XNYS:XEL Xcel Energy Inc Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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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 March 31, 2012
or
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File Number: 1-3034
 
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 o
Non-accelerated filer o (Do not check if smaller reporting company)
 
Smaller reporting company o

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 April 19, 2012
Common Stock, $2.50 par value
 
486,943,183 shares
 


 
 

 
 

PART I
   
3
 
Item 1 —
 
3
     
3
      4
              CONSOLIDATED STATEMENTS OF CASH FLOWS 5
              CONSOLIDATED BALANCE SHEETS 6
              CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY 7
              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8
 
Item 2 —
 
30
 
Item 3 —
 
44
 
Item 4 —
 
44
PART II
   
44
 
Item 1 —
 
44
 
Item 1A —
 
45
 
Item 2 —
 
45
 
Item 4 —
 
45
 
Item 5 —
 
45
 
Item 6 —
 
46
     
47
     
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).
 
 
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 March 31
 
   
2012
   
2011
 
Operating revenues
           
Electric
  $ 1,936,782     $ 2,029,972  
Natural gas
    621,035       765,349  
Other
    20,262       21,219  
Total operating revenues
    2,578,079       2,816,540  
                 
Operating expenses
               
Electric fuel and purchased power
    863,980       931,828  
Cost of natural gas sold and transported
    417,946       543,376  
Cost of sales — other
    7,304       8,055  
Operating and maintenance expenses
    510,684       510,027  
Conservation and demand side management program expenses
    63,707       75,298  
Depreciation and amortization
    228,672       224,723  
Taxes (other than income taxes)
    105,624       96,570  
Total operating expenses
    2,197,917       2,389,877  
                 
Operating income
    380,162       426,663  
                 
Other income, net
    3,737       4,766  
Equity earnings of unconsolidated subsidiaries
    7,158       7,713  
Allowance for funds used during construction — equity
    13,450       13,244  
                 
Interest charges and financing costs
               
Interest charges — includes other financing costs of $6,080 and $5,260, respectively
    151,830       144,354  
Allowance for funds used during construction — debt
    (6,607 )     (7,436 )
Total interest charges and financing costs
    145,223       136,918  
                 
Income from continuing operations before income taxes
    259,284       315,468  
Income taxes
    75,515       112,001  
Income from continuing operations
    183,769       203,467  
Income from discontinued operations, net of tax
    124       102  
Net income
    183,893       203,569  
Dividend requirements on preferred stock
    -       1,060  
Earnings available to common shareholders
  $ 183,893     $ 202,509  
                 
Weighted average common shares outstanding:
               
Basic
    487,360       483,641  
Diluted
    487,995       484,301  
                 
Earnings per average common share:
               
Basic
  $ 0.38     $ 0.42  
Diluted
    0.38       0.42  
                 
Cash dividends declared per common share
  $ 0.26     $ 0.25  

See Notes to Consolidated Financial Statements
 
 
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in thousands)
 
   
Three Months Ended March 31
 
   
2012
   
2011
 
             
Net income
  $ 183,893     $ 203,569  
                 
Other comprehensive income
               
                 
Pension and retiree medical benefits:
               
Amortization of losses included in net periodic benefit cost, net of tax of $622 and $551, respectively
    895       794  
                 
Derivative instruments:
               
Net fair value increase, net of tax of $16,491 and $145, respectively
    25,392       244  
Reclassification of losses to net income, net of tax of $156 and $147, respectively
    181       158  
      25,573       402  
Marketable securities:
               
Net fair value increase, net of tax of $36 and $34, respectively
    52       50  
Other comprehensive income
    26,520       1,246  
Comprehensive income
  $ 210,413     $ 204,815  

See Notes to Consolidated Financial Statements

 
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
   
Three Months Ended March 31
 
   
2012
   
2011
 
Operating activities
           
Net income
  $ 183,893     $ 203,569  
Remove income from discontinued operations
    (124 )     (102 )
Adjustments to reconcile net income to cash provided by operating activities:
               
Depreciation and amortization
    233,097       229,217  
Conservation and demand side management program amortization
    1,882       3,024  
Nuclear fuel amortization
    26,000       25,551  
Deferred income taxes
    167,426       114,852  
Amortization of investment tax credits
    (1,552 )     (1,580 )
Allowance for equity funds used during construction
    (13,450 )     (13,244 )
Equity earnings of unconsolidated subsidiaries
    (7,158 )     (7,713 )
Dividends from unconsolidated subsidiaries
    8,028       8,454  
Share-based compensation expense
    3,883       9,895  
Net derivative losses
    7,133       14,495  
Changes in operating assets and liabilities:
               
