UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10-Q

(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2012
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-3034

Xcel Energy Inc.
(Exact name of registrant as specified in its charter)

Minnesota
 
41-0448030
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
414 Nicollet Mall
 
 
Minneapolis, Minnesota
 
55401
(Address of principal executive offices)
 
(Zip Code)

(612) 330-5500
 (Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    xYes  oNo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    xYes  oNo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer x
 
Accelerated filer £
Non-accelerated filer o (Do not check if smaller reporting company)
 
Smaller reporting company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). oYes  xNo

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Class
 
Outstanding at Oct. 18, 2012
Common Stock, $2.50 par value
 
487,619,543 shares
 

 


TABLE OF CONTENTS

PART I
 
3
 
Item 1 —
3
 
 
3
 
 
4
 
 
5
 
 
6
 
 
7
 
 
9
 
Item 2 —
36
 
Item 3 —
55
 
Item 4 —
56
PART II
 
56
 
Item 1 —
56
 
Item 1A —
56
 
Item 2 —
56
 
Item 4 —
56
 
Item 5 —
56
 
Item 6 —
57
 
 
58
 
 
Certifications Pursuant to Section 302
1
 
 
Certifications Pursuant to Section 906
1
 
 
Statement Pursuant to Private Litigation
1

This Form 10-Q is filed by Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Company (SPS).  Xcel Energy Inc. and its consolidated subsidiaries are also referred to herein as Xcel Energy.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

2

Table of Contents
 
PART I — FINANCIAL INFORMATION
Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands, except per share data)
 
   
Three Months Ended Sept. 30
   
Nine Months Ended Sept. 30
 
   
2012
   
2011
   
2012
   
2011
 
Operating revenues
                       
Electric
  $ 2,532,709     $ 2,619,424     $ 6,506,320     $ 6,777,793  
Natural gas
    174,513       194,930       1,016,861       1,251,817  
Other
    17,119       17,244       53,907       56,750  
Total operating revenues
    2,724,341       2,831,598       7,577,088       8,086,360  
                                 
Operating expenses
                               
Electric fuel and purchased power
    1,006,830       1,150,252       2,725,183       3,071,493  
Cost of natural gas sold and transported
    49,739       87,107       557,444       793,539  
Cost of sales — other
    7,251       7,154       20,499       22,100  
Operating and maintenance expenses
    531,480       532,962       1,576,178       1,575,159  
Conservation and demand side management program expenses
    68,920       71,280       191,242       212,075  
Depreciation and amortization
    239,051       242,329       694,364       696,316  
Taxes (other than income taxes)
    100,636       89,018       305,892       278,077  
Total operating expenses
    2,003,907       2,180,102       6,070,802       6,648,759  
                                 
Operating income
    720,434       651,496       1,506,286       1,437,601  
                                 
Other income, net
    488       2,550       4,953       8,295  
Equity earnings of unconsolidated subsidiaries
    7,490       7,423       22,150       22,813  
Allowance for funds used during construction — equity
    15,860       11,840       44,504       38,690  
                                 
Interest charges and financing costs
                               
Interest charges — includes other financing costs of
 $6,010, $6,279, $18,126 and $17,724, respectively
    153,719       148,011       457,470       438,703  
Allowance for funds used during construction — debt
    (10,439 )     (6,301 )     (24,729 )     (21,575 )
Total interest charges and financing costs
    143,280       141,710       432,741       417,128  
                                 
Income from continuing operations before income taxes
    600,992       531,599       1,145,152       1,090,271  
Income taxes
    202,845       193,304       380,161       389,838  
Income from continuing operations
    398,147       338,295       764,991       700,433  
(Loss) income from discontinued operations, net of tax
    (41 )     37       68       230  
Net income
    398,106       338,332       765,059       700,663  
Dividend requirements on preferred stock
    -       1,414       -       3,534  
Premium on redemption of preferred stock
    -       3,260       -       3,260  
Earnings available to common shareholders
  $ 398,106     $ 333,658     $ 765,059     $ 693,869  
                                 
Weighted average common shares outstanding:
                               
Basic
    488,084       485,344       487,722       484,640  
Diluted
    488,578       485,894       488,198       485,152  
                                 
Earnings per average common share:
                               
Basic
  $ 0.82     $ 0.69     $ 1.57     $ 1.43  
Diluted
    0.81       0.69       1.57       1.43  
                                 
Cash dividends declared per common share
  $ 0.27     $ 0.26     $ 0.80     $ 0.77  
 
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in thousands)
 
   
Three Months Ended Sept. 30
   
Nine Months Ended Sept. 30
 
 
 
2012
   
2011
   
2012
   
2011
 
 
 
 
   
 
   
 
   
 
 
Net income
  $ 398,106     $ 338,332     $ 765,059     $ 700,663  
                                 
Other comprehensive loss
                               
                                 
Pension and retiree medical benefits:
                               
Amortization of losses included in net periodic benefit cost,
net of tax of $636, $515, $1,905 and $1,591, respectively
    911       743       2,738       2,290  
                                 
Derivative instruments:
                               
Net fair value decrease, net of tax of $(5,913), $(20,292),
$(12,586) and $(20,188), respectively
    (8,853 )     (30,947 )     (19,188 )     (30,740 )
Reclassification of losses to net income, net of tax of
$296, $150, $610 and $438, respectively
    393       159       756       464  
      (8,460 )     (30,788 )     (18,432 )     (30,276 )
                                 
Marketable securities:
                               
Net fair value (decrease) increase, net of tax of
$(30), $41, $89 and $76, respectively
    (45 )     59       129       110  
                                 
Other comprehensive loss
    (7,594 )   (29,986 )     (15,565 )     (27,876 )
Comprehensive income
  $ 390,512     $ 308,346     $ 749,494     $ 672,787  

See Notes to Consolidated Financial Statements
 
4


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
   
Nine Months Ended Sept. 30
 
   
2012
   
2011
 
Operating activities
 
 
   
 
 
Net income
  $ 765,059     $ 700,663  
Remove income from discontinued operations
    (68 )     (230 )
Adjustments to reconcile net income to cash provided by operating activities:
               
Depreciation and amortization
    707,630       709,936  
Conservation and demand side management program amortization
    5,511       7,979  
Nuclear fuel amortization
    79,171       75,292  
Deferred income taxes
    440,413       389,355  
Amortization of investment tax credits
    (4,656 )     (4,740 )
Allowance for equity funds used during construction
    (44,504 )     (38,690 )
Equity earnings of unconsolidated subsidiaries
    (22,150 )     (22,813 )
Dividends from unconsolidated subsidiaries
    24,922       25,481  
Share-based compensation expense
    20,886       31,943  
Net realized and unrealized hedging and derivative transactions
    (90,123 )     14,537  
Changes in operating assets and liabilities:
               
Accounts receivable
    (125,803 )     (33,649 )
Accrued unbilled revenues
    166,857       155,854  
Inventories
    55,511       (47,207 )
Other current assets
    (30,289 )     60,216  
Accounts payable
    (118,276 )     (82,681 )
Net regulatory assets and liabilities
    1,848       134,338  
Other current liabilities
    (35,283 )     5,969  
Pension and other employee benefit obligations
    (181,281 )     (136,538 )
Change in other noncurrent assets
    (38,790 )     21,211  
Change in other noncurrent liabilities
    (4,664 )     (42,108 )
Net cash provided by operating activities
    1,571,921       1,924,118  
                 
