PINNACLE WEST CAPITAL CORP, 10-K filed on 2/21/2014
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2013
Feb. 14, 2014
Jun. 30, 2013
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, 2013 
 
 
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
 
 
$ 6,078,967,225 
Entity Common Stock, Shares Outstanding
 
110,194,366 
 
Document Fiscal Year Focus
2013 
 
 
Document Fiscal Period Focus
FY 
 
 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
CONSOLIDATED STATEMENTS OF INCOME
 
 
 
OPERATING REVENUES
$ 3,454,628 
$ 3,301,804 
$ 3,241,379 
OPERATING EXPENSES
 
 
 
Fuel and purchased power
1,095,709 
994,790 
1,009,464 
Operations and maintenance
924,727 
884,769 
904,286 
Depreciation and amortization
415,708 
404,336 
427,054 
Taxes other than income taxes
164,167 
159,323 
147,408 
Other expenses
7,994 
6,831 
6,659 
Total
2,608,305 
2,450,049 
2,494,871 
OPERATING INCOME
846,323 
851,755 
746,508 
OTHER INCOME (DEDUCTIONS)
 
 
 
Allowance for equity funds used during construction (Note 1)
25,581 
22,436 
23,707 
Other income (Note 18)
1,704 
1,606 
3,111 
Other expense (Note 18)
(16,024)
(19,842)
(10,451)
Total
11,261 
4,200 
16,367 
INTEREST EXPENSE
 
 
 
Interest charges
201,888 
214,616 
241,995 
Allowance for borrowed funds used during construction (Note 1)
(14,861)
(14,971)
(18,358)
Total
187,027 
199,645 
223,637 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
670,557 
656,310 
539,238 
INCOME TAXES (Note 4)
230,591 
237,317 
183,604 
INCOME FROM CONTINUING OPERATIONS
439,966 
418,993 
355,634 
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
 
 
 
Net of income tax expense (benefit) of $--, $(3,813) and $7,418 (Note 1)
 
(5,829)
11,306 
NET INCOME
439,966 
413,164 
366,940 
Less: Net income attributable to noncontrolling interests (Note 19)
33,892 
31,622 
27,467 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
406,074 
381,542 
339,473 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)
109,984 
109,510 
109,053 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)
110,806 
110,527 
109,864 
EARNINGS PER WEIGHTED - AVERAGE COMMON SHARE OUTSTANDING
 
 
 
Income from continuing operations attributable to common shareholders - basic (in dollars per share)
$ 3.69 
$ 3.54 
$ 3.01 
Net income attributable to common shareholders - basic (in dollars per share)
$ 3.69 
$ 3.48 
$ 3.11 
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)
$ 3.66 
$ 3.50 
$ 2.99 
Net income attributable to common shareholders - diluted (in dollars per share)
$ 3.66 
$ 3.45 
$ 3.09 
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
 
 
 
Income from continuing operations, net of tax
406,074 
387,380 
328,110 
Discontinued operations, net of tax
 
(5,838)
11,363 
Net income attributable to common shareholders
$ 406,074 
$ 381,542 
$ 339,473 
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
CONSOLIDATED STATEMENTS OF INCOME
 
 
Income tax expense (benefit) on discontinued operations
$ (3,813)
$ 7,418 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
NET INCOME
$ 439,966 
$ 413,164 
$ 366,940 
Derivative instruments:
 
 
 
Net unrealized loss, net of tax benefit of $140, $14,900, and $37,389 (Note 17)
(213)
(22,763)
(57,271)
Reclassification of net realized loss, net of tax benefit of $17,472, $39,120, and $46,288 (Note 17)
26,747 
59,887 
70,902 
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(6,156), $(651), and $3,935 (Note 8)
9,421 
1,031 
(6,026)
Total other comprehensive income
35,955 
38,155 
7,605 
COMPREHENSIVE INCOME
475,921 
451,319 
374,545 
Less: Comprehensive income attributable to noncontrolling interests
33,892 
31,622 
27,467 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ 442,029 
$ 419,697 
$ 347,078 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
Net unrealized loss, tax benefit
$ 140 
$ 14,900 
$ 37,389 
Reclassification of net realized loss, tax benefit
17,472 
39,120 
46,288 
Pension and other postretirement benefits activity, tax (expense) benefit
$ (6,156)
$ (651)
$ 3,935 
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
CURRENT ASSETS
 
 
Cash and cash equivalents
$ 9,526 
$ 26,202 
Customer and other receivables
299,904 
277,225 
Accrued unbilled revenues
96,796 
94,845 
Allowance for doubtful accounts
(3,203)
(3,340)
Materials and supplies (at average cost)
221,682 
218,096 
Fossil fuel (at average cost)
38,028 
31,334 
Deferred income taxes (Note 4)
91,152 
152,191 
Income tax receivable (Note 4)
135,517 
2,423 
Assets from risk management activities (Note 17)
17,169 
25,699 
Deferred fuel and purchased power regulatory asset (Note 3)
20,755 
72,692 
Other regulatory assets (Note 3)
76,388 
71,257 
Other current assets
39,895 
37,102 
Total current assets
1,043,609 
1,005,726 
INVESTMENTS AND OTHER ASSETS
 
