10-Q 1 form10q.htm NORTHERN STATES POWER CO MN 10-Q 6-30-2012 form10q.htm


F
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 June 30, 2012

or

 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-31387

Northern States Power Company
(Exact name of registrant as specified in its charter)

Minnesota
 
41-1967505
(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 o
 
Accelerated filer o
     
Non-accelerated filer x
 
Smaller reporting company o
(Do not check if smaller reporting company)
   

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

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

Class
 
Outstanding at Aug. 3, 2012
Common Stock, $0.01 par value
 
1,000,000 shares

Northern States Power Company (a Minnesota corporation) meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.



 
 

 
 
TABLE OF CONTENTS

PART I  FINANCIAL INFORMATION
 
       
Item l —
 
3
Item 2 —
 
27
Item 4 —
 
33
       
PART II OTHER INFORMATION
 
       
Item 1 —
 
33
Item 1A —
 
33
Item 4 —
 
33
Item 5 —
 
33
Item 6 —
 
34
       
35

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 Northern States Power Company, a Minnesota corporation (NSP-Minnesota).  NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: NSP-Minnesota; Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Company, a New Mexico corporation (SPS).  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).
 
 
PART I FINANCIAL INFORMATION
Item 1 FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands)

   
Three Months Ended June 30
   
Six Months Ended June 30
 
   
2012
   
2011
   
2012
   
2011
 
Operating revenues
                       
Electric
  $ 908,050     $ 908,070     $ 1,782,434     $ 1,812,207  
Natural gas
    59,069       96,922       255,583       380,648  
Other
    5,417       5,534       11,292       10,563  
Total operating revenues
    972,536       1,010,526       2,049,309       2,203,418  
                                 
Operating expenses
                               
Electric fuel and purchased power
    362,146       378,597       727,474       752,674  
Cost of natural gas sold and transported
    25,545       56,970       159,735       258,212  
Cost of sales — other
    2,972       2,865       6,089       5,791  
Operating and maintenance expenses
    271,611       261,626       532,641       516,840  
Conservation program expenses
    22,487       29,926       50,171       68,412  
Depreciation and amortization
    99,923       104,355       198,903       204,828  
Taxes (other than income taxes)
    48,374       40,334       102,142       85,987  
Total operating expenses
    833,058       874,673       1,777,155       1,892,744  
                                 
Operating income
    139,478       135,853       272,154       310,674  
                                 
Other (expense) income, net
    (882 )     (1,205 )     1,523       1,679  
Allowance for funds used during construction — equity
    9,179       10,146       17,214       19,739  
                                 
Interest charges and financing costs
                               
Interest charges — includes other financing costs of $1,476, $1,616,
$2,953 and $3,042, respectively
    52,282       52,313       104,402       103,928  
Allowance for funds used during construction — debt
    (4,937 )     (5,961 )     (9,215 )     (11,284 )
Total interest charges and financing costs
    47,345       46,352       95,187       92,644  
                                 
Income before income taxes
    100,430       98,442       195,704       239,448  
Income taxes
    36,118       33,219       54,406       82,050  
Net income
  $ 64,312     $ 65,223     $ 141,298     $ 157,398  

See Notes to Consolidated Financial Statements


NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in thousands)

   
Three Months Ended June 30
   
Six Months Ended June 30
 
   
2012
   
2011
   
2012
   
2011
 
                         
Net income
  $ 64,312     $ 65,223     $ 141,298     $ 157,398  
                                 
Other comprehensive (loss) income
                               
                                 
Pension and retiree medical benefits:
                               
Amortization of losses included in net periodic benefit cost, net of tax of $30, $24, $56 and $48, respectively
    44       34       81       68  
                                 
Derivative instruments:
                               
Net fair value (decrease) increase, net of tax of $(11,680), $(6), $(3,163) and $72, respectively
    (16,970 )     (8 )     (4,597 )     105  
Reclassification of gains to net income, net of tax of $(23), $(32), $(45) and $(44), respectively
    (34 )     (46 )     (67 )     (61 )
      (17,004 )     (54 )     (4,664 )     44  
                                 
Marketable securities:
                               
Net fair value increase, net of tax of $84, $0, $120 and $34, respectively
    122       -       174       50  
                                 
Other comprehensive (loss) income
    (16,838 )     (20 )     (4,409 )     162  
Comprehensive income
  $ 47,474     $ 65,203     $ 136,889     $ 157,560  

See Notes to Consolidated Financial Statements
 
 
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)

