December 31, 2011 through the date the financial statements were issued.

 

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.  These consolidated financial statements and notes have been prepared consistently with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income, Consolidated Balance Sheets, and Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 21) and the impacts related to the reclassification of regulatory assets and liabilities for the current portion (see Note 3).

 

Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years.  Other line items are more condensed than the previous presentation.  The prior year amounts were reclassified to conform to the current year presentation.  These reclassifications had no impact on total net cash flow provided by operating activities.

 

The following tables show the impact of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

 

Statement of Income for the Year Ended
December, 2010

 

As
previously
reported

 

Reclassifications
for discontinued
operations

 

Amount reported
after reclassification
for discontinued
operations

 

Operating Revenues

 

 

 

 

 

 

 

Other revenues

 

$

82,967

 

$

(74,446

)

$

8,521

 

Operating Expenses

 

 

 

 

 

 

 

Operations and maintenance

 

877,406

 

(7,221

)

870,185

 

Depreciation and amortization

 

414,555

 

(76

)

414,479

 

Taxes other than income taxes

 

135,334

 

(6

)

135,328

 

Other expenses

 

65,651

 

(58,142

)

7,509

 

Other

 

 

 

 

 

 

 

Other income

 

6,368

 

19

 

6,387

 

Other expense

 

(9,764

)

(157

)

(9,921

)

Interest Expense

 

 

 

 

 

 

 

Allowance for borrowed funds used during construction

 

(16,539

)

60

 

(16,479

)

Income Taxes

 

164,321

 

(3,452

)

160,869

 

Income From Continuing Operations

 

350,598

 

(5,747

)

344,851

 

Income From Discontinued Operations

 

19,611

 

5,747

 

25,358

 

 

Statement of Income for the Year Ended
December, 2009

 

As
previously
reported

 

Reclassifications
for discontinued
operations

 

Amount reported
after reclassification
for discontinued
operations

 

Operating Revenues

 

 

 

 

 

 

 

Other revenues

 

$

26,723

 

$

(22,254

)

$

4,469

 

Operating Expenses

 

 

 

 

 

 

 

Operations and maintenance

 

831,863

 

(9,563

)

822,300

 

Depreciation and amortization

 

407,463

 

(109

)

407,354

 

Taxes other than income taxes

 

123,277

 

(7

)

123,270

 

Other expenses

 

24,534

 

(18,550

)

5,984

 

Other

 

 

 

 

 

 

 

Other income

 

5,278

 

(119

)

5,159

 

Other expense

 

(14,269

)

(31

)

(14,300

)

Interest Expense

 

 

 

 

 

 

 

Interest charges

 

237,527

 

239

 

237,766

 

Allowance for borrowed funds used during construction

 

(10,430

)

51

 

(10,379

)

Income Taxes

 

136,506

 

2,045

 

138,551

 

Income From Continuing Operations

 

252,558

 

3,490

 

256,048

 

Income From Discontinued Operations

 

(179,794

)

(3,490

)

(183,284

)

 

Balance Sheets - December 31, 2010

 

As
previously
reported

 

Reclassifications for
regulatory assets and
liabilities

 

Amount reported
after reclassification
for regulatory assets
and liabilities

 

Current Assets — Other regulatory assets

 

$

 

$

62,286

 

$

62,286

 

Current Assets — Deferred income taxes

 

94,602

 

30,295

 

124,897

 

Deferred Debits — Regulatory assets

 

1,048,656

 

(62,286

)

986,370

 

Current Liabilities — Deferred fuel and purchased power regulatory liability

 

 

58,442

 

58,442

 

Current Liabilities — Other regulatory liabilities

 

 

80,526

 

80,526

 

Deferred Credits and Other — Deferred income taxes

 

1,833,566

 

30,295

 

1,863,861

 

Deferred Credits and Other — Deferred fuel and purchased power regulatory liability

 

58,442

 

(58,442

)