Investing activities
               
Utility capital/construction expenditures
    (1,805,843 )     (1,604,206 )
Proceeds from insurance recoveries
    56,892       -  
Merricourt refund
    -       101,261  
Merricourt deposit
    -       (90,833 )
Allowance for equity funds used during construction
    44,504       38,690  
Purchases of investments in external decommissioning fund
    (501,009 )     (1,741,907 )
Proceeds from the sale of investments in external decommissioning fund
    501,009       1,741,909  
Investment in WYCO Development LLC
    (779 )     (1,768 )
Change in restricted cash
    95,287       (99,972 )
Other, net
    343       (4,129 )
Net cash used in investing activities
    (1,609,596 )     (1,660,955 )
                 
Financing activities
               
Proceeds from (repayments of) short-term borrowings, net
    85,000       (416,400 )
Proceeds from issuance of long-term debt
    1,691,322       688,686  
Repayments of long-term debt, including reacquisition premiums
    (653,532 )     (104,525 )
Proceeds from issuance of common stock
    5,878       6,164  
Repurchase of common stock
    (18,529 )     -  
Purchase of common stock for settlement of equity awards
    (23,307 )     -  
Dividends paid
    (362,568 )     (351,370 )
Net cash provided by (used in) financing activities
    724,264       (177,445 )
                 
Net change in cash and cash equivalents
    686,589       85,718  
Cash and cash equivalents at beginning of period
    60,684       108,437  
Cash and cash equivalents at end of period
  $ 747,273     $ 194,155  
                 
Supplemental disclosure of cash flow information:
               
Cash paid for interest (net of amounts capitalized)
  $ (436,296 )   $ (405,111 )
Cash (paid) received for income taxes, net
    (6,257 )     53,567  
Supplemental disclosure of non-cash investing and financing transactions:
               
Property, plant and equipment additions in accounts payable
  $ 229,847     $ 136,236  
Issuance of common stock for reinvested dividends and 401(k) plans
    51,350       55,319  
 
See Notes to Consolidated Financial Statements
 
5


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands, except share and per share data)
 
   
Sept. 30, 2012
   
Dec. 31, 2011
 
Assets
 
 
   
 
 
Current assets
 
 
   
 
 
Cash and cash equivalents
  $ 747,273     $ 60,684  
Restricted cash
    -       95,287  
Accounts receivable, net
    704,580       753,120  
Accrued unbilled revenues
    521,883       688,740  
Inventories
    562,721       618,232  
Regulatory assets
    353,807       402,235  
Derivative instruments
    79,988       64,340  
Deferred income taxes
    225,877       178,446  
Prepayments and other
    174,715       121,480  
Total current assets
    3,370,844       2,982,564  
                 
Property, plant and equipment, net
    23,401,597       22,353,367  
                 
Other assets
               
Nuclear decommissioning fund and other investments
    1,578,381       1,463,515  
Regulatory assets
    2,367,431       2,389,008  
Derivative instruments
    135,739       152,887  
Other
    203,506       155,926  
Total other assets
    4,285,057       4,161,336  
Total assets
  $ 31,057,498     $ 29,497,267  
                 
Liabilities and Equity
               
Current liabilities
               
Current portion of long-term debt
  $ 859,462     $ 1,059,922  
Short-term debt
    304,000       219,000  
Accounts payable
    885,099       902,078  
Regulatory liabilities
    219,464       275,095  
Taxes accrued
    264,792       289,713  
Accrued interest
    160,621       177,111  
Dividends payable
    131,653       126,487  
Derivative instruments
    33,126       157,414  
Other
    302,317       381,819  
Total current liabilities
    3,160,534       3,588,639  
                 
Deferred credits and other liabilities
               
Deferred income taxes
    4,551,072       4,020,377  
Deferred investment tax credits
    83,971       86,743  
Regulatory liabilities
    1,053,542       1,101,534  
Asset retirement obligations
    1,716,612       1,651,793  
Derivative instruments
    248,321       263,906  
Customer advances
    252,879       248,345  
Pension and employee benefit obligations
    810,057       1,001,906  
Other
    224,400       203,313  
Total deferred credits and other liabilities
    8,940,854       8,577,917  
                 
Commitments and contingencies
               
Capitalization
               
Long-term debt
    10,105,947       8,848,513  
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 487,612,881 and
 486,493,933 shares outstanding at Sept. 30, 2012 and Dec. 31, 2011, respectively
    1,219,032       1,216,234  
Additional paid in capital
    5,334,715       5,327,443  
Retained earnings
    2,406,016       2,032,556  
Accumulated other comprehensive loss
    (109,600 )     (94,035 )
Total common stockholders' equity
    8,850,163       8,482,198  
Total liabilities and equity
  $ 31,057,498     $ 29,497,267  
 
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED)
(amounts in thousands)
 
   
Common Stock Issued
                   
                           
Accumulated
     
                         
Other
   
Total Common
 
               
Additional Paid In
   
Retained
   
Comprehensive
   
Stockholders'
 
   
Shares
   
Par Value
   
Capital
   
Earnings
   
Loss
   
Equity
 
Three Months Ended Sept. 30,
2012 and 2011
                                   
Balance at June 30, 2011
    484,543     $ 1,211,356     $ 5,261,687     $ 1,812,505     $ (50,983 )   $ 8,234,565  
Comprehensive income:
                                               
Net income
                            338,332               338,332  
Other comprehensive loss
                                    (29,986 )     (29,986 )
Comprehensive income
                                            308,346  
Dividends declared:
                                               
Cumulative preferred stock
                            (1,414 )             (1,414 )
Common stock
                            (126,723 )             (126,723 )
Premium on redemption of
preferred stock
                            (3,260 )             (3,260 )
Issuances of common stock
    405       1,013       8,738                       9,751  
Share-based compensation
                    10,038                       10,038  
Balance at Sept. 30, 2011
    484,948     $ 1,212,369     $ 5,280,463     $ 2,019,440     $ (80,969 )   $ 8,431,303  
                                                 
Balance at June 30, 2012
    487,286     $ 1,218,214     $ 5,316,658     $ 2,140,639     $ (102,006 )   $ 8,573,505  
Comprehensive income:
                                               
Net income
                            398,106               398,106  
Other comprehensive loss
                                    (7,594 )     (7,594 )
Comprehensive income
                                            390,512  
Dividends declared:
                                               
Common stock
                            (132,729 )             (132,729 )
Issuances of common stock
    327       818       8,679                       9,497  
Share-based compensation
                    9,378                       9,378  
Balance at Sept. 30, 2012
    487,613     $ 1,219,032     $ 5,334,715     $ 2,406,016     $ (109,600 )   $ 8,850,163  

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED)
(amounts in thousands)
 

   
Common Stock Issued
                   
                           
Accumulated
     
                         
Other
   
Total Common
 
               
Additional
   
Retained
   
Comprehensive
   
Stockholders'
 
   
Shares
   
Par Value
   
Paid In Capital
   
Earnings
   
Loss
   
Equity
 
Nine Months Ended Sept. 30,
2012 and 2011
                                   
Balance at Dec. 31, 2010
    482,334     $ 1,205,834     $ 5,229,075     $ 1,701,703     $ (53,093 )   $ 8,083,519  
Comprehensive income:
                                               
Net income
                            700,663               700,663  
Other comprehensive loss
                                    (27,876 )     (27,876 )
Comprehensive income
                                            672,787  
Dividends declared:
                                               
Cumulative preferred stock
                            (3,534 )             (3,534 )
Common stock
                            (376,132 )             (376,132 )
Premium on redemption of
preferred stock
                            (3,260 )             (3,260 )
Issuances of common stock
    2,614       6,535       18,462                       24,997  
Share-based compensation
                    32,926                       32,926  
Balance at Sept. 30, 2011
    484,948     $ 1,212,369     $ 5,280,463     $ 2,019,440     $ (80,969 )   $ 8,431,303  
                                                 