   
Six Months Ended June 30
 
   
2012
   
2011
 
Operating activities
           
Net income
  $ 141,298     $ 157,398  
Adjustments to reconcile net income to cash provided by operating activities:
               
Depreciation and amortization
    201,290       207,493  
Nuclear fuel amortization
    49,765       43,732  
Deferred income taxes
    91,672       85,421  
Amortization of investment tax credits
    (1,351 )     (1,347 )
Allowance for equity funds used during construction
    (17,214 )     (19,739 )
Net derivative gains
    (626 )     (4,401 )
Changes in operating assets and liabilities:
               
Accounts receivable
    (83,951 )     24,654  
Accrued unbilled revenues
    39,555       57,260  
Inventories
    57,811       47,168  
Other current assets
    (25,456 )     (538 )
Accounts payable
    (62,066 )     46,431  
Net regulatory assets and liabilities
    (7,165 )     (8,480 )
Other current liabilities
    (29,202 )     (10,792 )
Pension and other employee benefit obligations
    (73,610 )     (43,484 )
Change in other noncurrent assets
    (23,952 )     (2,586 )
Change in other noncurrent liabilities
    (5,607 )     (26,893 )
Net cash provided by operating activities
    251,191       551,297  
                 
Investing activities
               
Utility capital/construction expenditures
    (469,026 )     (622,360 )
Proceeds from insurance recoveries
    24,000       -  
Merricourt refund
    -       101,261  
Merricourt deposit
    -       (90,833 )
Allowance for equity funds used during construction
    17,214       19,739  
Purchases of investments in external decommissioning fund
    (371,361 )     (1,226,490 )
Proceeds from the sale of investments in external decommissioning fund
    371,361       1,226,504  
Investments in utility money pool arrangement
    -       (432,000 )
Repayments from utility money pool arrangement
    -       432,000  
Advances to affiliate
    -       (111,300 )
Advances from affiliate
    -       148,300  
Change in restricted cash
    94,959       -  
Other, net
    (1,333 )     (3,691 )
Net cash used in investing activities
    (334,186 )     (558,870 )
                 
Financing activities
               
(Repayments of) proceeds from short-term borrowings, net
    (26,000 )     5,000  
Borrowings under utility money pool arrangement
    555,000       300  
Repayments under utility money pool arrangement
    (475,000 )     (300 )
Repayments of long-term debt, including reacquisition premiums
    -       (30 )
Capital contributions from parent
    145,621       125,000  
Dividends paid to parent
    (116,081 )     (116,007 )
Net cash provided by financing activities
    83,540       13,963  
                 
Net change in cash and cash equivalents
    545       6,390  
Cash and cash equivalents at beginning of period
    26,005       38,408  
Cash and cash equivalents at end of period
  $ 26,550     $ 44,798  
                 
Supplemental disclosure of cash flow information:
               
Cash paid for interest (net of amounts capitalized)
  $ (96,391 )   $ (89,977 )
Cash paid for income taxes, net
    (21,957 )     (4,211 )
Supplemental disclosure of non-cash investing transactions:
               
Property, plant and equipment additions in accounts payable
  $ 170,877     $ 23,513  

See Notes to Consolidated Financial Statements

 
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands, except share and per share data)

   
June 30, 2012
   
Dec. 31, 2011
 
Assets            
Current assets
           
Cash and cash equivalents
  $ 26,550     $ 26,005  
Restricted cash
    328       95,287  
Accounts receivable, net
    289,292       314,577  
Accounts receivable from affiliates
    30,751       18,033  
Accrued unbilled revenues
    191,748       231,303  
Inventories
    244,037       301,848  
Regulatory assets
    173,028       141,709  
Derivative instruments
    74,891       51,517  
Prepayments and other
    81,956       45,219  
Total current assets
    1,112,581       1,225,498  
                 
Property, plant and equipment, net
    9,311,126       8,982,834  
                 
Other assets
               
Nuclear decommissioning fund and other investments
    1,409,952       1,357,538  
Regulatory assets
    873,819       872,014  
Derivative instruments
    71,814       80,689  
Other
    59,576       36,638  
Total other assets
    2,415,161       2,346,879  
Total assets
  $ 12,838,868     $ 12,555,211  
                 
Liabilities and Equity
               
Current liabilities
               
Current portion of long-term debt
  $ 450,005     $ 450,000  
Short-term debt
    -       26,000  
Borrowings under utility money pool arrangement
    145,000       65,000  
Accounts payable
    405,233       322,979  
Accounts payable to affiliates
    48,435       47,651  
Regulatory liabilities
    68,754       132,574  
Taxes accrued
    123,864       158,319  
Accrued interest
    66,565       68,362  
Dividends payable to parent
    59,022       58,054  
Derivative instruments
    60,659       65,781  
Provision for rate refund
    82,419       69,746  
Other
    76,761       94,990  
Total current liabilities
    1,586,717       1,559,456  
                 