 
Assets from risk management activities (Note 17)
23,815 
35,891 
Nuclear decommissioning trust (Notes 14 and 20)
642,007 
570,625 
Other assets
60,875 
62,694 
Total investments and other assets
726,697 
669,210 
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
 
 
Plant in service and held for future use
15,200,464 
14,346,367 
Accumulated depreciation and amortization
(5,300,219)
(4,929,613)
Net
9,900,245 
9,416,754 
Construction work in progress
581,369 
565,716 
Palo Verde sale leaseback, net of accumulated depreciation of $225,925 and $222,055 (Note 19)
125,125 
128,995 
Intangible assets, net of accumulated amortization of $439,703 and $411,543
157,689 
162,150 
Nuclear fuel, net of accumulated amortization of $146,057 and $133,950
124,557 
122,778 
Total property, plant and equipment
10,888,985 
10,396,393 
DEFERRED DEBITS
 
 
Regulatory assets (Notes 1, 3 and 4)
711,712 
1,099,900 
Income tax receivable (Note 4)
 
70,389 
Other
137,683 
137,997 
Total deferred debits
849,395 
1,308,286 
TOTAL ASSETS
13,508,686 
13,379,615 
CURRENT LIABILITIES
 
 
Accounts payable
284,516 
221,312 
Accrued taxes (Note 4)
130,998 
124,939 
Accrued interest
48,351 
49,380 
Common dividends payable
62,528 
59,789 
Short-term borrowings (Note 5)
153,125 
92,175 
Current maturities of long-term debt (Note 6)
540,424 
122,828 
Customer deposits
76,101 
79,689 
Liabilities from risk management activities (Note 17)
31,892 
73,741 
Liability for asset retirements (Note 12)
32,896 
 
Regulatory liabilities (Note 3)
99,273 
88,116 
Other current liabilities
158,540 
171,573 
Total current liabilities
1,618,644 
1,083,542 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
2,796,465 
3,199,088 
DEFERRED CREDITS AND OTHER
 
 
Deferred income taxes (Note 4)
2,351,882 
2,151,371 
Regulatory liabilities (Notes 1, 3 and 4)
801,297 
759,201 
Liability for asset retirements (Note 12)
313,833 
357,097 
Liabilities for pension and other postretirement benefits (Note 8)
513,628 
1,058,755 
Liabilities from risk management activities (Note 17)
70,315 
85,264 
Customer advances
114,480 
109,359 
Coal mine reclamation
207,453 
118,860 
Deferred investment tax credit
152,361 
99,819 
Unrecognized tax benefits (Note 4)
42,209 
71,135 
Other
185,659 
183,835 
Total deferred credits and other
4,753,117 
4,994,696 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
   
   
EQUITY (Note 7)
 
 
Common stock, no par value; authorized 150,000,000 shares, issued 110,280,703 at end of 2013 and 109,837,957 at end of 2012
2,491,558 
2,466,923 
Treasury stock at cost; 98,944 shares at end of 2013 and 95,192 shares at end of 2012
(4,308)
(4,211)
Total common stock
2,487,250 
2,462,712 
Retained earnings
1,785,273 
1,624,102 
Accumulated other comprehensive loss:
 
 
Pension and other postretirement benefits (Note 8)
(54,995)
(64,416)
Derivative instruments (Note 17)
(23,058)
(49,592)
Total accumulated other comprehensive loss
(78,053)
(114,008)
Total shareholders' equity
4,194,470 
3,972,806 
Noncontrolling interests (Note 19)
145,990 
129,483 
Total equity
4,340,460 
4,102,289 
TOTAL LIABILITIES AND EQUITY
$ 13,508,686 
$ 13,379,615 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
 
 
Accumulated depreciation of Palo Verde sale leaseback
$ 225,925 
$ 222,055 
Accumulated amortization on intangible assets
439,703 
411,543 
Accumulated amortization on nuclear fuel
$ 146,057 
$ 133,950 
EQUITY (Note 7)
 
 
Common stock, par value
   
   
Common stock, authorized shares
150,000,000 
150,000,000 
Common stock, issued shares
110,280,703 
109,837,957 
Treasury stock at cost, shares
98,944 
95,192 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net Income
$ 439,966 
$ 413,164 
$ 366,940 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Gain on sale of energy-related products and services business
 
 
(10,404)
Depreciation and amortization including nuclear fuel
492,322 
481,262 
493,784 
Deferred fuel and purchased power
21,678 
71,573 
69,166 
Deferred fuel and purchased power amortization
31,190 
(116,716)
(155,157)
Allowance for equity funds used during construction
(25,581)
(22,436)
(23,707)
Deferred income taxes
249,296 
187,023 
117,952 
Deferred investment tax credit
52,542 
41,579 
58,240 
Change in derivative instruments fair value
534 
(749)
4,064 
Changes in current assets and liabilities:
 
 
 