Balance at Dec. 31, 2011
    486,494     $ 1,216,234     $ 5,327,443     $ 2,032,556     $ (94,035 )   $ 8,482,198  
Comprehensive income:
                                               
Net income
                            765,059               765,059  
Other comprehensive loss
                                    (15,565 )     (15,565 )
Comprehensive income
                                            749,494  
Dividends declared:
                                               
Common stock
                            (391,599 )             (391,599 )
Issuances of common stock
    1,819       4,548       19,449                       23,997  
Repurchase of common stock
    (700 )     (1,750 )     (16,779 )                     (18,529 )
Purchase of common stock for
settlement of equity awards
                    (23,307 )                     (23,307 )
Share-based compensation
                    27,909                       27,909  
Balance at Sept. 30, 2012
    487,613     $ 1,219,032     $ 5,334,715     $ 2,406,016     $ (109,600 )   $ 8,850,163  

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of Sept. 30, 2012 and Dec. 31, 2011; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders' equity for the three and nine months ended Sept. 30, 2012 and 2011; and its cash flows for the nine months ended Sept. 30, 2012 and 2011.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after Sept. 30, 2012 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2011.  These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q.  Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations.  For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2011, filed with the SEC on Feb. 24, 2012.  Due to the seasonality of Xcel Energy's electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Adopted

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders' equity.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  Xcel Energy implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements.  For required fair value measurement disclosures, see Note 8.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  Xcel Energy implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity's financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  Xcel Energy does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

3.
Selected Balance Sheet Data
 
(Thousands of Dollars)   Sept. 30, 2012     Dec. 31, 2011  
Accounts receivable, net
 
 
   
 
 
Accounts receivable
  $ 753,782     $ 811,685  
Less allowance for bad debts
    (49,202 )     (58,565 )
 
  $ 704,580     $ 753,120  
 
               
(Thousands of Dollars)    
Sept. 30, 2012 
     
Dec. 31, 2011 
 
Inventories
               
Materials and supplies
  $ 213,949     $ 202,699  
Fuel
    202,872       236,023  
Natural gas
    145,900       179,510  
 
  $ 562,721     $ 618,232  
 
               
(Thousands of Dollars)    
Sept. 30, 2012 
     
Dec. 31, 2011 
 
Property, plant and equipment, net
               
Electric plant
  $ 28,032,442     $ 27,254,541  
Natural gas plant
    3,774,764       3,676,754  
Common and other property
    1,476,663       1,546,643  
Plant to be retired (a)
    105,573       151,184  
Construction work in progress
    1,681,128       1,085,245  
Total property, plant and equipment
    35,070,570       33,714,367  
Less accumulated depreciation
    (12,023,296 )     (11,658,351 )
Nuclear fuel
    2,075,442       1,939,299  
Less accumulated amortization
    (1,721,119 )     (1,641,948 )
 
  $ 23,401,597     $ 22,353,367  
 
(a)
In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017.  In 2011, Cherokee Unit 2 was retired and in May 2012, Cherokee Unit 1 was retired.  Amounts are presented net of accumulated depreciation.
 
4.
Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in Xcel Energy Inc.'s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit Xcel Energy files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy's 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy's 2009 federal income tax return expires in September 2013.  In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011.

State Audits  Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns.  As of Sept. 30, 2012, Xcel Energy's earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:
 
State
 
Year
Colorado
 
2006
Minnesota
 
2008
Texas
 
2007
Wisconsin
 
2008
 
As of Sept. 30, 2012, there were no state income tax audits in progress.
 
10

 
Unrecognized Tax Benefits The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR).  In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefits is as follows:
 
(Millions of Dollars)
 
Sept. 30, 2012
   
Dec. 31, 2011
 
Unrecognized tax benefit — Permanent tax positions
  $ 4.7     $ 4.3  
Unrecognized tax benefit — Temporary tax positions
    32.6       30.4  
Total unrecognized tax benefit
  $ 37.3     $ 34.7  
 
The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)
 
Sept. 30, 2012
   
Dec. 31, 2011
 
NOL and tax credit carryforwards
  $ (36.2 )   $ (33.6 )
 
It is reasonably possible that Xcel Energy's amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. At this time, due to the uncertain nature of the audit process, an overall range of possible change cannot be reasonably estimated.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits at Sept. 30, 2012 and Dec. 31, 2011 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2012 or Dec. 31, 2011.

Federal Tax Loss Carryback Claims — Xcel Energy completed an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result of a higher tax rate in prior years, Xcel Energy recognized a discrete tax benefit of approximately $15 million in the first quarter of 2012.

Impact of the Patient Protection and Affordable Care Act — In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Xcel Energy expensed approximately $17 million of previously recognized tax benefits relating to the federal subsidies during the first quarter of 2010.

In the third quarter of 2012, Xcel Energy implemented a tax strategy related to the allocation of funding of Xcel Energy's retiree prescription drug plan.  This strategy restored a portion of the tax benefit associated with federal subsidies for prescription drug plans that had been accrued since 2004 and was expensed in 2010.  As a result, Xcel Energy recognized approximately $17 million of income tax benefit.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.'s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

NSP‑Minnesota – Minnesota Electric Rate Case — In November 2010, NSP‑Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent, and an additional increase of $48.3 million, or 1.81 percent, in 2012.  The rate filing was based on a 2011 forecast test year, a requested return on equity (ROE) of 11.25 percent, an electric rate base of $5.6 billion and an equity ratio of 52.56 percent.  The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.  In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and an additional increase of approximately $29 million in 2012.
In November 2011, NSP-Minnesota reached a settlement agreement with certain customer intervenors.  In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  In March 2012, the MPUC approved the settlement.  In May 2012, the MPUC issued an order approving the following:

· A rate increase of approximately $58 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent and an equity ratio of 52.56 percent.
· A reduction to depreciation expense and NSP-Minnesota's rate request by $30 million.

NSP-Minnesota filed its final rate implementation and interim rate refund compliance filing in June 2012, which the MPUC approved in August 2012.  Final rates were implemented Sept. 1, 2012, and interim refunds will be completed during October 2012.

NSP‑Minnesota – Minnesota Property Tax Deferral Request — In December 2011, NSP-Minnesota filed a request to defer incremental 2012 property taxes that would not be recovered in base rates, estimated to be approximately $24 million, or alternatively that a property tax rider be approved.  In June 2012, the MPUC denied NSP-Minnesota's request for deferred accounting for incremental property taxes and also denied the request for a property tax rider.  There were no incremental 2012 property taxes deferred as a regulatory asset.

Pending and Recently Concluded Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

NSP-Minnesota – South Dakota 2011 Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $14.6 million annually, effective in 2012.  The request was based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  On Jan. 2, 2012, interim rates of $12.7 million were implemented.  In June 2012, the SDPUC authorized a rate increase of approximately $8.0 million, based on an ROE of 9.25 percent, and an equity ratio of 53 percent.  Final rates became effective Aug. 1, 2012.  Interim rate refunds of $2.9 million were completed in September 2012.

NSP-Minnesota – South Dakota 2012 Electric Rate Case  In June 2012, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $19.4 million annually.  The request was based on a 2011 historic test year adjusted for known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent.  Discovery is being conducted and a procedural schedule has not been established.  A SDPUC decision is expected in late 2012 or early 2013.

NSP-Wisconsin

Pending Regulatory Proceedings Public Service Commission of Wisconsin (PSCW)

NSP-Wisconsin 2012 Electric and Gas Rate Case  In June 2012, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2013.  NSP-Wisconsin requested an overall increase in annual electric rates of $39.1 million, or 6.7 percent, and an increase in natural gas rates of $5.3 million, or 4.9 percent.