Accounts receivable
    (52,643 )     (46,947 )
Accrued unbilled revenues
    197,330       157,996  
Inventories
    143,873       118,595  
Other current assets
    (71,547 )     43,551  
Accounts payable
    (202,649 )     (72,424 )
Net regulatory assets and liabilities
    61,872       17,853  
Other current liabilities
    17,711       5,491  
Pension and other employee benefit obligations
    (180,030 )     (134,004 )
Change in other noncurrent assets
    (38,806 )     10,520  
Change in other noncurrent liabilities
    (6,686 )     (27,606 )
Net cash provided by operating activities
    477,483       659,443  
                 
Investing activities
               
Utility capital/construction expenditures
    (497,218 )     (540,339 )
Allowance for equity funds used during construction
    13,450       13,244  
Merricourt deposit
    -       (90,833 )
Purchase of investments in external decommissioning fund
    (213,618 )     (699,156 )
Proceeds from the sale of investments in external decommissioning fund
    213,618       699,156  
Investment in WYCO Development LLC
    (172 )     (901 )
Change in restricted cash
    86,232       26  
Other, net
    (1,304 )     (5,545 )
Net cash used in investing activities
    (399,012 )     (624,348 )
                 
Financing activities
               
Proceeds from short-term borrowings, net
    120,000       65,100  
Proceeds from issuance of long-term debt
    745       -  
Repayments of long-term debt, including reacquisition premiums
    (758 )     (551 )
Proceeds from issuance of common stock
    1,598       1,878  
Repurchase of common stock
    (18,529 )     -  
Purchase of common stock for settlement of equity awards
    (23,307 )     -  
Dividends paid
    (119,162 )     (115,621 )
Net cash used in financing activities
    (39,413 )     (49,194 )
                 
Net change in cash and cash equivalents
    39,058       (14,099 )
Cash and cash equivalents at beginning of period
    60,684       108,437  
Cash and cash equivalents at end of period
  $ 99,742     $ 94,338  
                 
Supplemental disclosure of cash flow information:
               
Cash paid for interest (net of amounts capitalized)
  $ (156,275 )   $ (150,473 )
Cash (paid) received for income taxes, net
    (1,173 )     59,051  
Supplemental disclosure of non-cash investing and financing transactions:
               
Property, plant and equipment additions in accounts payable
  $ 224,316     $ 116,145  
Issuance of common stock for reinvested dividends and 401(k) plans
    18,815       20,419  

See Notes to Consolidated Financial Statements
 
 
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands, except share and per share data)

   
March 31, 2012
   
Dec. 31, 2011
 
Assets
           
Current assets
           
Cash and cash equivalents
  $ 99,742     $ 60,684  
Restricted cash
    9,055       95,287  
Accounts receivable, net
    718,145       753,120  
Accrued unbilled revenues
    491,410       688,740  
Inventories
    474,359       618,232  
Regulatory assets
    333,053       402,235  
Derivative instruments
    61,971       64,340  
Deferred income taxes
    162,353       178,446  
Prepayments and other
    192,746       121,480  
Total current assets
    2,542,834       2,982,564  
                 
Property, plant and equipment, net
    22,672,686       22,353,367  
                 
Other assets
               
Nuclear decommissioning fund and other investments
    1,537,490       1,463,515  
Regulatory assets
    2,361,648       2,389,008  
Derivative instruments
    146,438       152,887  
Other
    192,157       155,926  
Total other assets
    4,237,733       4,161,336  
Total assets
  $ 29,453,253     $ 29,497,267  
                 
Liabilities and Equity
               
Current liabilities
               
Current portion of long-term debt
  $ 1,309,681     $ 1,059,922  
Short-term debt
    339,000       219,000  
Accounts payable
    786,187       902,078  
Regulatory liabilities
    220,526       275,095  
Taxes accrued
    359,064       289,713  
Accrued interest
    161,930       177,111  
Dividends payable
    126,601       126,487  
Derivative instruments
    56,132       157,414  
Other
    348,921       381,819  
Total current liabilities
    3,708,042       3,588,639  
                 