 

Deferred Credits and Other — Regulatory liabilities

 

694,589

 

(80,526

)

614,063

 

 

Statement of Cash Flows for the
Year Ended December 31, 2010

 

As previously
reported

 

Reclassifications for
regulatory assets and
liabilities and to
conform to current year
presentation

 

Amounts reported
after reclassification
for regulatory assets
and liabilities and to
conform to current
year presentation

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

Other current assets

 

$

5,246

 

$

4,129

 

$

9,375

 

Other current liabilities

 

5,204

 

(2,283

)

2,921

 

Change in other regulatory liabilities

 

54,518

 

2,283

 

56,801

 

Change in other long-term assets

 

(43,189

)

(4,751

)

(47,940

)

Expenditures for real estate investments

 

(622

)

622

 

 

Other changes in real estate assets

 

4,068

 

(4,068

)

 

Change in other long-term liabilities

 

(101,456

)

4,068

 

(97,388

)

 

Statement of Cash Flows for the
Year Ended December 31, 2009

 

As previously
reported

 

Reclassifications for
regulatory assets and
liabilities and to
conform to current year
presentation

 

Amounts reported after
reclassification for
regulatory assets and
liabilities and to
conform to current year
presentation

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

Other current assets

 

$

 24,647

 

$

 13,759

 

$

 38,406

 

Other current liabilities

 

29,274

 

28,006

 

57,280

 

Change in other regulatory liabilities

 

110,642

 

(27,992

)

82,650

 

Change in other long-term assets

 

(47,899

)

(16,730

)

(64,629

)

Change in other long-term liabilities

 

16,377

 

(4,216

)

12,161

 

Expenditures for real estate investments

 

(2,957

)

2,957

 

 

Other changes in real estate assets

 

(4,216

)

4,216

 

 

 

Accounting Records and Use of Estimates

 

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

 

Regulatory Accounting

 

APS is regulated by the ACC and the 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 other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in the state 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 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.

 

Effective January 1, 2010, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 retail rate case settlement agreement (see Note 3).  This revenue treatment continues through 2012, or until new rates are established in APS’s next general retail rate case, if that is before year end 2012.  Certain proceeds received under previous versions of the line extension policy, or for activities not involving an extension or upgrade of service (e.g., service relocations at the request of governmental entities or undergrounding of overhead facilities) will continue to be treated as contributions in aid of construction and will not impact electric revenues.

 

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.

 

Utility Plant and Depreciation

 

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 12.

 

APS records a regulatory liability for the asset retirement obligations related to its regulated assets.  This regulatory liability represents 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 capitalized 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, 2011 were as follows:

 

·                                          Fossil plant — 18 years;

·                                          Nuclear plant — 29 years;

·                                          Other generation — 28 years;

·                                          Transmission — 38 years;

·                                          Distribution — 35 years; and

·                                          Other — 7 years.

 

APS applied for twenty-year extensions of its operating licenses for each of the three Palo Verde units in December 2008.  On April 21, 2011, the NRC approved the extensions of the Palo Verde licenses.  The nuclear plant remaining life takes into consideration an ACC decision which authorizes the new Palo Verde Nuclear plant lives, effective January 1, 2012.

 

For the years 2009 through 2011, the depreciation rates ranged from a low of 1.30% to a high of 10.20%.  The weighted-average rate was 2.98% for 2011, 2.98% for 2010, and 3.06% for 2009.

 

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 Statement 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 10.25% for 2011, 9.2% for 2010, and 5.9% for 2009.  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 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 unobservable inputs, such as models and other valuation methods, 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 14 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, emission allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments that may qualify as derivatives, including futures, forwards, options and swaps. As part of our overall risk management program, we use such 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 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 18 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 another postretirement benefit plan for the employees of Pinnacle West and our subsidiaries and provide 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 8 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 charges APS $0.001 per kWh of nuclear generation.  See Note 11 for information on spent nuclear fuel disposal and Note 23 for information on nuclear decommissioning 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 liability 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.