Deferred credits and other liabilities
               
Deferred income taxes
    1,784,589       1,666,005  
Deferred investment tax credits
    31,048       31,743  
Regulatory liabilities
    430,764       439,029  
Asset retirement obligations
    1,623,642       1,581,896  
Derivative instruments
    180,016       184,190  
Pension and employee benefit obligations
    339,861       413,755  
Other
    82,598       65,464  
Total deferred credits and other liabilities
    4,472,518       4,382,082  
                 
Commitments and contingencies
               
Capitalization
               
Long-term debt
    2,889,396       2,888,897  
Common stock – authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares
outstanding at June 30, 2012 and Dec. 31, 2011, respectively
    10       10  
Additional paid in capital
    2,512,012       2,366,391  
Retained earnings
    1,396,976       1,372,727  
Accumulated other comprehensive loss
    (18,761 )     (14,352 )
Total common stockholder's equity
    3,890,237       3,724,776  
Total liabilities and equity
  $ 12,838,868     $ 12,555,211  

See Notes to Consolidated Financial Statements

 
NSP-MINNESOTA 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 NSP-Minnesota and its subsidiaries as of June 30, 2012 and Dec. 31, 2011; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2012 and 2011; and its cash flows for the six months ended June 30, 2012 and 2011.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after June 30, 2012 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the NSP-Minnesota 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 NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011, filed with the SEC on Feb. 27, 2012.  Due to the seasonality of NSP-Minnesota’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 NSP-Minnesota 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.  NSP-Minnesota 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.  NSP-Minnesota implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Minnesota 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)
 
June 30, 2012
   
Dec. 31, 2011
 
Accounts receivable, net
           
Accounts receivable
  $ 309,043     $ 337,581  
Less allowance for bad debts
    (19,751 )     (23,004 )
    $ 289,292     $ 314,577  
Inventories
               
Materials and supplies
  $ 130,458     $ 124,961  
Fuel
    89,030       113,711  
Natural gas
    24,549       63,176  
    $ 244,037     $ 301,848  
Property, plant and equipment, net
               
Electric plant
  $ 12,026,539     $ 11,948,041  
Natural gas plant
    1,010,389       1,006,163  
Common and other property
    465,887       525,139  
Construction work in progress
    874,927       639,246  
Total property, plant and equipment
    14,377,742       14,118,589  
Less accumulated depreciation
    (5,462,566 )     (5,433,106 )
Nuclear fuel
    2,087,663       1,939,299  
Less accumulated amortization
    (1,691,713 )     (1,641,948 )
    $ 9,311,126     $ 8,982,834  

4.
Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in the NSP-Minnesota 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 AuditNSP-Minnesota is a member of the Xcel Energy affiliated group that 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. As of June 30, 2012, there was no federal income tax audit in progress.

State AuditsNSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of June 30, 2012, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2008.  As of June 30, 2012, there were no state income tax audits in progress.
 
Unrecognized Tax BenefitsThe 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 benefit is as follows:

(Millions of Dollars)
 
June 30, 2012
   
Dec. 31, 2011
 
Unrecognized tax benefit — Permanent tax positions
  $ 3.3     $ 3.3  
Unrecognized tax benefit — Temporary tax positions
    12.6       13.4  
Unrecognized tax benefit balance
  $ 15.9     $ 16.7  
 
 
The unrecognized tax benefit balance was 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)
 
June 30, 2012
   
Dec. 31, 2011
 
NOL and tax credit carryforwards
  $ (17.2 )   $ (18.1 )

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly 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, an overall range of possible change cannot be reasonably estimated.

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

Federal Tax Loss Carryback Claims — NSP-Minnesota 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, NSP-Minnesota recognized a discrete tax benefit of approximately $15 million in the first quarter of 2012.

5. 
Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Minnesota’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.

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

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

In November 2011, NSP-Minnesota reached a settlement agreement with certain customer intervenors.  In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  In March 2012, the MPUC approved the settlement.  In May 2012, the MPUC issued an order approving the following:

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

As of June 30, 2012 and Dec. 31, 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $80 million and $67 million, respectively.

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

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

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 February 2012, the NDPSC approved the settlement agreement, 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.  NSP-Minnesota implemented final rates in May 2012 and issued refunds in June 2012.