Deferred credits and other liabilities
               
Deferred income taxes
    4,212,924       4,020,377  
Deferred investment tax credits
    85,819       86,743  
Regulatory liabilities
    1,107,818       1,101,534  
Asset retirement obligations
    1,662,175       1,651,793  
Derivative instruments
    260,152       263,906  
Customer advances
    247,224       248,345  
Pension and employee benefit obligations
    813,792       1,001,906  
Other
    219,273       203,313  
Total deferred credits and other liabilities
    8,609,177       8,577,917  
                 
Commitments and contingencies
               
Capitalization
               
Long-term debt
    8,598,363       8,848,513  
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 486,935,997 and 486,493,933 shares outstanding at March 31, 2012 and Dec. 31, 2011, respectively
    1,217,339       1,216,234  
Additional paid in capital
    5,298,572       5,327,443  
Retained earnings
    2,089,275       2,032,556  
Accumulated other comprehensive loss
    (67,515 )     (94,035 )
Total common stockholders’ equity
    8,537,671       8,482,198  
Total liabilities and equity
  $ 29,453,253     $ 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                    
   
Shares
     
Par Value
       
Additional
Paid In Capital
     
Retained
Earnings
   
Accumulated
Other
Comprehensive
Loss
     
Total Common
Stockholders'
Equity
 
Three Months Ended March 31, 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
                            203,569               203,569  
Other comprehensive income
                                    1,246       1,246  
Comprehensive income
                                            204,815  
Dividends declared:
                                               
Cumulative preferred stock
                            (1,060 )             (1,060 )
Common stock
                            (122,826 )             (122,826 )
Issuances of common stock
    1,831       4,577       1,652                       6,229  
Share-based compensation
                    10,806                       10,806  
Balance at March 31, 2011
    484,165     $ 1,210,411     $ 5,241,533     $ 1,781,386     $ (51,847 )   $ 8,181,483  
                                                 
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
                            183,893               183,893  
Other comprehensive income
                                    26,520       26,520  
Comprehensive income
                                            210,413  
Dividends declared:
                                               
Common stock
                            (127,174 )             (127,174 )
Issuances of common stock
    1,142       2,855       2,288                       5,143  
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
                    8,927                       8,927  
Balance at March 31, 2012
    486,936     $ 1,217,339     $ 5,298,572     $ 2,089,275     $ (67,515 )   $ 8,537,671  

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 March 31, 2012 and Dec. 31, 2011 and the results of its operations, cash flows and changes in stockholders’ equity for the three months ended March 31, 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 March 31, 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 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)
 
March 31, 2012
   
Dec. 31, 2011
 
Accounts receivable, net
           
Accounts receivable
  $ 776,140     $ 811,685  
Less allowance for bad debts
    (57,995 )     (58,565 )
    $ 718,145     $ 753,120  
Inventories
               
Materials and supplies
  $ 207,729     $ 202,699  
Fuel
    176,874       236,023  
Natural gas
    89,756       179,510  
    $ 474,359     $ 618,232  
Property, plant and equipment, net
               
Electric plant
  $ 27,393,092     $ 27,254,541  
Natural gas plant
    3,700,424       3,676,754  
Common and other property
    1,484,878       1,546,643  
Plant to be retired (a)
    115,401       151,184  
Construction work in progress
    1,315,390       1,085,245  
Total property, plant and equipment
    34,009,185       33,714,367  
Less accumulated depreciation
    (11,731,341 )     (11,658,351 )
Nuclear fuel
    2,062,790       1,939,299  
Less accumulated amortization
    (1,667,948 )     (1,641,948 )
    $ 22,672,686     $ 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 taken out of service.  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 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012.
 
 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 March 31, 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
   
2007
Texas
   
2007
Wisconsin
   
2007

As of March 31, 2012, there were no state income tax audits in progress.

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)
 
March 31, 2012
   
Dec. 31, 2011
 
Unrecognized tax benefit — Permanent tax positions
  $ 4.4     $ 4.3  
Unrecognized tax benefit — Temporary tax positions
    29.5       30.4  
Unrecognized tax benefit balance
  $ 33.9     $ 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)
 
March 31, 2012
   
Dec. 31, 2011
 
NOL and tax credit carryforwards
  $ (32.8 )   $ (33.6 )

The decrease in the unrecognized tax benefit balance of $0.8 million from Dec. 31, 2011 to March 31, 2012 was due to adjustments for prior years’ activity.  Xcel Energy’s amount of unrecognized tax benefits could change in the next 12 months as the Internal Revenue Service and state audits resume.  At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

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 March 31, 2012 and Dec. 31, 2011 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 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.