The electric rate filing was based on a 2013 forecast test year, an ROE of 10.40 percent, an equity ratio of 52.50 percent and an average 2013 electric rate base of approximately $788.6 million.  The natural gas rate request was solely due to a proposal to recover the initial costs associated with the environmental cleanup of the Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) in Ashland, Wis.

On Oct. 19, 2012, the PSCW Staff and intervenors filed their direct testimony.  The PSCW Staff recommended an electric rate increase of $32.9 million, or 5.6 percent, based on a 10.40 percent ROE and a 52.50 percent equity ratio.  The major adjustments recommended by the PSCW Staff were a $2.2 million reduction in employee compensation expense primarily related to disallowance of the annual incentive program and a net $2.9 million reduction in electric fuel expense and fixed production charges.  The PSCW Staff testimony acknowledged the unique issues before the PSCW related to the Ashland site cleanup and presented several alternatives for consideration by the PSCW.

Rebuttal testimony is expected to be filed on Oct. 31, 2012, and the hearing is expected to be held on Nov. 7, 2012.  A PSCW decision is anticipated in December 2012.

PSCo

Recently Concluded Regulatory Proceedings — CPUC

PSCo 2011 Electric Rate Case  In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million.  The request was based on a 2012 forecast test year, a 10.75 percent ROE, an electric rate base of $5.4 billion and an equity ratio of 56 percent.

In April 2012, the CPUC approved a comprehensive multi-year settlement agreement, which covers 2012 through 2014.  Key terms of the agreement include the following:

· PSCo would implement an annual electric rate increase of $73 million in 2012.  The rate increase was effective on May 1, 2012.  In addition, PSCo will implement incremental electric rate increases of $16 million on Jan. 1, 2013 and $25 million on Jan. 1, 2014.  These rate increases are net of the shift of the costs from the purchased capacity cost adjustment and the transmission cost adjustment clauses to base rates.
· The settlement reflects an authorized ROE of 10 percent and an equity ratio of 56 percent.
· For 2012 through 2014, incremental property taxes in excess of $76.7 million (2010-2011 historic test year property taxes) will be deferred over a three-year period with the amortization effective the first year after the deferral.  To the extent that PSCo is successful in gaining the manufacturer's sales tax refund as a result of the sales tax lawsuit currently pending in the Colorado Supreme Court, PSCo will credit such refunds first against legal fees incurred to obtain the refund and then against the deferred property tax balances outstanding at the end of the 2014.
· The signing parties agreed to implement an earnings test, in which customers and shareholders will share weather normalized earnings above an ROE of 10 percent.  The sharing mechanism is as follows:
 
ROE
 
Shareholders
   
Customers
 
> 10.0% ≤ 10.2%
    40 %     60 %
> 10.2% 10.5%
    50       50  
> 10.5%
    -       100  
 
· PSCo agreed that it will not file for an electric rate increase that would take effect prior to Jan. 1, 2015, provided that net revenue requirements increase or decrease in excess of $10 million caused by changes in tax law, government mandates, or natural disasters may be deferred or recovered through a modified rate adjustment.  In the event normalized base revenues in either 2012 or 2013 are 2.0 percent below 2011 actual levels adjusted to reflect the rate increases allowed for 2012 and 2013, PSCo has the right to an additional rate adjustment in the next year for 50 percent of the shortfall.  The parties acknowledged that PSCo may file an electric rate increase as early as May 1, 2014, so long as no rate increase takes effect on either an interim or permanent basis prior to Jan. 1, 2015.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing — In May 2011, the CPUC determined that margin sharing on stand‑alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014.  The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers' share of the margins to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance.  In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

In March 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo.  Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo.  The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance.  In March 2012, PSCo credited approximately $28.7 million against the RESA regulatory asset balance.  PSCo has continued to credit the customer share of REC margins to the RESA regulatory asset balance each month.  As of Sept. 30, 2012, PSCo has credited $41.2 million.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and to review evidence regarding actual deliveries in relatively more complex markets such as California.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

PSCo Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a historic test year formula rate to a forecast transmission formula rate and to establish formula ancillary services rates.  PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up.  The request would increase PSCo's wholesale transmission and ancillary services revenue by approximately $2.0 million annually.  Various transmission customers taking service under the tariff protested the filing.  In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to Nov. 17, 2012, subject to refund, and setting the case for settlement judge or hearing procedures.  PSCo has been engaged in discovery and initial settlement discussions with the intervenors and the FERC Staff.

Separately, several wholesale customers filed a complaint with the FERC in June 2012 seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012.  If implemented, the ROE reduction would reduce PSCo transmission and ancillary rate revenues by approximately $1.8 million annually.  On Oct. 5, 2012, the FERC issued an order accepting the complaint, consolidating the complaint with the April 2012 formula rate change filing, establishing a refund effective date of July 1, 2012, and setting the complaint for settlement judge and hearing procedures.  The settlement discussions are now expected to seek to resolve both dockets.  If PSCo, the FERC and intervenors do not reach settlement, the dockets would proceed to a contested hearing.

SPS

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

SPS Wholesale Rate Complaint — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a rate complaint with the FERC alleging that SPS' rates for wholesale service were excessive.  Golden Spread alleges that the base ROE currently charged to them through the SPS production formula rate, of 10.25 percent, and the SPS transmission base formula rate, ROE of 10.77 percent, is unjust and unreasonable.  Golden Spread alleges that the appropriate base ROE is 9.15 percent, or an annual difference of approximately $3.3 million.  An additional 50 basis point incentive is added to the base ROE for the transmission formula rate for SPS' participation in the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO).  Golden Spread is not contesting this transmission incentive.  The FERC has taken no action on this complaint.

6.
Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.'s Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference.  The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy's financial position.

Purchased Power Agreements

Under certain purchased power agreements, NSP‑Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase.  These specific purchased power agreements create a variable interest in the associated independent power producing entity.

Xcel Energy had approximately 3,324 megawatts (MW) and 3,773 MW of capacity under long‑term purchased power agreements as of Sept. 30, 2012 and Dec. 31, 2011, respectively, with entities that have been determined to be variable interest entities.  Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities' economic performance.  These agreements have expiration dates through the year 2033.

Guarantees and Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions.  The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries.  As a result, Xcel Energy Inc.'s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities.  As of Sept. 30, 2012 and Dec. 31, 2011, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.
The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy Inc.:
 
(Millions of Dollars)
 
Sept. 30, 2012
   
Dec. 31, 2011
 
Guarantees issued and outstanding
  $ 68.4     $ 67.5  
Current exposure under these guarantees
    17.9       18.0  
Bonds with indemnity protection
    30.0       31.2  
 
Indemnification Agreements

In connection with the acquisition of the 201 MW Nobles wind project in 2011, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  NSP-Minnesota's indemnification obligation is capped at $20 million, in the aggregate, at Sept. 30, 2012 and Dec. 31, 2011.  The indemnification obligation expires in March 2013.  NSP-Minnesota has not recorded a liability related to this indemnity at Sept. 30, 2012 or Dec. 31, 2011.

In connection with the acquisition of 900 MW of natural gas-fired generation from subsidiaries of Calpine Development Holdings Inc. in 2010, PSCo agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  The aggregate liability for PSCo pursuant to these indemnities is not subject to a capped dollar amount.  The indemnification obligation expires in December 2012.  PSCo has not recorded a liability related to this indemnity at Sept. 30, 2012 or Dec. 31, 2011.

Xcel Energy Inc. and its subsidiaries provide other indemnifications through contracts entered into in the normal course of business.  These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including due organization, transaction authorization and income tax matters with respect to assets sold.  Xcel Energy Inc.'s and its subsidiaries' obligations under these agreements may be limited in terms of time and amount.  The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated.