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

South Dakota 2011 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 was based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  On Jan. 2, 2012, interim rates of $12.7 million were implemented.  In June 2012, the SDPUC authorized a rate increase of approximately $8.0 million, based on an ROE of 9.25 percent, and an equity ratio of 53 percent.  On July 17, 2012, the SDPUC approved implementation of final rates on Aug. 1, 2012, with refunds to be issued in September 2012.

South Dakota 2012 Electric Rate Case  On June 29, 2012, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $19.4 million annually.  The request was based on a 2011 historic test year adjusted for certain known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million, and an equity ratio of 52.89 percent.  A SDPUC decision is expected in late 2012 or early 2013.

6. 
Commitments and Contingencies

Except as noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota 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 NSP-Minnesota’s financial position.

Purchased Power Agreements

Under certain purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases.  These specific purchased power agreements create a variable interest in the associated independent power producing entity.

NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements as of June 30, 2012 and Dec. 31, 2011 with entities that have been determined to be variable interest entities.  NSP-Minnesota 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 2028.

Guarantees and Indemnifications

In connection with the acquisition of the 201 MW Nobles wind project in 2011, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  NSP-Minnesota’s indemnification obligation is capped at $20 million, in the aggregate, at June 30, 2012 and Dec. 31, 2011.  The indemnification obligation expires in March 2013.  NSP-Minnesota has not recorded a liability related to this indemnity, and it had no assets held as collateral related to this agreement at June 30, 2012 or Dec. 31, 2011.
 
 
Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the U.S. Environmental Protection Agency (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.  Xcel Energy submitted comments on the proposed GHG NSPS in June 2012.  It is not possible to evaluate the impact of this regulation until its final requirements are known.

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

Cross-State Air Pollution Rule (CSAPR) — In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the United States, including Minnesota.  The CSAPR sets more stringent requirements than the proposed Clean Air Transport Rule.  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 during the summer 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, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at Sherco Units 1 and 2, which is estimated to cost a total of $10 million through 2014, and system operating changes to Black Dog and Sherco Units 1 and 2.  Costs for the Sherco Units 1 and 2 SO2 control technology are discussed below in the regional haze rules as SO2 reductions are part of the compliance plan for both the CSAPR and the regional haze rules.  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.  In April 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 the 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.  The D.C. Circuit held this appeal in abeyance until it issues its decision.

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

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

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

In 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 U.S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.  In May 2012, a notice of intent to sue was filed with the EPA by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyagers National Park Association, Fresh Energy and Sierra Club.  The notice advised the EPA of the parties’ intent to sue the EPA in 180 days to attempt to require the EPA to determine BART for the Sherco Units 1 and 2 under the RAVI program.  It is not yet known how the EPA intends to respond to this notice.

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

Legal Contingencies

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 NSP-Minnesota’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 Inc., the parent company of NSP-Minnesota, 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 Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In 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 Inc. 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 NSP-Minnesota’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. and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit. While Xcel Energy Inc. 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 NSP-Minnesota’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.  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 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 NSP-Minnesota 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 NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

7. 
Borrowings and Other Financing Instruments

Commercial Paper — NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.  The following table presents commercial paper outstanding for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)
 
Three Months Ended
June 30, 2012
   
Twelve Months Ended
Dec. 31, 2011
 
Borrowing limit
 
$
500
   
$
500
 
Amount outstanding at period end
   
-
     
26
 
Average amount outstanding
   
52
     
7
 
Maximum amount outstanding
   
89
     
80
 
Weighted average interest rate, computed on a daily basis
   
0.41
 %
   
0.34
 %
Weighted average interest rate at period end
   
N/A
     
0.45
 
 
 
Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an amount exceeding available capacity under the credit agreement.  The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At June 30, 2012, NSP-Minnesota had the following committed credit facility available (in millions of dollars):
 
Credit Facility
   
Drawn (a)
   
Available
 
$ 500.0     $ 8.7     $ 491.3  
 
(a)
Includes outstanding letters of credit.
 
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Minnesota had no direct advances on the credit facility outstanding at June 30, 2012 and Dec. 31, 2011.

Amended Credit Agreement In July 2012, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks, replacing the previous four-year credit agreement. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an improvement in pricing and an extension of maturity from March 2015 to July 2017. The Eurodollar borrowing margin on the line of credit was reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the line of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

Letters of Credit NSP-Minnesota uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations.  At June 30, 2012 and Dec. 31, 2011, there were $8.7 million and $7.7 million of letters of credit outstanding under the credit facility, respectively.  An additional $1.1 million of letters of credit not issued under the credit facility were outstanding at June 30, 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.