Customer and other receivables
(44,991)
14,587 
40,626 
Accrued unbilled revenues
(1,951)
30,394 
(21,947)
Materials, supplies and fossil fuel
(11,878)
(23,043)
(23,398)
Income tax receivable
(133,094)
(4,043)
3,983 
Other current assets
(17,913)
(27,352)
(3,079)
Accounts payable
45,414 
(96,600)
58,346 
Accrued taxes
6,059 
12,736 
8,085 
Other current liabilities
(7,513)
23,869 
20,358 
Change in margin and collateral accounts - assets
993 
2,216 
33,349 
Change in margin and collateral accounts - liabilities
12,355 
137,785 
29,731 
Change in long term income tax receivable
137,270 
(1,756)
(3,530)
Change in unrecognized tax benefits
(91,425)
(2,583)
8,410 
Change in other regulatory liabilities
64,473 
13,539 
37,009 
Change in other long-term assets
(41,757)
6,872 
(41,722)
Change in other long-term liabilities
(24,682)
29,801 
58,484 
Net cash flow provided by operating activities
1,153,307 
1,171,122 
1,125,583 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,016,322)
(889,551)
(884,350)
Contributions in aid of construction
41,090 
49,876 
38,096 
Allowance for borrowed funds used during construction
(14,861)
(14,971)
(18,358)
Proceeds from sale of energy-related products and services business
 
45,111 
Proceeds from nuclear decommissioning trust sales
446,025 
417,603 
497,780 
Investment in nuclear decommissioning trust
(463,274)
(434,852)
(513,799)
Proceeds from sale of life insurance policies
 
 
55,444 
Other
(2,059)
(1,099)
(1,931)
Net cash flow used for investing activities
(1,009,401)
(872,994)
(782,007)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
136,307 
476,081 
470,353 
Repayment of long-term debt
(122,828)
(654,286)
(655,169)
Short-term borrowings and payments - net
60,950 
92,175 
(16,600)
Dividends paid on common stock
(235,244)
(225,075)
(221,728)
Common stock equity issuance
17,319 
15,955 
15,841 
Distributions to noncontrolling interests
(17,385)
(10,529)
(10,210)
Other
299 
170 
(2,668)
Net cash flow used for financing activities
(160,582)
(305,509)
(420,181)
NET DECREASE IN CASH AND CASH EQUIVALENTS
(16,676)
(7,381)
(76,605)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
26,202 
33,583 
110,188 
CASH AND CASH EQUIVALENTS AT END OF YEAR
$ 9,526 
$ 26,202 
$ 33,583 
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, 2010
 
$ 2,421,372 
$ (2,239)
$ 1,423,961 
$ (159,767)
$ 91,899 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
Issuance of common stock
 
22,875 
 
 
 
 
 
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 declared ($2.23, $2.67, and $ 2.10 per share)
 
 
 
(228,951)
 
 
 
Net income attributable to noncontrolling interests
(27,467)
 
 
 
 
27,467 
 
Net capital activities by noncontrolling interests
 
 
 
 
 
(10,630)
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
 
 
 
 
 
 
 
Other comprehensive income attributable to common shareholders
7,605 
 
 
 
7,604 
 
7,605 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
347,078 
 
 
 
 
 
347,078 
Balance at Dec. 31, 2011
3,930,586 
2,444,247 
(4,717)
1,534,483 
(152,163)
108,736 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
Issuance of common stock
 
22,676 
 
 
 
 
 
Purchase of treasury stock
 
 
(4,607)
 
 
 
 
Reissuance of treasury stock used for stock compensation
 
 
5,113 
 
 
 
 
Net income attributable to common shareholders
381,542 
 
 
381,542 
 
 
381,542 
Common stock dividends declared ($2.23, $2.67, and $ 2.10 per share)
 
 
 
(291,923)
 
 
 
Net income attributable to noncontrolling interests
(31,622)
 
 
 
 
31,622 
 
Net capital activities by noncontrolling interests
 
 
 
 
 
(10,875)
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
 
 
 
 
 
 
 
Other comprehensive income attributable to common shareholders
38,155 
 
 
 
38,155 
 
38,155 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
419,697 
 
 
 
 
 
419,697 
Balance at Dec. 31, 2012
4,102,289 
2,466,923 
(4,211)
1,624,102 
(114,008)
129,483 
 
Increase (Decrease) in Shareholders' Equity
 
 
 
 
 
 
 
Issuance of common stock
 
24,635 
 
 
 
 
 
Purchase of treasury stock
 
 
(9,727)
 
 
 
 
Reissuance of treasury stock used for stock compensation
 
 
9,630 
 
 
 
 
Net income attributable to common shareholders
406,074 
 
 
406,074 
 
 
406,074 
Common stock dividends declared ($2.23, $2.67, and $ 2.10 per share)
 
 
 
(244,903)
 
 
 
Net income attributable to noncontrolling interests
(33,892)
 
 
 
 
33,892 
 
Net capital activities by noncontrolling interests
 
 
 
 
 
(17,385)
 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
 
 
 
 
 
 
 
Other comprehensive income attributable to common shareholders
35,955 
 
 
 
35,955 
 
35,955 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
442,029 
 
 
 
 
 
442,029 
Balance at Dec. 31, 2013
$ 4,340,460 
$ 2,491,558 
$ (4,308)
$ 1,785,273 
$ (78,053)
$ 145,990 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
 
 
 
Common stock dividends declared (in dollars per share)
$ 2.23 
$ 2.67 
$ 2.10 
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 and El Dorado, and formerly SunCor and 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 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.  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 reported as discontinued operations.  El Dorado is an investment firm.

 

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS and El Dorado, and formerly SunCor and APSES.  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 19).

 

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.