 

Real Estate Investments

 

We did not have any real estate investments at December 31, 2011 and December 31, 2010 on our Consolidated Balance Sheets.  For the purposes of evaluating impairment, in accordance with the provisions on accounting for the impairment or disposal of long-lived assets; we classified our real estate assets, such as land under development, land held for future development, and commercial property as “held and used” in 2010 and 2009.  When events or changes in circumstances indicated that the carrying values of real estate assets considered held and used would not be recoverable, we compared the undiscounted cash flows that we estimated would be generated by each asset to its carrying amount.  If the carrying amount exceeded the undiscounted cash flows, we adjusted the asset to fair value and recognized an impairment charge.  The adjusted value became the new book value (carrying amount) for held and used assets.  Our internal models used inputs that we believe were consistent with those that would be used by market participants.

 

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.

 

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 $47 million in 2011, $45 million in 2010, and $35 million in 2009. Estimated amortization expense on existing intangible assets over the next five years is $42 million in 2012, $35 million in 2013, $28 million in 2014, $21 million in 2015, and $13 million in 2016. At December 31, 2011, the weighted average remaining amortization period for intangible assets was 7 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).

 

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 14 and Note 23 for more information on these investments.

New Accounting Standards
New Accounting Standards

 

 

2.                                      New Accounting Standards

 

In May 2011, the FASB issued amended guidance to converge fair value measurement and disclosure requirements for GAAP and IFRS. The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures.  The guidance is effective for us on January 1, 2012.  The adoption of this new guidance will result in additional fair value disclosures, but will not impact our financial statement results.

 

In June 2011, the FASB issued amended guidance on the presentation of comprehensive income intended to increase the prominence of items reported in other comprehensive income and to facilitate convergence with IFRS.  The amended guidance requires entities to present total comprehensive income, which includes components of net income and components of other comprehensive income, in either a single continuous statement of comprehensive income or in two separate but consecutive statements.  The guidance is effective for us on January 1, 2012. The guidance will change our presentation of comprehensive income, but will not impact our financial statement results.

Regulatory Matters
Regulatory Matters

 

 

3.                                      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 increase the average retail customer bill approximately 6.6%.  The filing is based on a test year ended December 31, 2010, adjusted as described below.  On January 6, 2012, APS and other parties to APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have agreed to settle the rate case.  The Settlement Agreement requires the approval of the ACC.  Evidentiary hearings on the matter were completed on February 3, 2012.  Opening briefs from parties are due February 29, 2012 and responsive briefs are due March 14, 2012.  See below for details regarding the Settlement Agreement.

 

The key financial provisions of APS’s original request included:

 

·                                          an increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through APS’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through the PSA (which will decrease base rates);

 

·                                          a rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;

 

·                                          the following proposed capital structure and costs of capital:

 

 

 

Capital Structure

 

Cost of Capital

 

Long-term debt

 

46.1

%

6.38

%

Common stock equity

 

53.9

%

11.00

%

Weighted-average cost of capital

 

 

 

8.87

%

 

·                                          a Base Fuel Rate of $0.03242 per kWh based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

 

APS proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision.  In addition, APS proposed a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.

 

Settlement Agreement

 

The 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 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 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 Settlement Agreement.

 

Other key provisions of the 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 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 proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant;

 

·                                          Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

 

·                                          Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce approximately $5 million annually;

 

·                                          Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

 

·                                          Allowing a negative credit that currently exists in the PSA 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.

 

If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012.  As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.

 

2008 General Retail Rate Case Impacts

 

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008.  The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates.  The new rates were effective January 1, 2010.  The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

 

·                                          Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

 

·                                          An authorized return on common equity of 11%;

 

·                                          A capital structure comprised of 46.2% debt and 53.8% common equity;

 

·                                          A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);

 

·                                          Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

 

·                                          Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.