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.  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 following table presents money pool borrowings for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)
 
Three Months Ended
June 30, 2012
   
Twelve Months Ended
Dec. 31, 2011
 
Borrowing limit
 
$
250
   
$
250
 
Amount outstanding at period end
   
145
     
65
 
Average amount outstanding
   
50
     
17
 
Maximum amount outstanding
   
145
     
80
 
Weighted average interest rate, computed on a daily basis
   
0.34
 %
 
0.34
 %
Weighted average interest rate at period end
   
0.34
     
0.35
 


8. 
Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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

NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts 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 NSP-Minnesota’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities 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 securities under the applicable accounting guidance.  NSP-Minnesota plans to reinvest proceeds from matured securities until decommissioning begins.

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

Unrealized gains for the nuclear decommissioning fund were $109.8 million and $79.8 million at June 30, 2012 and Dec. 31, 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $76.6 million and $87.5 million at June 30, 2012 and Dec. 31, 2011, respectively.
 
 
The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund investments at June 30, 2012 and Dec. 31, 2011:

   
June 30, 2012
 
         
Fair Value
 
(Thousands of Dollars)
 
Cost
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Nuclear decommissioning fund (a)
                             
Cash equivalents
  $ 24,913     $ 15,082     $ 9,831     $ -     $ 24,913  
Commingled funds
    375,222       -       372,487       -       372,487  
International equity funds
    65,712       -       62,469       -       62,469  
Private equity investments
    22,593       -       -       23,303       23,303  
Real estate
    28,536       -       -       32,721       32,721  
Debt securities:
                                       
Government securities
    118,378       -       119,376       -       119,376  
U.S. corporate bonds
    151,444       -       159,834       -       159,834  
International corporate bonds
    22,782       -       23,709       -       23,709  
Municipal bonds
    66,769       -       70,608       -       70,608  
Asset-backed securities
    7,057       -       -       7,068       7,068  
Mortgage-backed securities
    63,526       -       -       66,321       66,321  
Equity securities:
                                       
Common stock
    407,384       424,703       -       -       424,703  
Total
  $ 1,354,316     $ 439,785     $ 818,314     $ 129,413     $ 1,387,512  
 
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $22.4 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 $21.1 million of miscellaneous investments.
 
 
The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2012 and 2011:
 
(Thousands of Dollars)
 
April 1, 2012
   
Purchases
   
Settlements
   
Gains (Losses)
Recognized as
Regulatory Assets
and Liabilities
   
June 30, 2012
 
Private equity investments
  $ 20,068     $ 3,235     $ -     $ -     $ 23,303  
Real estate
    27,905       2,271       -       2,545       32,721  
Asset-backed securities
    16,547       -       (9,458 )     (21 )     7,068  
Mortgage-backed securities
    68,671       7,414       (9,690 )     (74 )     66,321  
Total
  $ 133,191     $ 12,920     $ (19,148 )   $ 2,450     $ 129,413  

(Thousands of Dollars)
 
April 1, 2011
   
Purchases
   
Settlements
   
Gains (Losses)
Recognized as
Regulatory Assets
and Liabilities
   
June 30, 2011
 
Asset-backed securities
  $ 26,020     $ -     $ (5,206 )   $ 190     $ 21,004  
Mortgage-backed securities
    98,367       52,952       (88,584 )     (464 )     62,271  
Total
  $ 124,387     $ 52,952     $ (93,790 )   $ (274 )   $ 83,275  

(Thousands of Dollars)
 
Jan. 1, 2012
   
Purchases
   
Settlements
   
Gains (Losses)
Recognized as
Regulatory Assets
and Liabilities
   
June 30, 2012
 
Private equity investments
  $ 9,203     $ 13,390     $ -     $ 710     $ 23,303  
Real estate
    26,395       3,907       (1,766 )     4,185       32,721  
Asset-backed securities
    16,501       -       (9,459 )     26       7,068  
Mortgage-backed securities
    78,664       14,318       (26,418 )     (243 )     66,321  
Total
  $ 130,763     $ 31,615     $ (37,643 )   $ 4,678     $ 129,413  

(Thousands of Dollars)
 
Jan. 1, 2011
   
Purchases
   
Settlements
   
Gains (Losses)
Recognized as
Regulatory Assets
and Liabilities
   
June 30, 2011
 
Asset-backed securities
  $ 33,174     $ 756     $ (13,116 )   $ 190     $ 21,004  
Mortgage-backed securities
    72,589       99,065       (108,457 )     (926 )     62,271  
Total
  $ 105,763     $ 99,821     $ (121,573 )   $ (736 )   $ 83,275  