 

Certain line items are presented in more detail on the Consolidated Balance Sheets and 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 assets or net cash flow provided by operating activities.  The following tables show the impacts of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

 

Balance Sheets - December 31, 2012

 

As
previously
reported

 

Reclassifications to
conform to current year
presentation

 

Amount reported
after reclassification
to conform to current
year presentation

 

Long-Term Debt less Current Maturities —

 

 

 

 

 

 

 

Long-term debt less current maturities

 

$

3,160,219

 

$

38,869

 

$

3,199,088

 

Long-Term Debt less Current Maturities —

 

 

 

 

 

 

 

Palo Verde sale leaseback lessor notes less

 

 

 

 

 

 

 

current maturities

 

38,869

 

(38,869

)

 

 

Statement of Cash Flows for the
Year Ended December 31, 2012

 

As previously
reported

 

Reclassifications to
conform to current year
presentation

 

Amount reported after
reclassification to
conform to current
year presentation

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

Deferred income taxes

 

$

228,602

 

$

(41,579

)

$

187,023

 

Deferred investment tax credit

 

 

41,579

 

41,579

 

Accrued taxes and income tax receivable

 

8,693

 

(8,693

)

 

Income tax receivable

 

 

(4,043

)

(4,043

)

Accrued taxes

 

 

12,736

 

12,736

 

 

Statement of Cash Flows for the
Year Ended December 31, 2011

 

As previously
reported

 

Reclassifications to
conform to current year
presentation

 

Amount reported after
reclassification to
conform to current year
presentation

 

Cash Flows from Operating Activities

 

 

 

 

 

 

 

Deferred income taxes

 

$

176,192

 

$

(58,240

)

$

117,952

 

Deferred investment tax credit

 

 

58,240

 

58,240

 

Accrued taxes and income tax receivable

 

12,068

 

(12,068

)

 

Income tax receivable

 

 

3,983

 

3,983

 

Accrued taxes

 

 

8,085

 

8,085

 

 

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 12.

 

APS records a regulatory liability on its regulated assets 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, 2013 were as follows:

 

·                                          Fossil plant — 18 years;

·                                          Nuclear plant — 26 years;

·                                          Other generation — 26 years;

·                                          Transmission — 37 years;

·                                          Distribution — 34 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 use of the new Palo Verde nuclear plant lives, effective January 1, 2012.

 

Pursuant to an ACC order, we defer operating costs 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 are deferred on the depreciation line of the Consolidated Statements of Income.

 

For the years 2011 through 2013, the depreciation rates ranged from a low of 0.45% to a high of 12.08%.  The weighted-average rate was 3.00% for 2013, 2.71% for 2012, and 2.98% for 2011.

 

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 8.56% for 2013, 8.60% for 2012, and 10.25% for 2011.  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 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 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 17 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 our 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 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 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):

 

 

 

Years ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

 

 

 

 

 

 

 

Cash paid during the period for:

 

 

 

 

 

 

 

Income taxes, net of refunds

 

$

18,537

 

$

2,543

 

$

10,324

 

Interest, net of amounts capitalized

 

184,010

 

200,923

 

217,789

 

Significant non-cash investing and financing activities:

 

 

 

 

 

 

 

Accrued capital expenditures

 

$

33,184

 

$

26,208

 

$

27,245

 

Dividends declared but not paid

 

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 2013, $50 million in 2012, and $47 million in 2011.  Estimated amortization expense on existing intangible assets over the next five years is $47 million in 2014, $38 million in 2015, $29 million in 2016, $19 million in 2017, and $7 million in 2018.  At December 31, 2013, 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).

 

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 20 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.

 

New Accounting Standards
New Accounting Standards

2.                                      New Accounting Standards

 

During 2013, we adopted, on a retrospective basis, new guidance relating to balance sheet offsetting disclosures.  The new guidance requires enhanced disclosures regarding an entity’s ability to offset certain instruments on the balance sheet and how offsetting impacts the balance sheet.  The adoption of this guidance resulted in expanded disclosures relating to our derivative instruments (see Note 17), but did not impact our financial statement results.

 

During 2013, we also adopted, on a prospective basis, new guidance relating to reporting amounts reclassified from accumulated other comprehensive income.  This guidance requires new disclosures relating to accumulated other comprehensive income and how reclassifications from accumulated other comprehensive income impact net income.  As a result of adopting this new guidance, we have included a new footnote disclosure to provide the information required by the new standard (see Notes 21 and S-4).  The adoption of this guidance did not impact our financial statement results.

 

In July 2013, new guidance was issued which will generally require 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.  The intent of this guidance is to eliminate diversity in practice in the presentation of certain unrecognized tax benefits.  The new guidance is effective for us during the first quarter of 2014, and is permitted to be adopted using either a prospective or retrospective application.  Currently, we do not present unrecognized tax benefits as a reduction to deferred tax asset carryforwards on the balance sheet.  As a result, the adoption of this new guidance will impact our balance sheet presentation; however, we do not expect these presentation changes to be material to our balance sheet.  The adoption of this new guidance will not impact our results of operations or cash flows.

 

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 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 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, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

 

·                                          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.