 

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 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016  timeframe and requesting 2012 RES funding of $129 million to $152 million.  On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million.  Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 MW under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015.  In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications.  Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

 

Demand-Side Management Adjustor Charge (“DSMAC”).  The 2008 retail rate case settlement agreement requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC.  In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand-side management programs over the current year.  Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis.  The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.

 

The ACC previously approved recovery of all 2009 program costs plus incentives.  The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2009 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery.  As requested by APS, 2009 program cost recovery is to be amortized over a three-year period.

 

On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million.  On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.

 

On June 1, 2011, APS filed its 2012 Energy Efficiency Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the settlement agreement related to APS’s 2008 retail rate case (1.5% of total energy resources). APS proposed a budget for 2012 of $90 million. When added to the third and final year of the amortization of 2009 program costs authorized in 2009 and less the $10 million already being recovered in general rates, the proposed 2012 DSMAC would recover approximately $85 million over a twelve month period beginning March 1, 2012.  APS expects a decision from the ACC prior to March 31, 2012.

 

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;

 

·                                          under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchased power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate (see “Settlement Agreement” above for information regarding the elimination of this arrangement);

 

·                                          an adjustment to the PSA rate is made annually each February 1st (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 2011 and 2010 (dollars in millions):

 

 

 

Year Ended
December 31,

 

 

 

2011

 

2010

 

Beginning balance

 

$

(58

)

$

(87

)

Deferred fuel and purchased power costs-current period

 

(69

)

(93

)

Amounts refunded through revenues

 

155

 

122

 

Ending balance

 

$

28

 

$

(58

)

 

The PSA rate for the PSA year beginning February 1, 2012 is ($0.0042) per kWh as compared to ($0.0057) per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

 

Transmission Rates and Transmission Cost AdjustorIn July 2008, the 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 must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  If the Settlement Agreement (discussed above) is approved, 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-collected amounts.

 

Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula.  Approximately $38 million of this revenue increase relates to Retail Transmission Charges.  The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

 

Regulatory Assets and Liabilities

 

As discussed in Note 1, as of March 31, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Consolidated Balance Sheets.  This presentation is reflected in the tables below.

 

The detail of regulatory assets is as follows (dollars in millions):

 

 

 

Remaining
Amortization

 

December 31, 2011

 

December 31, 2010

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

(a)

 

$

 

$

1,023

 

$

 

$

669

 

Income taxes —AFUDC equity

 

2041

 

3

 

81

 

3

 

69

 

Deferred fuel and purchased power — mark-to-market (Note 18)

 

2016

 

43

 

34

 

42

 

35

 

Transmission vegetation management

 

2016

 

9

 

32

 

 

46

 

Coal reclamation

 

2026

 

2

 

35

 

2

 

36

 

Palo Verde VIE (Note 20)

 

2015

 

 

35

 

 

33

 

Deferred compensation

 

2036

 

 

33

 

 

32

 

Deferred fuel and purchased power (b)

 

2012

 

28

 

 

 

 

Income taxes — Medicare subsidy

 

2024

 

2

 

18

 

2

 

21

 

Loss on reacquired debt

 

2034

 

1

 

19

 

1

 

21

 

Income taxes — investment tax credit basis adjustment

 

2044

 

 

15

 

 

 

Pension and other postretirement benefits deferral

 

2015

 

 

12

 

 

 

Demand side management

 

2013

 

7

 

1

 

12

 

6

 

Other

 

Various

 

2

 

14

 

 

18

 

Total regulatory assets (c)

 

 

 

$

97

 

$

1,352

 

$

62

 

$

986

 

 

(a)                                  This asset represents the future recovery in earnings of under-funded pension and other postretirement benefits obligation costs 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.

(b)                                 See “Cost Recovery Mechanisms” discussion above.

(c)                                  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 and Transmission Cost Adjustor.”