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

Pending and 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 various parties, which resolved all financial issues and several rate design issues.  The settlement agreement includes:

·
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.
·
The ability for NSP-Minnesota to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012.
·
The stipulation that NSP-Minnesota will not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement agreement and the property tax filing are approved by the MPUC.

 
In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  On March 29, 2012, the MPUC approved the settlement and a written order is pending.  As of March 31, 2012 and Dec. 31, 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $78 million and $67 million, respectively, to align with the settlement agreement.

NSP-Minnesota – Minnesota Property Tax Deferral Request — As part of the settlement agreement in the Minnesota electric rate case, the settling parties acknowledged that NSP-Minnesota would be filing a petition seeking deferred accounting for 2012 property tax expense in excess of the level approved in the rate case.  The settling parties waived any right to object to the petition, but reserved the right to review and comment on the petition.  In December 2011, NSP-Minnesota filed the petition to request deferral of approximately $28 million of incremental 2012 property taxes that will not be recovered in base rates.  The estimate of 2012 incremental property taxes has been subsequently revised to approximately $24 million.

In April 2012, the Minnesota Department of Commerce (DOC) filed comments on the petition.  The DOC concluded that NSP-Minnesota had not made a reasonable case for deferred accounting and recommended that the MPUC deny NSP-Minnesota’s request to defer incremental 2012 property taxes and also opposed the proposed rider mechanism.  The Xcel Large Industrials and the Minnesota Chamber of Commerce filed comments in support of the deferred accounting treatment as preferable to a rider mechanism, with the understanding that all costs will be reviewed in NSP-Minnesota’s next rate case.  Until the MPUC rules on the issue, NSP-Minnesota will continue to expense the incremental property taxes.  An MPUC decision is expected in the second quarter of 2012.

Recently Concluded Regulatory Proceedings — North Dakota Public Service Commission (NDPSC)

NSP-Minnesota – North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent, and a step increase of $4.2 million, or 2.6 percent, in 2012.  The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.  The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff, which provided for a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues.  To address 2012 sales coming in below forecast revenue projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.  In February 2012, the NDPSC approved the settlement agreement.

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

NSP-Minnesota – South Dakota Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012.  The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms.  The request is 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.  NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.  On Jan. 2, 2012, interim rates of $12.7 million were implemented.

In April 2012, the SDPUC Staff filed their direct testimony, which recommended an ROE of approximately 9 percent (ranging from 8.5 percent to 9.5 percent) and a lower cost of debt than the request (6.02 percent compared to the original request of 6.13 percent).  The Staff also recommended disallowance of the Nobles wind project costs unless the SDPUC determines there is energy value in which case the Staff’s recommendation would be to disallow a portion of the costs.  NSP-Minnesota’s rebuttal testimony is due by April 27, 2012 and a final SDPUC decision is expected in the summer of 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.

 
On April 26, 2012, the CPUC approved a comprehensive multi-year settlement agreement, which covers 2012 through 2014. Key terms of the agreement include the following:

·
PSCo will implement an annual electric rate increase of $73 million in 2012.  The rate increase will be effective on May 1, 2012, subject to refund.  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.
·
PSCo will forego the opportunity allowed under the CACJA to seek additional rate mechanisms to recover approved CACJA plan costs through 2014.  PSCo will instead recover the carrying costs of CACJA related expenditures through the recording of allowance for funds used during construction.
·
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 shall 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 rates that take effect include no incremental recovery of deferred costs associated with the expiration of the Black Hills contract.  However, the jurisdictional allocator used to determine the increase in base rates and for all rider calculations will reflect the expiration of the Black Hills contract as of Dec. 31, 2011.  The rates that would take effect also include no change in depreciation rates.
·
The signing parties agree to implement an earnings test, in which customers and shareholders will share 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 agrees that it will not file for an electric rate increase that would take effect prior to Jan. 1, 2015, provided that net revenue requirements increases or decreases 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 acknowledge 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.