 

2008 General Retail Rate Case On-Going Impacts

 

On December 30, 2009, the ACC issued an order approving the 2009 Settlement Agreement entered into by APS and twenty-one other parties.  The 2009 Settlement Agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

 

·                                          A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

 

·                                          Authorization and requirements of equity infusions into APS of $700 million during the period beginning June 1, 2009 through December 31, 2014 and compliance with various financial conditions, including the maintenance of a prescribed capital structure (APS was able to meet these conditions without the need for additional equity infusions beyond the $253 million infused into APS in the second quarter of 2010); and

 

·                                          Renewable energy programs that require APS to expand its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses.

 

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 so that utilities can establish compliance without using renewable energy credits.

 

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either:  (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price.  APS also proposed that the ACC:  (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.

 

On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on future customers who install rooftop solar panels 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. The new policy will be in effect until the next APS rate case.

 

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 professional 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, but instead 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.

 

Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC.

 

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Rules, which became effective January 1, 2011.  The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year.  This energy savings requirement is slightly higher than the goal established by the 2009 Settlement Agreement (2.75% of total energy resources for the same two-year period).  The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs.  This amount was recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).

 

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards require 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.

 

The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels.  ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward.  APS expects to receive a decision from the ACC in early 2014.

 

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished.  This spring the ACC will hold a series of three workshops 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.

 

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 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 for 2013 and 2012 (dollars in millions):

 

 

 

Twelve Months Ended
December 31,

 

 

 

2013

 

2012

 

Beginning balance

 

$

73

 

$

28

 

Deferred fuel and purchased power costs - current period

 

(21

)

(72

)

Amounts (charged) credited to customers

 

(31

)

117

 

Ending balance

 

$

21

 

$

73

 

 

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This represents a $0.000228 per kWh increase over the 2013 PSA charge.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

 

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 (discussed above), 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, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula.

 

Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula.  Pursuant to the 2012 Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.

 

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 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.  APS anticipates that the ACC will consider whether to approve APS’s LFCR adjustment prior to the end of March 2014.

 

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 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.  Workshops in this docket are expected to be held in 2014.

 

Four Corners

 

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  As a result of this purchase, APS now owns 63% of Units 4 and 5.  APS has a total entitlement from Four Corners of 970 MW.  The final purchase price for the interest was approximately $182 million.  APS acquired assets and assumed certain of SCE’s decommissioning and mine reclamation obligations.  We have recognized plant-in-service, net of accumulated depreciation, of $316 million, which includes an acquisition adjustment of $255 million.  In addition, we have recognized a liability of $34 million for the decommissioning obligations, $93 million for the mine reclamation obligations, $18 million of other various liabilities, and $11 million of construction work in progress relating to this purchase.  These amounts are subject to revision during the measurement period, not to exceed one year, to the extent additional information is obtained about the facts and circumstances that existed as of the acquisition date.  While we expect the ACC to approve the recovery of the acquisition adjustment, should recovery be disallowed, it will be reclassified from plant-in-service to goodwill, subject to impairment testing.  The decommissioning and mine reclamation obligations were recognized at their fair value.  Because APS’s rates are regulated, APS expects to recover the costs of the acquired plant assets, including a return on its investment based on its cost of capital.  APS believes this return is consistent with what a market participant would consider to be fair value in APS’s regulatory environment.  Accordingly, APS believes the cost of the plant assets approximate their fair value.

 

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 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.  This includes deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Four Corners Units 1-3.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Four Corners Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Four Corners Units 1-3 was $37 million as of December 31, 2013.

 

As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, 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 will 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 for transmission of the additional power received from Four Corners.  This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate.  APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement.  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.

 

Regulatory Assets and Liabilities

 

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

 

 

 

Remaining
Amortization

 

December 31, 2013

 

December 31, 2012

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Pension and other postretirement benefits

 

(a

)

$

 

$

314

 

$

 

$

780

 

Income taxes — AFUDC equity

 

2043

 

4

 

105

 

4

 

92

 

Deferred fuel and purchased power — mark-to-market (Note 17)

 

2016

 

5

 

29

 

19

 

21

 

Transmission vegetation management

 

2016

 

9

 

14

 

9

 

23

 

Coal reclamation

 

2038

 

8

 

18

 

8

 

24

 

Palo Verde VIEs (Note 19)

 

2046

 

 

41

 

 

38

 

Deferred compensation

 

2036

 

 

34

 

 

34

 

Deferred fuel and purchased power (b) (c)

 

2014

 

21

 

 

73

 

 

Tax expense of Medicare subsidy

 

2023

 

2

 

15

 

2

 

17

 

Loss on reacquired debt

 

2034

 

1

 

17

 

2

 

18

 

Income taxes — investment tax credit basis adjustment

 

2043

 

1

 

39

 

1

 

26

 

Pension and other postretirement benefits deferral

 

2015

 

8

 

4

 

8

 

13

 

Four Corners cost deferral

 

2024

 

 

37

 

 

 

Lost fixed cost recovery

 

2014

 

25

 

 

7

 

 

Transmission cost adjustor

 

2015

 

8

 

2

 

10

 

 

Retired power plant costs

 

2020

 

3

 

18

 

 

 

Other

 

Various

 

2

 

25

 

1

 

14

 

Total regulatory assets (d)

 

 

 

$

97

 

$

712

 

$

144

 

$

1,100

 

 

(a)                                 This asset represents the future recovery of under-funded 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 8 for further discussion.

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

(c)                                  Subject to a carrying charge.