Environmental Contingencies

MGP Sites

Ashland MGP Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis.  The Ashland site includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior's Chequamegon Bay adjoining the park (the Sediments).

The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in September 2010, which documents the remedy that the EPA has selected for the cleanup of the Ashland site.  In April 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site.  The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation.  As a result of those settlement negotiations, the EPA agreed to segment the Ashland site into separate areas.  The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments.

In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources (WDNR), the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin.  This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area.  Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site.  The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million.  The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments.  As part of the settlement, NSP-Wisconsin will convey approximately 1,390 acres of land to the State of Wisconsin and tribes so that they may manage and preserve the natural resource benefits associated with those properties.  Assuming final access agreements are obtained, fieldwork at the Ashland site will commence as early as November 2012.
Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing.  The EPA's ROD for the Ashland site estimates that the cost of the preferred remediation related to the Sediments is between $63.3 million and $77.1 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site.  Answers to the NSP-Wisconsin complaint were due from other parties on Oct. 22, 2012.  The U.S. District Court has not yet issued a scheduling order for litigation.

At each of Sept. 30, 2012 and Dec. 31, 2011, NSP-Wisconsin had recorded a liability of $104.3 million for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $26.6 million was considered a current liability.  NSP-Wisconsin's potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change until after negotiations or litigation with the EPA and other PRPs are fully resolved.  NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site.  Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include, but are not limited to, the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, the contributions, if any, by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred, as a regulatory asset, the estimated site remediation costs less insurance and rate recoveries, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.  The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities.  External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process.  Under an existing PSCW policy with respect to recovery of remediation costs for MGPs, utilities have recovered remediation costs in natural gas rates, amortized over a four- to six-year period.  The PSCW has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.  In a recent rate case decision, the PSCW recognized the potential magnitude of the future liability for, and circumstances of, the cleanup at the Ashland site and indicated it may consider alternatives to its established MGP site cleanup cost accounting and cost recovery guidelines for the Ashland site in a future proceeding.  Pursuant to the PSCW decision, NSP-Wisconsin proposed an alternative long-term plan to recover costs related to the Ashland site in the rate case application filed on June 1, 2012.  As compared to the current cost recovery policy, NSP-Wisconsin's alternative proposal mitigates the rate impact to natural gas customers and allows for partial recovery of carrying costs.  NSP-Wisconsin expects a decision on the alternative cost recovery plan by the end of 2012.

Other MGP Sites Xcel Energy is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited.  Xcel Energy has identified eight sites where former MGP activities have or may have resulted in actual site contamination and are under current investigation and/or remediation.  At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation that may be conducted.  Xcel Energy anticipates that the majority of the remediation at these sites will continue through at least 2014.  For these sites, Xcel Energy had accrued $4.0 million and $3.9 million at Sept. 30, 2012 and Dec. 31, 2011, respectively.  There may be insurance recovery and/or recovery from other PRPs that will offset any costs actually incurred at these sites.  Xcel Energy anticipates that any amounts actually spent will be fully recovered from customers.

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the EPA proposed a GHG NSPS for newly constructed power plants.  The proposal requires that carbon dioxide (CO2) emission rates be equal to those achieved by a natural gas combined-cycle plant, even if the plant is coal-fired.  The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and that installation of control equipment on existing plants would not constitute a "modification" to those plants under the NSPS program.  Xcel Energy submitted comments on the proposed GHG NSPS in June 2012.  It is not possible to evaluate the impact of this regulation until its final requirements are known.

The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA).  It is not known when the EPA will propose new standards for existing sources.

New Mexico GHG Regulations — In 2010, the New Mexico Environmental Improvement Board (EIB) adopted two regulations to limit GHG emissions, including CO2 emissions from power plants and other industrial sources.  The EIB repealed both regulations in the first quarter of 2012. Western Resource Advocates and New Energy Economy, Inc. have since filed appeals with the New Mexico Court of Appeals to challenge each of the EIB's decisions to repeal the two GHG rules.
Cross-State Air Pollution Rule (CSAPR) In July 2011, the EPA issued the CSAPR intended to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the United States.  For Xcel Energy, the rule, if implemented, would have applied in Minnesota, Wisconsin and Texas.  The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and specifically would have required plants in Texas to reduce their SO2 and annual NOx emissions.  The rule also would have created an emissions trading program.

In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA.  The D.C. Circuit also stated that the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement.  In October 2012, the EPA, as well as state and local governments and environmental advocates, petitioned the D.C. Circuit to rehear the CSAPR appeal.  It is not yet known whether the court will grant rehearing of the case, or how the EPA might approach a replacement rule.  Therefore, it is not known what requirements may be imposed in the future.

If the EPA continues administering the CAIR while the CSAPR is pending, Xcel Energy expects to comply with the CAIR primarily through the purchase of emissions allowances. Based on current CAIR allowance prices, the cost of CAIR compliance is not expected to have a material impact on results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective April 2012.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date.  Xcel Energy expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. Xcel Energy believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States. Xcel Energy generating facilities in several states are subject to BART requirements.  Individual states were required to identify the facilities located in their states that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities.

PSCo
In 2006, the Colorado Air Quality Control Commission (CAQCC) promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal.  In January 2011, the CAQCC approved a revised regional haze BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements.  The Colorado legislature enacted a statute approving the SIP (the Colorado SIP), which was signed into law in 2011.  Subsequently, the Colorado Mining Association (CMA) challenged the Colorado SIP in a Colorado District Court.  In June 2012, the CMA's appeal was dismissed due to the legislative approval given to the Colorado SIP after the CAQCC approval.  The CMA appealed this decision to the Colorado Court of Appeals in August 2012.

In September 2012, the EPA granted final approval of the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements.  The emission controls are expected to be installed between 2014 and 2017.  Projected costs for emission controls at the Hayden and Pawnee plants are $334.2 million.  PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA emission reduction plan recovery mechanisms or other regulatory mechanisms.

In March 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park.  The following PSCo plants are named in the petition:  Cherokee, Hayden, Pawnee and Valmont.  The groups allege that the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park.  It is not known when the DOI will rule on the petition.

NSP-Minnesota
In December 2009, the Minnesota Pollution Control Agency (MPCA) approved the regional haze SIP for Minnesota (the Minnesota SIP), which has been submitted to the EPA for approval.  The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks.  The MPCA concluded Selective Catalytic Reduction (SCR) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA's BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2.  The combustion controls have been installed on Sherco Units 1 and 2, and the scrubber upgrades are scheduled to be installed by 2015.  At this time, the estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $20 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2.  Xcel Energy anticipates that all costs associated with BART compliance will be fully recoverable through regulatory recovery mechanisms.

In June 2011, the EPA provided comments to the MPCA on the Minnesota SIP, stating that the EPA's preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2.  The MPCA has since proposed that the CSAPR should be considered BART for EGUs and the EPA proposed that states be allowed to find that CSAPR compliance meets BART requirements for EGUs, and specifically that Minnesota's proposal to find the CSAPR to meet BART requirements should be approved, if finalized by the state.

In April 2012, the MPCA approved a supplement to the 2009 regional haze Minnesota SIP finding that the CSAPR meets BART for EGUs in Minnesota.  The supplement also made a source-specific BART determination for Sherco Units 1 and 2 that requires installation of the combustion controls for NOx and scrubber upgrades for SO2 by January 2015.  In May 2012, the EPA adopted a final rule that allows states to determine whether CSAPR compliance meets BART requirements.  In June 2012, the EPA issued its final approval of the Minnesota SIP for EGUs.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA's approval of the Minnesota SIP to the U.S. Court of Appeals for the Eight Circuit.  NSP-Minnesota has petitioned to intervene in the case.  It is not yet known how the D.C. Circuit's reversal of the CSAPR may impact the EPA's approval of the Minnesota SIP.