 

The detail of regulatory liabilities is as follows (dollars in millions):

 

 

 

Remaining
Amortization

 

December 31, 2011

 

December 31, 2010

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs

 

(a)

 

$

22

 

$

349

 

$

22

 

$

357

 

Asset retirement obligations

 

(a)

 

 

225

 

 

184

 

Renewable energy standard (b)

 

2012

 

54

 

 

50

 

 

Income taxes — change in rates

 

2041

 

 

59

 

 

 

Spent nuclear fuel

 

2047

 

5

 

44

 

4

 

41

 

Deferred gains on utility property

 

2019

 

2

 

14

 

2

 

16

 

Income taxes-unamortized investment tax credit

 

2044

 

1

 

30

 

 

1

 

Deferred fuel and purchased power (b)(c)

 

 

 

 

 

58

 

 

Other

 

Various

 

4

 

16

 

3

 

15

 

Total regulatory liabilities

 

 

 

$

88

 

$

737

 

$

139

 

$

614

 

 

(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 12.

(b)                                 See “Cost Recovery Mechanisms” discussion above.

(c)                                  Subject to a carrying charge.

Income Taxes
Income Taxes

 

 

4.                                      Income Taxes

 

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using the 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 investment tax credits 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.

 

The $69 million long-term income tax receivable on the Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  This amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.

 

During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007.  As a result of this settlement, net uncertain tax positions decreased $62 million, including approximately $3 million which decreased our effective tax rate.  Additionally, the settlement resulted in the recognition of net interest benefits of approximately $4 million through the effective tax rate.

 

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):

 

 

 

2011

 

2010

 

2009

 

Total unrecognized tax benefits, January 1

 

$

127,595

 

$

201,216

 

$

63,318

 

Additions for tax positions of the current year

 

10,915

 

7,551

 

44,094

 

Additions for tax positions of prior years

 

 

 

98,942

 

Reductions for tax positions of prior years for:

 

 

 

 

 

 

 

Changes in judgment

 

(1,555

)

(11,017

)

 

Settlements with taxing authorities

 

(124

)

(62,199

)

(4,089

)

Lapses of applicable statute of limitations

 

(826

)

(7,956

)

(1,049

)

Total unrecognized tax benefits, December 31

 

$

136,005

 

$

127,595

 

$

201,216

 

 

Included in the balances of unrecognized tax benefits at December 31, 2011, 2010 and 2009 were approximately $8 million, $7 million and $16 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, 2008 and all subsequent tax years remain subject to examination by the IRS.  With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years prior to 2006.  We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.

 

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 Statement of Income related to unrecognized tax benefits was a pre-tax expense of $3 million for 2011, a pre-tax benefit of $2 million for 2010 and a pre-tax expense of $2 million for 2009.

 

The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $9 million as of December 31, 2011, $6 million as of December 31, 2010 and $8 million as of December 31, 2009.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2011, we have recognized $4 million of interest income to be received on the overpayment 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,

 

 

 

2011

 

2010

 

2009

 

Current:

 

 

 

 

 

 

 

Federal

 

$

(310

)

$

(108,827

)

$

(38,502

)

State

 

15,140

 

25,545

 

(38,080

)

Total current

 

14,830

 

(83,282

)

(76,582

)

Deferred:

 

 

 

 

 

 

 

Federal

 

159,566

 

260,236

 

62,874

 

State

 

16,626

 

10,911

 

42,618

 

Discontinued operations

 

 

(10,736

)

 

Total deferred

 

176,192

 

260,411

 

105,492

 

Total income tax expense

 

191,022

 

177,129

 

28,910

 

Less: income tax expense (benefit) on discontinued operations

 

7,418

 

16,260

 

(109,641

)

Income tax expense — continuing operations

 

$

183,604

 

$

160,869

 

$

138,551

 

 

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,

 

 

 

2011

 