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

PSCo 2011 Wholesale Electric Rate Case — In February 2011, PSCo filed with the FERC to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011.  The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent.  The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year.  In September 2011, PSCo implemented an interim rate increase of $7.8 million, subject to refund.

In April 2012, PSCo filed an unopposed settlement agreement with wholesale customers for an annual rate increase of $7.8 million.  The primary reasons for the decrease from the original request were a reduction to depreciation expense of $5.8 million and a lower ROE (ranging from 10.1 percent to 10.4 percent).  The reduction of depreciation expense is associated with the early retirement of plants related to PSCo’s compliance with the CACJA.  The depreciation expense will be deferred and amortized over the original life of the plants.

PSCo Transmission Formula Rate Case — In April 2012, PSCo filed with the FERC to revise the wholesale transmission rates formula from a historic test year formula rate to a forecast transmission formula.  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 transmission revenue by approximately $2.0 million over rates expected to be effective in June 2012.  A FERC decision is expected in the second half of 2012.

 
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 the first quarter of 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.

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.

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 that own natural gas or biomass fueled power plants 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 3,773 megawatts (MW) of capacity under long-term purchased power agreements as of March 31, 2012 and Dec. 31, 2011 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 March 31, 2012 and Dec. 31, 2011, Xcel Energy Inc. and its subsidiaries have 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)
 
March 31, 2012
   
Dec. 31, 2011
 
Guarantees issued and outstanding
  $ 67.5     $ 67.5  
Current exposure under these guarantees
    17.9       18.0  
Bonds with indemnity protection
    30.4       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.  The indemnification obligation expires in March 2013.  NSP-Minnesota has not recorded a liability related to this indemnity.

In connection with the acquisition of 900 MW of 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.

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

Manufactured Gas Plant (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/Northern States Power Lakefront Superfund Site (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 cleanup at the site.  The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intend to conduct or pay for the cleanup.  In June 2011, NSP-Wisconsin submitted a settlement offer to the EPA related to the future cleanup of the Ashland site.  In July 2011, the EPA informed NSP-Wisconsin and the other PRPs that it was rejecting all of their individual offers and can now choose to initiate enforcement actions at any time.  Despite this decision, the EPA also indicated a willingness to continue settlement negotiations with NSP-Wisconsin, which are currently ongoing.

At March 31, 2012 and Dec. 31, 2011, NSP-Wisconsin had recorded a liability of $104.3 million, 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, which party implements the cleanup, the timing of when the cleanup is implemented and the contributions, if any, by other PRPs.

NSP-Wisconsin has deferred, as a regulatory asset, the estimated site remediation expenses and spending to date less insurance and rate recoveries, based on an expectation that the Public Service Commission of Wisconsin (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.  NSP-Wisconsin is working with the PSCW Staff to develop alternatives for consideration by the PSCW.

 
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 ultimate 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 March 31, 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.

Other Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the Clean Air Act (CAA).  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 noted that, pursuant to its general NSPS regulations, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program.  It is not possible to evaluate the impact of this regulation until its final requirements are known.  It is not known when the EPA will propose 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.  SPS, other utilities and industry groups have filed separate appeals with the New Mexico Court of Appeals challenging the validity of these two GHG regulations.  The appellate cases have been stayed pending further proceedings before the EIB.

In July 2011, SPS and other parties filed a petition for repeal of each GHG rule with the EIB.  The EIB repealed both regulations in February 2012 and in March 2012.  In April 2012, Western Resource Advocates and New Energy Economy, Inc. filed an appeal with the New Mexico Court of Appeals to challenge the EIB’s February decision to repeal the GHG cap-and-trade program rule.  SPS has filed a petition to intervene in the appeal.

Cross-State Air Pollution Rule (CSAPR) In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter 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 applies to Minnesota, Wisconsin and Texas.  The CSAPR sets more stringent requirements than the proposed Clean Air Transport Rule and specifically requires plants in Texas to reduce their SO2 and annual NOx emissions.  The rule also creates an emissions trading program.
 
On Dec. 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a stay of the CSAPR, pending completion of judicial review.  Oral arguments in the case were held in April 2012 and it is anticipated the D.C. Circuit will rule on the challenges to the CSAPR in the second half of 2012.  It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future D.C. Circuit decision.