In addition to the regional haze rules identified in the EPA's visibility program, and addressed in the Minnesota SIP discussed above, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program.  In October 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota's Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.  In May 2012, a notice of intent to sue was filed with the EPA by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club.  The notice advised the EPA of the parties' intent to sue the EPA in 180 days to attempt to require the EPA to determine BART for the Sherco Units 1 and 2 under the RAVI program.  It is not yet known how the EPA intends to respond to this notice.

SPS
Harrington Units 1 and 2 are potentially subject to BART.  Texas has developed a regional haze SIP (the Texas SIP) that finds the CAIR equal to BART for EGUs, and as a result, no additional controls for these units beyond CAIR compliance would be required.  In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs.  It is not yet known how the D.C. Circuit's reversal of the CSAPR may impact the EPA's approval of the Texas SIP.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In June 2012, the EPA proposed to lower the primary (health-based) NAAQS for annual average fine PM and to retain the current daily standard for fine PM.  In areas in which Xcel Energy operates power plants, current monitored air concentrations are below the range of the proposed annual primary standard.  The EPA also proposed to add a secondary (welfare-based) NAAQS to improve visibility, primarily in urban areas.  Xcel Energy expects the proposed visibility standard would likely be met where Xcel Energy operates power plants based on currently available information.  A final rule is expected in December 2012 and the EPA is expected to designate non-compliant locations by December 2014.  If such areas are identified, states would then study the sources of the nonattainment and make emission reduction plans to attain the standards.  It is not possible to evaluate the impact of this regulation further until its final requirements are known.

Legal Contingencies

Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business.  The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation.  Management is sometimes unable to estimate an amount or range of a reasonably possible loss, in certain situations, including but not limited to where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.  In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.  For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy's financial statements.

Environmental Litigation

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in the U.S. District Court for the Northern District of California against Xcel Energy and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants' emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In October 2012 the Ninth Circuit affirmed the U.S. District Court's dismissal.  On Oct. 14, 2012, plaintiffs filed a petition for rehearing en banc.  It is uncertain when the Ninth Circuit will respond to this petition.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs' alleged relocation is estimated to cost between $95 million to $400 million.  Although Xcel Energy believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in the U.S. District Court in Mississippi.  The complaint alleges defendants' CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.  Although Xcel Energy believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota.  NSP-Minnesota's decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact.  NSP-Minnesota also terminated the agreements due to enXco's nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011.  NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011.  In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements and enXco also filed a separate lawsuit in the same court seeking, among other things, approximately $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco's lawsuit is without merit and filed a motion to dismiss.  In September 2011, the U.S. District Court denied the motion to dismiss.  On Oct. 22, 2012, NSP-Minnesota filed a motion for summary judgment.  If the U.S. District Court denies NSP-Minnesota's motion, trial in this matter is expected to occur during the first or second quarter of 2013.  Although Xcel Energy believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Exelon Wind (formerly John Deere Wind (JD Wind)) Complaint  Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS' payments for energy produced from the Exelon Wind subsidiaries' projects.  There are two main areas of dispute.  First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS' forecasted avoided cost as determined in 2005 through 2007.  Although SPS has refused to accept Exelon Wind's LEOs, SPS has paid Exelon Wind for energy under SPS' Public Utility Commission of Texas (PUCT) Qualifying Facilities (QF) Tariff.  Second, Exelon Wind has raised various challenges to SPS' PUCT QF Tariff, which became effective in August 2010. The state and federal lawsuits are in various stages of litigation.  SPS believes the likelihood of loss in these lawsuits is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms.  No accrual has been recorded for this matter.

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001.  PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings.  In September 2001, the presiding administrative law judge (ALJ) concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices.  Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered.  Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million.  In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings.  Certain purchasers filed appeals of the FERC's orders in this proceeding with the U.S. Court of Appeals for the Ninth Circuit.

In an order issued in August 2007, the U.S. Court of Appeals for the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.  The U.S. Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC has issued an order on remand establishing principles for the review proceeding in October 2011.  In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers and has expanded the period for which it seeks refunds to May 2000 through June 2001, during which PSCo had sales to the City of Seattle of approximately $50 million.  The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets.  Preliminary calculations of the City of Seattle's claim for refunds from PSCo are approximately $28 million not including interest.  PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  In making this assessment, PSCo considered two factors:  PSCo's view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and that the FERC's standard will likely be challenged on appeal to the U.S. Court of Appeals for the Ninth Circuit.  PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions.  In addition, if a loss were sustained, PSCo would attempt to recover those losses from other PRPs.  No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP‑Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy's (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP‑Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004.  In September 2007, the court awarded NSP‑Minnesota $116.5 million in damages.  In August 2007, NSP‑Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million.  The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation.  NSP-Minnesota received the initial $100 million payment in August 2011 and the second installment of $18.6 million in March 2012, which were subsequently refunded to customers, except for approved reductions such as legal costs and customer refund amounts still in process at Sept. 30, 2012.  Also pursuant to this settlement agreement, on Aug. 8, 2012, the DOE approved reimbursement in the amount of approximately $20.7 million for costs incurred in 2011 for storing spent nuclear fuel.  NSP-Minnesota recognized the expected payment of $20.7 million as a receivable as of Sept. 30, 2012, which was subsequently received in October 2012.  NSP-Minnesota and NSP-Wisconsin expect to make the appropriate regulatory filings within the prescribed deadlines for the various jurisdictions.
7.
Borrowings and Other Financing Instruments

Money Pool  Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries.  NSP-Wisconsin does not participate in the money pool.  Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.  The money pool balances are eliminated upon consolidation.

Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities.  Commercial paper outstanding for Xcel Energy was as follows:
 
(Millions of Dollars, Except Interest Rates)
 
Three Months Ended
Sept. 30, 2012
   
Twelve Months Ended
Dec. 31, 2011
 
Borrowing limit
 
$
                       2,450
   
$
                       2,450
 
Amount outstanding at period end
 
 
                          304
     
                          219
 
Average amount outstanding
 
 
                          433
     
                          430
 
Maximum amount outstanding
 
 
                          630
     
                          824
 
Weighted average interest rate, computed on a daily basis
 
 
                         0.34
%
 
                         0.36
%
Weighted average interest rate at period end
 
 
                         0.34
     
                         0.40
 
 
Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Sept. 30, 2012 and Dec. 31, 2011, there were $12.7 million of letters of credit outstanding under the credit facilities.  There were no letters of credit outstanding that were not issued under the credit facilities at Sept. 30, 2012.  There were $1.1 million of letters of credit outstanding at Dec. 31, 2011 that were not issued under the credit facilities.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities.  The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At Sept. 30, 2012, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
 
(Millions of Dollars)
 
Credit Facility
   
Drawn (a)
   
Available
 
Xcel Energy Inc.
  $ 800.0     $ 205.0     $ 595.0  
PSCo
    700.0       4.0       696.0  
NSP-Minnesota
    500.0       8.7       491.3  
SPS
    300.0       -       300.0  
NSP-Wisconsin
    150.0       99.0       51.0  
Total
  $ 2,450.0     $ 316.7     $ 2,133.3  
 
(a)
Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities.  Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at Sept. 30, 2012 and Dec. 31, 2011.

Amended Credit Agreements — In July 2012, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. entered into amended five-year credit agreements with a syndicate of banks, replacing their previous four-year credit agreements.  The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with an improvement in pricing and an extension of maturity from March 2015 to July 2017.  The Eurodollar borrowing margins on these lines of credit were reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings.  The commitment fees, calculated on the unused portion of the lines of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.
 