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at June 30, 2012:
 
   
Final Contractual Maturity
 
 
(Thousands of Dollars)
 
Due in 1
Year or Less
   
Due in 1 to 5
Years
   
Due in 5 to 10
Years
   
Due after 10
Years
   
 
Total
 
Government securities
  $ 104,694     $ 79     $ 3,648     $ 10,955     $ 119,376  
U.S. corporate bonds
    -       40,032       103,834       15,968       159,834  
International corporate bonds
    -       6,481       17,228       -       23,709  
Municipal bonds
    -       -       27,692       42,916       70,608  
Asset-backed securities
    -       4,983       2,085       -       7,068  
Mortgage-backed securities
    -       -       877       65,444       66,321  
Debt securities
  $ 104,694     $ 51,575     $ 155,364     $ 135,283     $ 446,916  
 
 
Derivative Instruments Fair Value Measurements

NSP-Minnesota 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, vehicle fuel prices, as well as variances in forecasted weather.

Interest Rate Derivatives — NSP-Minnesota 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 June 30, 2012, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At June 30, 2012, NSP-Minnesota had unsettled interest rate swaps outstanding with a total notional amount of $225 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 — NSP-Minnesota conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related products.  NSP-Minnesota’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 the policy.

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

At June 30, 2012, NSP-Minnesota had vehicle fuel contracts designated as cash flow hedges extending through December 2014.  NSP-Minnesota 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.  NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2012 and 2011.

At June 30, 2012, accumulated OCI related to commodity derivative cash flow hedges included immaterial amounts of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota 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 revenue, 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 June 30, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)
 
June 30, 2012
   
Dec. 31, 2011
 
Megawatt hours (MWh) of electricity
    60,527       37,522  
MMBtu of natural gas
    1,828       7,290  
Gallons of vehicle fuel
    275       330  

(a)
Amounts are not reflective of net positions in the underlying commodities.
(b)
Notional amounts for options are also 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 and six months ended June 30, 2012 and 2011, on OCI, regulatory assets and liabilities, and income:

   
Three Months Ended June 30, 2012
 
   
Fair Value Gains (Losses)
   
Pre-Tax (Gains) Losses Reclassified
       
   
Recognized During the Period in:
   
into Income During the Period from:
       
   
Accumulated
         
Accumulated
         
Pre-Tax Gains
 
   
Other
   
Regulatory
   
Other
   
Regulatory
   
Recognized
 
   
Comprehensive
   
(Assets) and
   
Comprehensive
   
Assets and
   
During the Period
 
(Thousands of Dollars)   Loss     Liabilities     Loss     (Liabilities)     in Income  
Derivatives designated as cash flow hedges
                             
Interest rate
  $ (28,532 )   $ -     $ (27 ) (a)   $ -     $ -  
Vehicle fuel and other commodity
    (118 )     -       (30 ) (e)     -       -  
Total
  $ (28,650 )   $ -     $ (57 )   $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 1,588
  (b)
Electric commodity
    -       38,174       -       (9,714 ) (c)     -  
Natural gas commodity
    -       96       -       -       -  
Total
  $ -     $ 38,270     $ -     $ (9,714 )   $ 1,588  
                                         
    Six Months Ended June 30, 2012  
    Fair Value Gains (Losses)    
Pre-Tax (Gains) Losses Reclassified
       
   
Recognized During the Period in:
   
into Income During the Period from:
       
   
Accumulated
           
Accumulated
           
Pre-Tax Gains
 
   
Other
   
Regulatory
   
Other
   
Regulatory
   
Recognized
 
   
Comprehensive
   
(Assets) and
   
Comprehensive
   
Assets and
   
During the Period
 
(Thousands of Dollars)   Loss    
Liabilities
   
Loss
   
(Liabilities)
   
in Income
 
Derivatives designated as cash flow hedges
                                       
Interest rate
  $ (7,745 )   $ -     $ (54 ) (a)   $ -     $ -  
Vehicle fuel and other commodity
    (15 )     -       (58 ) (e)     -       -  
Total
  $ (7,760 )   $ -     $ (112 )   $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 3,311
  (b)
Electric commodity
    -       39,756       -       (17,685 ) (c)     -  
Natural gas commodity
    -       (2,564 )     -       16,158   (d)     -  
Total
  $ -     $ 37,192     $ -     $ (1,527 )   $ 3,311  
 