(d)                                 There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”

 

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

 

 

 

Remaining
Amortization

 

December 31, 2013

 

December 31, 2012

 

 

 

Period

 

Current

 

Non-Current

 

Current

 

Non-Current

 

Removal costs

 

(a

)

$

28

 

$

303

 

$

27

 

$

321

 

Asset retirement obligations

 

(a

)

 

266

 

 

256

 

Renewable energy standard (b)

 

2015

 

33

 

15

 

43

 

 

Income taxes — change in rates

 

2043

 

 

74

 

 

66

 

Spent nuclear fuel

 

2047

 

6

 

36

 

10

 

36

 

Deferred gains on utility property

 

2019

 

2

 

10

 

2

 

12

 

Income taxes — deferred investment tax credit

 

2043

 

3

 

79

 

2

 

52

 

Demand side management (b)

 

2014

 

27

 

 

4

 

 

Other

 

Various

 

 

18

 

 

16

 

Total regulatory liabilities

 

 

 

$

99

 

$

801

 

$

88

 

$

759

 

 

(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.

Income Taxes
Income Taxes

4.             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.

 

The $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.

 

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  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 will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment.  To account for the adoption of these regulations, plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets.  Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.

 

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19).  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):

 

 

 

2013

 

2012

 

2011

 

Total unrecognized tax benefits, January 1

 

$

133,422

 

$

136,005

 

$

127,595

 

Additions for tax positions of the current year

 

3,516

 

5,167

 

10,915

 

Additions for tax positions of prior years

 

13,158

 

 

 

Reductions for tax positions of prior years for:

 

 

 

 

 

 

 

Changes in judgment

 

(108,099

)

(7,729

)

(1,555

)

Settlements with taxing authorities

 

 

 

(124

)

Lapses of applicable statute of limitations

 

 

(21

)

(826

)

Total unrecognized tax benefits, December 31

 

$

41,997

 

$

133,422

 

$

136,005

 

 

Included in the balances of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 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, 2010 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 2010.

 

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 benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012, and a pre-tax expense of $3 million for 2011.

 

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, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2013, we have recognized $5 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,

 

 

 

2013

 

2012

 

2011

 

Current:

 

 

 

 

 

 

 

Federal

 

$

(81,784

)

$

(3,493

)

$

(310

)

State

 

10,537

 

8,395

 

15,140

 

Total current

 

(71,247

)

4,902

 

14,830

 

Deferred:

 

 

 

 

 

 

 

Federal

 

279,973

 

200,322

 

159,566

 

State

 

21,865

 

28,280

 

16,626

 

Total deferred

 

301,838

 

228,602

 

176,192

 

Total income tax expense

 

230,591

 

233,504

 

191,022

 

Less: income tax expense (benefit) on discontinued operations

 

 

(3,813

)

7,418

 

Income tax expense — continuing operations

 

$

230,591

 

$

237,317

 

$

183,604

 

 

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,

 

 

 

2013

 

2012

 

2011

 

 

 

 

 

 

 

 

 

Federal income tax expense at 35% statutory rate

 

$

234,695

 

$

229,709

 

$

188,733

 

Increases (reductions) in tax expense resulting from:

 

 

 

 

 

 

 

State income tax net of federal income tax benefit

 

21,387

 

23,819

 

19,594

 

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

 

(3,356

)

 

 

Medicare Subsidy Part-D

 

823

 

483

 

823

 

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

 

(6,997

)

(6,158

)

(6,881

)

Palo Verde VIE noncontrolling interest (see Note 19)

 

(11,862

)

(11,065

)

(9,636

)

Other

 

(4,099

)

529

 

(9,029

)

Income tax expense — continuing operations

 

$

230,591

 

$

237,317

 

$

183,604

 

 

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

 

 

 

December 31,

 

 

 

2013

 

2012

 

Current asset

 

$

91,152

 

$

152,191

 

Long-term liability

 

(2,351,882

)

(2,151,371

)

Deferred income taxes — net

 

$

(2,260,730

)

$

(1,999,180

)

 

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, 2013 APS has recorded a regulatory liability of $75 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, 2013, 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,

 

 

 

2013

 

2012

 

DEFERRED TAX ASSETS

 

 

 

 

 

Risk management activities

 

$

44,920

 

$

72,243

 

Regulatory liabilities:

 

 

 

 

 

Asset retirement obligation and removal costs

 

235,959

 

238,669

 

Unamortized investment tax credits

 

82,116

 

53,837

 

Other

 

42,609

 

33,764

 

Pension and other postretirement liabilities

 

198,642

 

408,764

 

Renewable energy incentives

 

65,434

 

66,941

 

Credit and loss carryforwards

 

133,070

 

139,022

 

Other

 

148,492

 

68,844

 

Total deferred tax assets

 

951,242

 

1,082,084

 

DEFERRED TAX LIABILITIES

 

 

 

 

 

Plant-related

 

(2,903,730

)

(2,584,166

)

Risk management activities

 

(16,191

)

(23,940

)

Regulatory assets:

 

 

 

 

 

Allowance for equity funds used during construction

 

(43,058

)

(37,899

)

Deferred fuel and purchased power

 

(8,282

)

(28,858

)

Deferred fuel and purchased power — mark-to-market

 

(13,343

)

(15,796

)

Pension and other postretirement benefits

 

(129,250

)

(316,757

)

Other

 

(93,202

)

(68,170

)

Other

 

(4,916

)

(5,678

)

Total deferred tax liabilities

 

(3,211,972

)

(3,081,264

)

Deferred income taxes — net

 

$

(2,260,730

)

$

(1,999,180

)

 

As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $131 million which first begin to expire in 2031, and other federal and state loss carryforwards of $2 million which first begin to expire in 2018.