21

 
Xcel Energy Inc. and its utility subsidiaries, other than NSP-Wisconsin, have the right to request an extension of the revolving termination date for two additional one-year periods, and NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period, each subject to majority bank group approval.

Long-Term Borrowings and Other Financing Instruments

SPS — In June 2012, SPS issued an additional $100 million of its 4.50 percent first mortgage bonds due Aug. 15, 2041.  Including the $200 million of this series previously issued in August 2011, total principal outstanding for this series is $300 million.

NSP-Minnesota In August 2012, NSP-Minnesota issued $300 million of 2.15 percent first mortgage bonds due Aug. 15, 2022, as well as $500 million of 3.40 percent first mortgage bonds due Aug. 15, 2042.  NSP-Minnesota used a portion of the net proceeds from the first mortgage bonds to repay $450 million of 8.0 percent first mortgage bonds maturing on Aug. 28, 2012 and to redeem the following series of pollution control bonds:  $100 million of 8.50 percent bonds due Sept. 1, 2019, $27.9 million of 8.50 percent bonds due March 1, 2019 and $69 million of 8.50 percent bonds due April 1, 2030.

PSCo In September 2012, PSCo issued $300 million of 2.25 percent first mortgage bonds due Sept. 15, 2022, as well as $500 million of 3.60 percent first mortgage bonds due Sept. 15, 2042.  PSCo used a portion of the net proceeds from the first mortgage bonds to redeem $600 million of 7.875 percent first mortgage bonds maturing on Oct. 1, 2012, and intends to redeem $48.75 million of 5.10 percent bonds due Jan. 1, 2019, for which a notice of full optional redemption was issued to bondholders on Oct. 1, 2012.

NSP-Wisconsin — In October 2012, NSP-Wisconsin issued $100 million of 3.70 percent first mortgage bonds due Oct. 1, 2042.

Preferred Stock — Xcel Energy Inc. has authorized 7,000,000 shares of preferred stock with a $100 par value.  At Sept. 30, 2012 and Dec. 31, 2011, there were no shares of preferred stock outstanding.

In 2011, Xcel Energy Inc. redeemed all series of its preferred stock at an aggregate purchase price of $108 million, plus accrued dividends.  The redemption premium of $3.3 million and accrued dividends are reflected as reductions of Xcel Energy's earnings available to common shareholders in the consolidated statements of income for the three and nine months ended Sept. 30, 2011.

8.
Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value.  A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.  The three levels in the hierarchy are as follows:

Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.

Level 3 Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Investments in equity securities and other funds Equity securities are valued using quoted prices in active markets.  The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value.  The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice.  Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion.  Unscheduled distributions from real estate investments may be redeemed with proper notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.  Based on Xcel Energy's evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities  Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset‑backed and mortgage‑backed securities, for which the third party service may also consider additional, more subjective inputs.  Since the impact of the use of these less observable inputs can be significant to the valuation of asset‑backed and mortgage‑backed securities, fair value measurements for these instruments have been assigned a Level 3.  Inputs that may be considered in the valuation of asset-backed and mortgage-backed securities in conjunction with pricing of similar securities in active markets include the use of risk-based discounting and estimated prepayments in a discounted cash flow model.  When these additional inputs and models are utilized, increases in the risk-adjusted discount rates and decreases in the assumed principal prepayment rates each have the impact of reducing reported fair values for these instruments.

Interest rate derivatives The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include financial transmission rights (FTRs) purchased from Midwest Independent Transmission System Operator, Inc. (MISO). FTRs purchased from MISO are financial instruments that entitle the holder to one year of monthly revenues or charges based on transmission congestion across a given transmission path.  The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints.  In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path.  Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.  NSP-Minnesota's valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease.  Given the limited observability of management's forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.  Monthly FTR settlements are included in the fuel clause adjustment, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability.  Given this regulatory treatment and the limited magnitude of NSP-Minnesota's FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

Xcel Energy continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty's ability to perform on the transactions set forth in the contracts.  Given this assessment, as well as an assessment of the impact of Xcel Energy's own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

Non-Derivative Instruments Fair Value Measurements

The Nuclear Regulatory Commission (NRC) requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants.  The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale.  NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs.  Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.  Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $146.3 million and $79.8 million at Sept. 30, 2012 and Dec. 31, 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $49.4 million and $87.5 million at Sept. 30, 2012 and Dec. 31, 2011, respectively.

The following tables present the cost and fair value of Xcel Energy's non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Sept. 30, 2012 and Dec. 31, 2011:
 
 
 
Sept. 30, 2012
 
 
 
 
   
Fair Value
   
 
 
 
 
 
   
 
   
 
   
 
   
 
 
(Thousands of Dollars)
 
Cost
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Nuclear decommissioning fund (a)
 
 
   
 
   
 
   
 
   
 
 
Cash equivalents
  $ 28,835     $ 16,074     $ 12,761     $ -     $ 28,835  
Commingled funds
    375,958       -       398,592       -       398,592  
International equity funds
    65,713       -       66,518       -       66,518  
Private equity investments
    20,662       -       -       24,073       24,073  
Real estate
    30,252       -       -       35,233       35,233  
Debt securities:
                                       
Government securities
    126,381       -       127,124       -       127,124  
U.S. corporate bonds
    153,283       -       164,501       -       164,501  
International corporate bonds
    24,952       -       26,442       -       26,442  
Municipal bonds
    61,683       -       66,800       -       66,800  
Asset-backed securities
    4,971       -       -       4,995       4,995  
Mortgage-backed securities
    60,628       -       -       63,957       63,957  
Equity securities:
                                       
Common stock
    402,769       445,891       -       -       445,891  
Total
  $ 1,356,087     $ 461,965     $ 862,738     $ 128,258     $ 1,452,961  
 
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.4 million of equity investments in unconsolidated subsidiaries and $34.0 million of miscellaneous investments.
 
24

 
 
 
Dec. 31, 2011
 
 
 
 
   
Fair Value
   
 
 
 
 
 
   
 
   
 
   
 
   
 
 
(Thousands of Dollars)
 
Cost
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Nuclear decommissioning fund (a)
 
 
   
 
   
 
   
 
   
 
 
Cash equivalents
  $ 26,123     $ 7,103     $ 19,020     $ -     $ 26,123  
Commingled funds
    320,798       -       311,105       -       311,105  
International equity funds
    63,781       -       58,508       -       58,508  
Private equity investments
    9,203       -       -       9,203       9,203  
Real estate
    24,768       -       -       26,395       26,395  
Debt securities:
                                       
Government securities
    116,490       -       117,256       -       117,256  
U.S. corporate bonds
    187,083       -       193,516       -       193,516  
International corporate bonds
    35,198       -       35,804       -       35,804  
Municipal bonds
    60,469       -       64,731       -       64,731  
Asset-backed securities
    16,516       -       -       16,501       16,501  
Mortgage-backed securities
    75,627       -       -       78,664       78,664  
Equity securities:
                                       
Common stock
    408,122       398,625       -       -       398,625  
Total
  $ 1,344,178     $ 405,728     $ 799,940     $ 130,763     $ 1,336,431  
 
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $92.7 million of equity investments in unconsolidated subsidiaries and $34.3 million of miscellaneous investments.