If the CSAPR is upheld and unmodified, Xcel Energy believes that the CSAPR could ultimately require the installation of additional emission controls on some of SPS’ coal-fired electric generating units.  If compliance is required in a short time frame, SPS may be required to redispatch its system to reduce coal plant operating hours, in order to decrease emissions from its facilities prior to the installation of emission controls.  The expected cost for these scenarios may vary significantly and SPS has estimated capital expenditures of approximately $470 million over the next four years for the plant modifications related to the CSAPR requirements.  SPS believes the cost of any required capital investment or possible increased fuel costs would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position or cash flows.  On April 23, 2012, SPS appealed to the D.C. Circuit on a final rule that the EPA issued that made changes to certain allowance allocations under CSAPR.  While this rule increases the allowance allocations for SO2 for SPS, it did not increase them by as much as the proposed rule. SPS is seeking additional allowance allocations through this appeal, which, if successful, would reduce SPS’ costs to comply with the CSAPR.

If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at NSP-Minnesota’s Sherco plant, which is estimated to cost a total of $10 million through 2014, and system operating changes to the Black Dog and the Sherco plants.  If available, NSP-Minnesota would also consider allowance purchases.  In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota.  NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas.  On April 23, 2012, NSP-Minnesota appealed to the D.C. Circuit on a final rule that the EPA issued that made changes to certain allowance allocations under CSAPR, seeking to secure additional allocations for its Riverside and High Bridge plants.  If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the CSAPR.

 
If the CSAPR is upheld and unmodified, NSP-Wisconsin would likely make a combination of system operating changes and allowance purchases.  NSP-Wisconsin estimates the cost of compliance would be $0.2 million, and expects the cost of any required capital investment will be recoverable from customers.

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 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 will be subject to BART requirements.  Individual states are required to identify the facilities located in their states that will have to reduce SO2, NOx and particulate matter emissions under BART and then set emissions limits for those facilities.

PSCo
In 2006, the Colorado Air Quality Control Commission 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 Colorado Air Quality Control Commission approved a revised Regional Haze BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements.  In March 2012, the EPA proposed to approve the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements.  PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA plan recovery mechanisms or other regulatory mechanisms.  Emissions controls are expected to be installed between 2012 and 2017.

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, 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 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.

In June 2011, the EPA provided comments to the MPCA on the 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 has 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. 
 
On April 24, 2012, the MPCA approved a supplement to the 2009 Regional Haze SIP finding that 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.  This SIP supplement will be forwarded to the EPA for approval, and it is anticipated that the EPA will make a decision in May 2012.

In addition to the Regional Haze rules identified in the EPA’s visibility program, and addressed in the MPCA’s 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.

 
SPS
Harrington Units 1 and 2 are potentially subject to BART.  Texas has developed a Regional Haze SIP that finds the Clean Air Interstate Rule (CAIR) equal to BART for EGUs, and as a result, no additional controls for these units beyond the CAIR compliance would be required.  The EPA is scheduled to publish its proposal of the Texas plan in May 2012 and complete its review by November 2012.

Legal Contingencies

Lawsuits and claims arise in the normal course of business.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material effect on Xcel Energy’s consolidated financial position, results of operations, and cash flows.

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 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.  In November 2011, oral arguments were presented.  It is unknown when the Ninth Circuit will render a final opinion.  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.  While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on Xcel Energy’s consolidated results of operations, cash flows or financial position.  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 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.  On March 20, 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.  While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on Xcel Energy’s consolidated results of operations, cash flows or financial position.  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.  As a result, 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 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, in excess of $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco’s lawsuit is without merit and has filed a motion to dismiss.  In September 2011, the U.S. District Court denied the motion to dismiss.  The trial is set to begin in late 2012 or early 2013.  While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on Xcel Energy’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

 
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:

(Amounts in Millions, Except Interest Rates)
 
Three Months Ended
March 31, 2012
   
Twelve Months Ended
Dec. 31, 2011
 
Borrowing limit
 
$
                       2,450
   
$
                       2,450
 
Amount outstanding at period end
   
                          339
     
                          219
 
Average amount outstanding
   
                          324
     
                          430
 
Maximum amount outstanding
   
                          463
     
                          824
 
Weighted average interest rate, computed on a daily basis
   
                         0.36
%
 
                         0.36
%
Weighted average interest rate at period end
   
                         0.36
     
                         0.40
 

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 agreements.  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 March 31, 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     $ 214.0     $ 586.0  
PSCo
    700.0       3.0       697.0  
NSP-Minnesota
    500.0       35.7       464.3  
SPS
    300.0       26.0       274.0  
NSP-Wisconsin
    150.0       71.0       79.0  
Total
  $ 2,450.0     $ 349.7     $ 2,100.3  

(a)
Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings 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 March 31, 2012 and Dec. 31, 2011.