 

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, 2013 (dollars in millions):

 

Credit Facility

 

Expiration

 

Amount
Committed

 

Unused
Amount (a)

 

Commitment
Fees

 

Pinnacle West Revolving Credit Facility

 

November 2016

 

$

200

 

$

200

 

0.175

%

 

 

 

 

 

 

 

 

 

 

APS Revolving Credit Facility

 

November 2016

 

500

 

347

 

0.125

%

 

 

 

 

 

 

 

 

 

 

APS Revolving Credit Facility

 

April 2018

 

500

 

500

 

0.125

%

Total

 

 

 

$

1,200

 

$

1,047

 

 

 

 

(a)                                 At December 31, 2013, APS had $153 million of outstanding commercial paper.  Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $847 million.

 

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

 

Pinnacle West

 

At December 31, 2013, the Pinnacle West credit facility, which terminates in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At December 31, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

 

APS

 

On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility.  The new revolving credit facility matures in April 2018.

 

At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016.  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS can use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At December 31, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  In addition, APS had commercial paper borrowings of $153 million at December 31, 2013.

 

See “Financial Assurances” in Note 11 for a discussion of APS’s separate outstanding letters of credit.

 

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2012 (dollars in millions):

 

Credit Facility

 

Expiration

 

Amount
Committed

 

Unused
Amount (a)

 

Commitment
Fees

 

Pinnacle West Revolving Credit Facility

 

November 2016

 

$

200

 

$

200

 

0.225

%

 

 

 

 

 

 

 

 

 

 

APS Revolving Credit Facility

 

November 2016

 

500

 

408

 

0.175

%

 

 

 

 

 

 

 

 

 

 

APS Revolving Credit Facility

 

February 2015

 

500

 

500

 

0.20

%

Total

 

 

 

$

1,200

 

$

1,108

 

 

 

 

(a)                                 At December 31, 2012, APS had $92 million of outstanding commercial paper.  Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $908 million.

 

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

 

Pinnacle West

 

At December 31, 2012, the Pinnacle West credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At December 31, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

 

APS

 

APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At December 31, 2012, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  In addition, APS had commercial paper borrowings of $92 million at December 31, 2012.

 

See “Financial Assurances” in Note 11 for a discussion of APS’s separate outstanding letters of credit.

 

Debt Provisions

 

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.  On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt.  This financing order is set to expire on December 31, 2017.

 

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

6.                                      Long-Term Debt and Liquidity Matters

 

All of Pinnacle West’s and APS’s debt is unsecured.  The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2013 and 2012 (dollars in thousands):

 

 

 

Maturity

 

Interest

 

December 31,

 

 

 

Dates (a)

 

Rates

 

2013

 

2012

 

APS

 

 

 

 

 

 

 

 

 

Pollution Control Bonds:

 

 

 

 

 

 

 

 

 

Variable

 

2029-2038

 

(b)

 

$

75,580

 

$

75,580

 

Fixed

 

2024-2034

 

1.25%-6.00%

 

426,125

 

490,275

 

Total Pollution Control Bonds

 

 

 

 

 

501,705

 

565,855

 

 

 

 

 

 

 

 

 

 

 

Senior unsecured notes

 

2014-2042

 

4.50%-8.75%

 

2,675,000

 

2,575,000

 

Palo Verde sale leaseback lessor notes

 

2015

 

8.00%

 

38,869

 

65,547

 

Unamortized discount

 

 

 

 

 

(8,732

)

(9,486

)

Unamortized premium

 

 

 

 

 

5,047

 

 

Total APS long-term debt

 

 

 

 

 

3,211,889

 

3,196,916

 

Less current maturities

 

(d)

 

 

 

540,424

 

122,828

 

Total APS long-term debt less current maturities

 

 

 

 

 

2,671,465

 

3,074,088

 

Pinnacle West

 

 

 

 

 

 

 

 

 

Term loan

 

2015

 

(c)

 

125,000

 

125,000

 

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES

 

 

 

 

 

$

2,796,465

 

$

3,199,088

 

 

(a)                                 This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b)                                 The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.06% at December 31, 2013 and 0.13%-0.15% at December 31, 2012.

(c)                                  The weighted-average interest rate was 1.269% at December 31, 2013 and 1.312% at December 31, 2012.

(d)                                 Current maturities include $215 million of pollution control bonds expected to be remarketed in 2014 and $300 million in senior unsecured notes that mature in 2014.