The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2012 and 2011:
 
(Thousands of Dollars)  
July 1, 2012
   
Purchases
   
Settlements
   
Gains Recognized
as Regulatory
Liabilities
   
Sept. 30, 2012
 
Private equity investments
  $ 23,303     $ -     $ (1,931 )   $ 2,701     $ 24,073  
Real estate
    32,721       2,882       (1,165 )     795       35,233  
Asset-backed securities
    7,068       -       (2,085 )     12       4,995  
Mortgage-backed securities
    66,321       16,782       (19,681 )     535       63,957  
Total
  $ 129,413     $ 19,664     $ (24,862 )   $ 4,043     $ 128,258  
 
 
(Thousands of Dollars)
 
July 1, 2011
   
Purchases
   
Settlements
   
Losses
Recognized as
Regulatory Assets
   
Sept. 30, 2011
 
Asset-backed securities
  $ 21,004     $ 9,496     $ (19,443 )   $ (811 )   $ 10,246  
Mortgage-backed securities
    62,271       1,972       (8,978 )     (450 )     54,815  
Total
  $ 83,275     $ 11,468     $ (28,421 )   $ (1,261 )   $ 65,061  

 
(Thousands of Dollars)
 
Jan. 1, 2012
   
Purchases
   
Settlements
   
Gains Recognized
as Regulatory
Liabilities
   
Sept. 30, 2012
 
Private equity investments
  $ 9,203     $ 13,390     $ (1,931 )   $ 3,411     $ 24,073  
Real estate
    26,395       6,789       (2,931 )     4,980       35,233  
Asset-backed securities
    16,501       -       (11,544 )     38       4,995  
Mortgage-backed securities
    78,664       31,100       (46,099 )     292       63,957  
Total
  $ 130,763     $ 51,279     $ (62,505 )   $ 8,721     $ 128,258  
 
25

 
 
(Thousands of Dollars)
 
Jan. 1, 2011
   
Purchases
   
Settlements
   
Losses
Recognized as
Regulatory Assets
   
Sept. 30, 2011
 
Asset-backed securities
  $ 33,174     $ 10,252     $ (32,559 )   $ (621 )   $ 10,246  
Mortgage-backed securities
    72,589       101,037       (117,435 )     (1,376 )     54,815  
Total
  $ 105,763     $ 111,289     $ (149,994 )   $ (1,997 )   $ 65,061  
 
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at Sept. 30, 2012:
 
 
 
Final Contractual Maturity
 
 
(Thousands of Dollars)
 
Due in 1 Year
or Less
   
Due in 1 to 5
Years
   
Due in 5 to 10
Years
   
Due after 10
Years
   
Total
 
Government securities
  $ 104,587     $ 7,074     $ 1,848     $ 13,615     $ 127,124  
U.S. corporate bonds
    -       37,372       111,801       15,328       164,501  
International corporate bonds
    -       8,108       16,657       1,677       26,442  
Municipal bonds
    -       -       31,417       35,383       66,800  
Asset-backed securities
    -       4,237       758       -       4,995  
Mortgage-backed securities
    -       -       824       63,133       63,957  
Debt securities
  $ 104,587     $ 56,791     $ 163,305     $ 129,136     $ 453,819  
 
Derivative Instruments Fair Value Measurements

Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Sept. 30, 2012, accumulated other comprehensive losses related to interest rate derivatives included $2.7 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

In conjunction with the NSP-Minnesota debt issuance in August 2012, NSP-Minnesota settled interest rate hedging instruments with a notional amount of $225 million during the three months ended Sept. 30, 2012 with cash payments of $45.0 million.  In conjunction with the PSCo debt issuance in September 2012, PSCo settled interest rate hedging instruments with a notional amount of $250 million during the three months ended Sept. 30, 2012 with cash payments of $44.7 million.  These losses are classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and will be reclassified to earnings over the term of the hedged interest payments.  See Note 7 for further discussion of long-term borrowings.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.'s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy‑related instruments.  Xcel Energy's risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes.  This could include the purchase or sale of energy or energy‑related products, natural gas to generate electric energy, natural gas for resale and vehicle fuel.

At Sept. 30, 2012, Xcel Energy had various vehicle fuel related contracts designated as cash flow hedges extending through December 2016.  Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non‑trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2012 and 2011.

At Sept. 30, 2012, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.
 
26

 
Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers.  Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin‑sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2012 and Dec. 31, 2011:
 
(Amounts in Thousands) (a)(b)
 
Sept. 30, 2012
   
Dec. 31, 2011
 
Megawatt hours (MWh) of electricity
    54,374       38,822  
MMBtu of natural gas
    8,238       40,736  
Gallons of vehicle fuel
    732       600  
 
(a)
Amounts are not reflective of net positions in the underlying commodities.
(b)
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy's accumulated other comprehensive loss, included in the consolidated statement of common stockholders' equity and in the consolidated statement of comprehensive income, is detailed in the following table:
 
 
 
Three Months Ended Sept. 30
 
(Thousands of Dollars)
 
2012
   
2011
 
Accumulated other comprehensive loss related to cash flow hedges at July 1
  $ (55,710 )   $ (7,582 )
After-tax net unrealized losses related to derivatives accounted for as hedges
     (8,853 )      (30,947 )
After-tax net realized losses on derivative transactions reclassified into earnings
     393        159  
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30
  $ (64,170 )   $ (38,370 )
   
 
 
                 
 
 
Nine Months Ended Sept. 30
 
(Thousands of Dollars)
    2012       2011  
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
  $ (45,738 )   $ (8,094 )
After-tax net unrealized losses related to derivatives accounted for as hedges
     (19,188 )      (30,740 )
After-tax net realized losses on derivative transactions reclassified into earnings
     756        464  
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30
  $ (64,170 )   $ (38,370 )
 
The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2012 and Sept. 30, 2011, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
 
     
Three Months Ended Sept. 30, 2012 
   
     
Fair Value Gains (Losses) 
     
Pre-Tax (Gains) Losses Reclassified 
           
     
Recognized During the Period in: 
     
into Income During the Period from: 
           
     
Accumulated 
             
Accumulated 
             
Pre-Tax Gains 
   
     
Other 
     
Regulatory 
     
Other 
     
Regulatory 
     
Recognized 
   
     
Comprehensive 
     
(Assets) and 
     
Comprehensive 
     
Assets and 
     
During the Period 
   
(Thousands of Dollars)    
Loss 
     
Liabilities 
     
Loss 
     
(Liabilities) 
     
in Income 
   
Derivatives designated as cash flow hedges                                          
Interest rate
  $ (14,923 )   $ -     $ 733  
(a)
$ -  
 
$ -  
 
Vehicle fuel and other commodity
    157       -       (44 )
(e)
-
 
-
 
Total
  $ (14,766 )   $ -     $ 689  
 
$ -  
 
$ -  
 
                         
 
     
 
     
 
Other derivative instruments
                       
 
     
 
     
 
Trading commodity
  $ -     $ -     $ -  
 
$ -  
 
$ 7,651  
(b)
Electric commodity
    -       3,923       -  
 
  (11,931 )
(c)
  -  
 
Natural gas commodity
    -       1,193       -  
 
  -  
 
  -  
 
Total
  $ -     $ 5,116     $ -  
 
$ (11,931 )
 
$ 7,651  
 

    Nine Months Ended Sept. 30, 2012    
   
Fair Value Gains (Losses)
   
Pre-Tax (Gains) Losses Reclassified
         
   
Recognized During the Period in:
   
into Income During the Period from:
         
    Accumulated           Accumulated           Pre-Tax Gains    
    Other     Regulatory     Other     Regulatory     (Losses) Recognized    
    Comprehensive     (Assets) and     Comprehensive     Assets and     During the Period    
(Thousands of Dollars)  
Loss
   
Liabilities
   
Loss
   
(Liabilities)
   
in Income
   
Derivatives designated as cash flow hedges                                          
Interest rate
  $ (31,914 )   $ -     $ 1,511  
(a)