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 March 31, 2012 and Dec. 31, 2011, there were $10.7 million and $12.7 million of letters of credit outstanding, respectively, under the credit facilities.  An additional $1.1 million of letters of credit not issued under the credit facilities were outstanding at March 31, 2012 and Dec. 31, 2011, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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 hierarchal 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.  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 NSP-Minnesota’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 that energy congestion, which is caused by overall transmission load and other transmission constraints. 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 derivatives, 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 interest rate derivatives and 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 decommissioning fund were $117.1 million and $79.8 million at March 31, 2012 and Dec. 31, 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $65.7 million and $87.5 million at March 31, 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 March 31, 2012 and Dec. 31, 2011:

   
March 31, 2012
 
         
Fair Value
       
                               
(Thousands of Dollars)
 
Cost
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Nuclear decommissioning fund (a)
                             
Cash equivalents
  $ 12,383     $ 8,023     $ 4,360     $ -     $ 12,383  
Commingled funds
    374,523       -       371,078       -       371,078  
International equity funds
    65,712       -       67,183       -       67,183  
Private equity investments
    19,358       -       -       20,068       20,068  
Real estate
    26,265       -       -       27,905       27,905  
Debt securities:
                                       
Government securities
    131,152       -       131,401       -       131,401  
U.S. corporate bonds
    156,602       -       163,851       -       163,851  
International corporate bonds
    25,187       -       26,351       -       26,351  
Municipal bonds
    53,895       -       56,862       -       56,862  
Asset-backed securities
    16,515       -       -       16,547       16,547  
Mortgage-backed securities
    65,803       -       -       68,671       68,671  
Equity securities:
                                       
Common stock
    410,729       447,205       -       -       447,205  
Total
  $ 1,358,124     $ 455,228     $ 821,086     $ 133,191     $ 1,409,505  

(a)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $92.3 million of equity investments in unconsolidated subsidiaries and $35.7 million of miscellaneous investments.
 
 
   
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:

(Thousands of Dollars)
  Jan. 1, 2012     Purchases     Settlements     Gains (Losses) Recognized as Regulatory Assets and Liabilities     March 31, 2012  
Asset-backed securities
  $ 16,501     $ -     $ (1 )   $ 47     $ 16,547  
Mortgage-backed securities
    78,664       6,904       (16,728 )     (169 )     68,671  
Real estate
    26,395       1,636       (1,766 )     1,640       27,905  
Private equity investments
    9,203       10,155       -       710       20,068  
Total
  $ 130,763     $ 18,695     $ (18,495 )   $ 2,228     $ 133,191  

(Thousands of Dollars)
 
Jan. 1, 2011
   
Purchases
   
Settlements
   
Losses
Recognized as
Regulatory Assets
    March 31, 2011  
Asset-backed securities
  $ 33,174     $ 756     $ (7,910 )   $ -     $ 26,020  
Mortgage-backed securities
    72,589       46,113       (19,873 )     (462 )     98,367  
Total
  $ 105,763     $ 46,869     $ (27,783 )   $ (462 )   $ 124,387  

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at March 31, 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
  $ 113,004     $ 701     $ 17,696     $ -     $ 131,401  
U.S. corporate bonds
    -       37,556       112,103       14,192       163,851  
International corporate bonds
    -       8,162       18,186       3       26,351  
Municipal bonds
    -       -       27,039       29,823       56,862  
Asset-backed securities
    -       13,269       3,278       -       16,547  
Mortgage-backed securities
    -       -       959       67,712       68,671  
Debt securities
  $ 113,004     $ 59,688     $ 179,261     $ 111,730     $ 463,683  

 
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, as well as variances in forecasted weather.

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 March 31, 2012, accumulated other comprehensive losses related to interest rate derivatives included $0.9 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At March 31, 2012, Xcel Energy had unsettled interest rate swaps outstanding with a notional amount of $475 million.  These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

Short-Term Wholesale and Commodity Trading Risk — Xcel Energy conducts various short-term 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, gas for resale and vehicle fuel.