 
    Three Months Ended June 30, 2011  
    Fair Value Gains (Losses)     Pre-Tax (Gains) Losses Reclassified        
    Recognized During the Period in:     into Income During the Period from:        
    Accumulated           Accumulated           Pre-Tax Gains  
    Other     Regulatory     Other     Regulatory     Recognized  
    Comprehensive     (Assets) and     Comprehensive     Assets and     During the Period  
(Thousands of Dollars)   Income     Liabilities    
Income
    (Liabilities)     in Income  
Derivatives designated as cash flow hedges
                                       
Interest rate
  $ -     $ -     $ (27 ) (a)   $ -     $ -  
Vehicle fuel and other commodity
    (36 )     -       (33 ) (e)     -       -  
Total
  $ (36 )   $ -     $ (60 )   $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 1,320  (b)
Electric commodity
    -       10,299       -       (8,666 ) (c)     -  
Natural gas commodity
    -       (1,534 )     -       -       -  
Total
  $ -     $ 8,765     $ -     $ (8,666 )   $ 1,320  
                                         
    Six Months Ended June 30, 2011  
    Fair Value Gains (Losses)     Pre-Tax (Gains) Losses Reclassified          
    Recognized During the Period in:     into Income During the Period from:          
    Accumulated           Accumulated           Pre-Tax Gains  
   
Other
    Regulatory     Other     Regulatory     Recognized  
    Comprehensive     (Assets) and     Comprehensive     Assets and     During the Period  
(Thousands of Dollars)   Income     Liabilities     Income     (Liabilities)     in Income  
Derivatives designated as cash flow hedges
                                       
Interest rate
  $ -     $ -     $ (54 ) (a)   $ -     $ -  
Vehicle fuel and other commodity
    177       -       (55 ) (e)     -       -  
Total
  $ 177     $ -     $ (109 )   $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 6,675  (b)
Electric commodity
    -       19,145       -       (17,555 ) (c)     -  
Natural gas commodity
    -       (3,553 )     -       10,928   (d)     -  
Total
  $ -     $ 15,592     $ -     $ (6,627 )   $ 6,675  
 
(a)
Recorded to interest charges.
(b)
Recorded to electric operating revenues.  Portions of these gains and losses are shared 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 operating and maintenance (O&M) expenses.
 
 
NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2012 and 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 NSP-Minnesota enters into may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings.  At June 30, 2012, contracts underlying $21.2 million of derivative instruments in a gross liability position would require NSP-Minnesota to post collateral or settle applicable contracts if the credit ratings of NSP-Minnesota are downgraded below investment grade, however, at June 30, 2012, these derivative liabilities were offset by derivative assets with the applicable counterparties, and therefore such a downgrade would not result in payments to these counterparties.  If the credit ratings of NSP-Minnesota were downgraded below investment grade, contracts underlying $1.4 million of derivative instruments in a gross liability position at Dec. 31, 2011 would have required NSP-Minnesota to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $0.1 million.  At June 30, 2012 and Dec. 31, 2011, there was no collateral posted on these specific contracts.

Certain of NSP-Minnesota’s 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 NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired.  NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2012 and Dec. 31, 2011.

Recurring Fair Value Measurements  The following table presents, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012:

   
June 30, 2012
 
   
Fair Value
                   
                     
Fair Value
   
Counterparty
       
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Total
   
Netting (b)
   
Total
 
Current derivative assets
                                   
Derivatives designated as cash flow hedges:
                                   
Vehicle fuel and other commodity
  $ -     $ 49     $ -     $ 49     $ -     $ 49  
Other derivative instruments:
                                               
Trading commodity
    79       25,408       -       25,487       (7,622 )     17,865  
Electric commodity
    -       -       35,664       35,664       (1,875 )     33,789  
Natural gas commodity
    -       98       -       98       (19 )     79  
Total current derivative assets
  $ 79     $ 25,555     $ 35,664     $ 61,298     $ (9,516 )     51,782  
Purchased power agreements (a)
                                            23,109  
Current derivative instruments
                                          $ 74,891  
                                                 
Noncurrent derivative assets
                                               
Derivatives designated as cash flow hedges:
                                               
Vehicle fuel and other commodity
  $ -     $ 32     $ -     $ 32     $ (32 )   $ -  
Other derivative instruments:
                                               
Trading commodity
    -       31,482       -       31,482       (2,729 )     28,753  
Total noncurrent derivative assets
  $ -     $ 31,514     $ -     $ 31,514     $ (2,761 )     28,753  
Purchased power agreements (a)
                                            43,061  
Noncurrent derivative instruments
                                          $ 71,814  
 
 
   