2010

 

2009

 

 

 

 

 

 

 

 

 

Federal income tax expense at 35% statutory rate

 

$

188,733

 

$

177,002

 

$

138,110

 

Increases (reductions) in tax expense resulting from:

 

 

 

 

 

 

 

State income tax net of federal income tax benefit

 

19,594

 

17,485

 

15,068

 

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

 

 

(17,300

)

 

Medicare Subsidy Part-D

 

823

 

1,311

 

(2,095

)

Allowance for equity funds used during construction (see Note 1)

 

(6,881

)

(6,563

)

(4,265

)

Palo Verde VIE noncontrolling interest (see Note 20)

 

(9,636

)

(7,057

)

(6,723

)

Other

 

(9,029

)

(4,009

)

(1,544

)

Income tax expense — continuing operations

 

$

183,604

 

$

160,869

 

$

138,551

 

 

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):

 

 

 

December 31,

 

 

 

2011

 

2010

 

Current asset

 

$

130,571

 

$

124,897

 

Long-term liability

 

(1,925,388

)

(1,863,861

)

Deferred income taxes — net

 

$

(1,794,817

)

$

(1,738,964

)

 

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. In 2011, APS increased regulatory liabilities by a total of $62 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,

 

 

 

2011

 

2010

 

DEFERRED TAX ASSETS

 

 

 

 

 

Risk management activities

 

$

117,765

 

$

124,731

 

Regulatory liabilities:

 

 

 

 

 

Asset retirement obligation and removal costs

 

236,739

 

222,448

 

Deferred fuel and purchased power

 

 

23,089

 

Renewable energy standard

 

19,722

 

18,749

 

Unamortized investment tax credits

 

31,460

 

642

 

Other

 

33,155

 

27,718

 

Pension and other postretirement liabilities

 

501,202

 

321,182

 

Real estate investments and assets held for sale

 

 

19,855

 

Renewable energy incentives

 

57,901

 

37,327

 

Credit and loss carryforwards

 

171,915

 

42,971

 

Other

 

73,759

 

68,684

 

Total deferred tax assets

 

1,243,618

 

907,396

 

DEFERRED TAX LIABILITIES

 

 

 

 

 

Plant-related

 

(2,446,908

)

(2,210,976

)

Risk management activities

 

(30,171

)

(30,125

)

Regulatory assets:

 

 

 

 

 

Allowance for equity funds used during construction

 

(33,347

)

(28,276

)

Deferred fuel and purchased power

 

(10,884

)

 

Deferred fuel and purchased power — mark-to-market

 

(30,559

)

(30,276

)

Pension and other postretirement benefits

 

(408,716

)

(264,313

)

Other

 

(73,087

)

(77,078

)

Other

 

(4,763

)

(5,316

)

Total deferred tax liabilities

 

(3,038,435

)

(2,646,360

)

Deferred income taxes — net

 

$

(1,794,817

)

$

(1,738,964

)

 

As of December 31, 2011, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($67 million) and federal net operating losses ($92 million), both of which first begin to expire in 2029, and other federal and state loss carryforwards ($13 million) which first begin to expire in 2014.

Lines of Credit and Short-Term Borrowings
Lines of Credit and Short-Term Borrowings

 

 

5.             Lines of Credit and Short-Term Borrowings

 

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2011 (dollars in millions):

 

Credit Facility

 

Expiration

 

Amount
Committed

 

Unused
Amount

 

Commitment
Fees

 

Pinnacle West Revolving Credit Facility

 

November 2016

 

$

200

 

$

200

 

0.275

%

 

 

 

 

 

 

 

 

 

 

APS Revolving Credit Facility

 

November 2016

 

500

 

500

 

0.225

%

 

 

 

 

 

 

 

 

 

 

APS Revolving Credit Facility

 

February 2015

 

500

 

500

 

0.250

%

Total

 

 

 

$

1,200

 

$