At March 31, 2012, Xcel Energy had various vehicle fuel related contracts designated as cash flow hedges extending through December 2014.  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 months ended March 31, 2012 and 2011.

At March 31, 2012, accumulated OCI related to commodity derivative cash flow hedges included $0.2 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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 March 31, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)
 
March 31, 2012
   
Dec. 31, 2011
 
Megawatt hours (MWh) of electricity
    23,385       38,822  
MMBtu of natural gas
    -       40,736  
Gallons of vehicle fuel
    550       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.
 
 
The following tables detail the impact of derivative activity during the three months ended March 31, 2012 and 2011, on OCI, regulatory assets and liabilities, and income:
 
    Three Months Ended March 31, 2012  
    Fair Value Changes Recognized
During the Period in:
    Pre-Tax Amounts Reclassified into
Income During the Period from:
       
 
(Thousands of Dollars)
  Accumulated
Other
Comprehensive Loss
    Regulatory
(Assets) and
Liabilities
    Accumulated
Other
Comprehensive
Loss
   
Regulatory
Assets and
(Liabilities)
    Pre-Tax Gains
(Losses) Recognized
During the Period
in Income
 
Derivatives designated as cash flow hedges
                             
Interest rate
  $ 41,704     $ -     $ 389 (a)   $ -     $ -  
Vehicle fuel and other commodity
    179       -       (52 )(e)     -       -  
Total
  $ 41,883     $ -     $ 337     $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 1,723 (b)
Electric commodity
    -       1,582       -       (7,972 )(c)     -  
Natural gas commodity
    -       (10,783 )     -       80,939 (d)     (109 )(b)
Total
  $ -     $ (9,201 )   $ -     $ 72,967     $ 1,614  
 
    Three Months Ended March 31, 2011  
   
Fair Value Changes Recognized
During the Period in:
   
Pre-Tax Amounts Reclassified into
Income During the Period from:
       
 
(Thousands of Dollars)
 
Accumulated
Other
Comprehensive
Loss
   
Regulatory
(Assets) and
Liabilities
   
Accumulated
Other
Comprehensive
Loss
   
Regulatory
Assets and
(Liabilities)
   
Pre-Tax Gains
Recognized
During the Period
in Income
 
 Derivatives designated  as cash flow hedges                              
Interest rate
  $ -     $ -     $ 337 (a)   $ -     $ -  
Vehicle fuel and other commodity
    389       -       (32 )(e)     -       -  
Total
  $ 389     $ -     $ 305     $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 5,600 (b)
Electric commodity
    -       8,846       -       (8,888 )(c)     -  
Natural gas commodity
    -       (7,615 )     -       57,387 (d)     -  
Total
  $ -     $ 1,231     $ -     $ 48,499     $ 5,600  

(a)
Recorded to interest charges.
(b)
Recorded to electric operating revenues.  Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)
Recorded to electric fuel and purchased power.  These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(d)
Recorded to cost of natural gas sold and transported.  These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(e)
Recorded to O&M expenses.

Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2012 and March 31, 2011.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.
 
 
Credit Related Contingent Features  Contract provisions of the derivative instruments that the utility subsidiaries enter into may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings.  If the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade, contracts underlying $10.8 million and $8.3 million of derivative instruments in a gross liability position at March 31, 2012 and Dec. 31, 2011, respectively, would have required Xcel Energy Inc.’s utility subsidiaries to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $9.4 million and $9.3 million, respectively.  At March 31, 2012 and Dec. 31, 2011, there was no collateral posted on these specific contracts.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses.  These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.  Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2012 and Dec. 31, 2011.

Recurring Fair Value Measurements — The following tables present for each of the hierarchy levels, Xcel Energy’s derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2012:

   
March 31, 2012
 
   
Fair Value
                   
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Fair Value
Total
   
Counterparty
Netting (b)
   
Total
 
Current derivative assets
                                   
Derivatives designated as cash flow hedges:
                                   
Interest rate
  $ -     $ 306     $ -     $ 306     $ -     $ 306  
Vehicle fuel and other commodity
    -       208       -       208       -       208  
Other derivative instruments:
                                               
Trading commodity
    -       39,483       -       39,483       (16,195 )     23,288  
Electric commodity
    -       -       5,898       5,898       (570 )     5,328  
Total current derivative assets
  $ -     $ 39,997     $ 5,898     $ 45,895