 

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in millions):

 

Year

 

Consolidated
Pinnacle West

 

Consolidated
APS

 

2014

 

$

540

 

$

540

 

2015

 

470

 

345

 

2016

 

358

 

358

 

2017

 

 

 

2018

 

32

 

32

 

Thereafter

 

1,940

 

1,940

 

Total

 

$

3,340

 

$

3,215

 

 

Debt Fair Value

 

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within level 2 of the fair value hierarchy.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 

 

 

As of
December 31, 2013

 

As of
December 31, 2012

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Pinnacle West

 

$

125

 

$

125

 

$

125

 

$

125

 

APS

 

3,212

 

3,454

 

3,197

 

3,750

 

Total

 

$

3,337

 

$

3,579

 

$

3,322

 

$

3,875

 

 

Credit Facilities and Debt Issuances

 

APS

 

On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.

 

On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029.  On May 28, 2013, we remarketed the bonds.  The interest rate for these bonds was set to a new term rate.  The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018.  During this time, the bonds will bear interest at a rate of 1.75% per annum.  These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2013 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

 

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

 

On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

 

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt indebtedness.

 

See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 11 for discussion of APS’s other letters of credit.

 

Debt Provisions

 

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At December 31, 2013, the ratio was approximately 47% for Pinnacle West and 45% for APS.  Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.  See further discussion of “cross-default” provisions below.

 

Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.  However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

 

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.  All of APS’s bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements.  Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

 

An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At December 31, 2013, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same.  Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

 

Common Stock and Treasury Stock
Common Stock and Treasury Stock

7.                                      Common Stock and Treasury Stock

 

Our common stock and treasury stock activity during each of the three years 2013, 2012 and 2011 is as follows (dollars in thousands):

 

 

 

Common Stock

 

Treasury Stock

 

 

 

Shares

 

Amount

 

Shares

 

Amount

 

Balance at December 31, 2010

 

108,820,067

 

$

2,421,372

 

(50,410

)

$

(2,239

)

 

 

 

 

 

 

 

 

 

 

Common stock issuance

 

536,907

 

22,875

 

 

 

Purchase of treasury stock (a)

 

 

 

(88,440

)

(3,720

)

Reissuance of treasury stock for stock compensation

 

 

 

27,689

 

1,242

 

Balance at December 31, 2011

 

109,356,974

 

2,444,247

 

(111,161

)

(4,717

)

 

 

 

 

 

 

 

 

 

 

Common stock issuance

 

480,983

 

22,676

 

 

 

Purchase of treasury stock (a)

 

 

 

(89,629

)

(4,607

)

Reissuance of treasury stock for stock compensation

 

 

 

105,598

 

5,113

 

Balance at December 31, 2012

 

109,837,957

 

2,466,923

 

(95,192

)

(4,211

)

 

 

 

 

 

 

 

 

 

 

Common stock issuance

 

442,746

 

24,635

 

 

 

Purchase of treasury stock (a)

 

 

 

(174,290

)

(9,727

)

Reissuance of treasury stock for stock compensation

 

 

 

170,538

 

9,630

 

Balance at December 31, 2013

 

110,280,703

 

$

2,491,558

 

(98,944

)

$

(4,308

)

 

(a)                                 Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

 

At December 31, 2013, 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.

 

Retirement Plans and Other Benefits
Retirement Plans and Other Benefits

8.                                      Retirement Plans and Other Benefits

 

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries.  All new employees participate in the account balance plan.  Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant.  The pension plan covers nearly all employees.  The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors.  Our employees do not contribute to the plans.  Generally, we calculate the benefits based on age, years of service and pay.

 

Pinnacle West also sponsors an other postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries.  This plan provides medical and life insurance benefits to retired employees.  Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.  For the medical insurance plan, retirees make contributions to cover a portion of the plan costs.  For the life insurance plan, retirees do not make contributions.  We retain the right to change or eliminate these benefits.

 

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.  See Note 14 for further discussion of how fair values are determined.  Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

 

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates.  Accordingly, these changes are recorded as a regulatory asset.  In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012.  We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011.  Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over 3 years beginning in July 2012.  We amortized approximately $8 million during 2013 and $4 million during 2012.

 

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

 

 

 

Pension

 

Other Benefits

 

 

 

2013

 

2012

 

2011

 

2013

 

2012

 

2011

 

Service cost-benefits earned during the period

 

$

64,195

 

$

63,502

 

$

57,605

 

$

23,597

 

$

27,163

 

$

21,856

 

Interest cost on benefit obligation

 

112,392

 

119,586

 

124,727

 

41,536

 

46,467

 

46,807

 

Expected return on plan assets

 

(146,333

)

(140,979

)

(133,678

)

(45,717

)

(45,793

)

(41,536

)

Amortization of:

 

 

 

 

 

 

 

 

 

 

 

 

 

Transition obligation

 

 

 

 

 

452

 

452

 

Prior service cost (credit)

 

1,097

 

1,143

 

1,400

 

(179

)

(179

)

(179

)

Net actuarial loss

 

39,852

 

44,250

 

25,956

 

11,310

 

20,233

 

15,015

 

Net periodic benefit cost

 

$

71,203

 

$

87,502

 

$

76,010

 

$

30,547

 

$

48,343

 

$

42,415

 

Portion of cost charged to expense

 

$

38,968

 

$

36,333

 

$

29,312

 

$

18,469

 

$

19,321

 

$

15,208

 

 

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2013 and 2012 (dollars in thousands):

 

 

 

Pension

 

Other Benefits

 

 

 

2013

 

2012

 

2013

 

2012

 

Change in Benefit Obligation

 

 

 

 

 

 

 

 

 

Benefit obligation at January 1