June 30, 2012
 
   
Fair Value
                   
                     
Fair Value
   
Counterparty
       
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Total
   
Netting (b)
   
Total
 
Current derivative liabilities
                                   
Derivatives designated as cash flow hedges:
                                   
Interest rate
  $ -     $ 35,864     $ -     $ 35,864     $ -     $ 35,864  
Other derivative instruments:
                                               
Trading commodity
    112       19,868       -       19,980       (9,036 )     10,944  
Electric commodity
    -       -       1,875       1,875       (1,875 )     -  
Natural gas commodity
    -       2       -       2       (2 )     -  
Total current derivative liabilities
  $ 112     $ 55,734     $ 1,875     $ 57,721     $ (10,913 )     46,808  
Purchased power agreements (a)
                                            13,851  
Current derivative instruments
                                          $ 60,659  
                                                 
Noncurrent derivative liabilities
                                               
Other derivative instruments:
                                               
Trading commodity
  $ -     $ 16,683     $ -     $ 16,683     $ (2,761 )   $ 13,922  
Total noncurrent derivative liabilities
  $ -     $ 16,683     $ -     $ 16,683     $ (2,761 )     13,922  
Purchased power agreements (a)
                                            166,094  
Noncurrent derivative instruments
                                          $ 180,016  

(a)
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b)
The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following tables present, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

   
Dec. 31, 2011
 
   
Fair Value
                   
                     
Fair Value
   
Counterparty
       
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Total
   
Netting (b)
   
Total
 
Current derivative assets
                                   
Derivatives designated as cash flow hedges:
                                   
Vehicle fuel and other commodity
  $ -     $ 93     $ -     $ 93     $ -     $ 93  
Other derivative instruments:
                                               
Trading commodity
    -       26,133       -       26,133       (9,679 )     16,454  
Electric commodity
    -       -       13,333       13,333       (1,471 )     11,862  
Total current derivative assets
  $ -     $ 26,226     $ 13,333     $ 39,559     $ (11,150 )     28,409  
Purchased power agreements (a)
                                            23,108  
Current derivative instruments
                                          $ 51,517  
                                                 
Noncurrent derivative assets
                                               
Derivatives designated as cash flow hedges:
                                               
Vehicle fuel and other commodity
  $ -     $ 59     $ -     $ 59     $ (59 )   $ -  
Other derivative instruments:
                                               
Trading commodity
    -       28,307       -       28,307       (2,234 )     26,073  
Total noncurrent derivative assets
  $ -     $ 28,366     $ -     $ 28,366     $ (2,293 )     26,073  
Purchased power agreements (a)
                                            54,616  
Noncurrent derivative instruments
                                          $ 80,689  
 
 
   
Dec. 31, 2011
 
   
Fair Value
                   
                     
Fair Value
   
Counterparty
       
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Total
   
Netting (b)
   
Total
 
Current derivative liabilities
                                   
Derivatives designated as cash flow hedges:
                                   
Interest rate
  $ -     $ 28,119     $ -     $ 28,119     $ -     $ 28,119  
Other derivative instruments:
                                               
Trading commodity
    -       21,816       -       21,816       (11,647 )     10,169  
Electric commodity
    -       698       916       1,614       (1,471 )     143  
Natural gas commodity
    -       13,499       -       13,499       -       13,499  
Total current derivative liabilities
  $ -     $ 64,132     $ 916     $ 65,048     $ (13,118 )     51,930  
Purchased power agreements (a)
                                            13,851  
Current derivative instruments
                                          $ 65,781  
                                                 
Noncurrent derivative liabilities
                                               
Other derivative instruments:
                                               
Trading commodity
  $ -     $ 13,464     $ -     $ 13,464     $ (2,293 )   $ 11,171  
Total noncurrent derivative liabilities
  $ -     $ 13,464     $ -     $ 13,464     $ (2,293 )     11,171  
Purchased power agreements (a)
                                            173,019  
Noncurrent derivative instruments
                                          $ 184,190  

(a)
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b)
The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2012 and 2011:
 
   
Three Months Ended June 30
 
(Thousands of Dollars)
 
2012
   
2011
 
Balance at April 1
  $ 5,324     $ 2,332  
Purchases
    37,296       33,609  
Settlements
    (12,675 )     (8,211 )
Net transactions recorded during the period:
               
Gains recognized in earnings (a)
    -       4  
Gains (losses) recorded as regulatory assets and liabilities
    3,844       (23,738 )
Balance at June 30
  $ 33,789     $ 3,996  
                 
   
Six Months Ended June 30
 
(Thousands of Dollars)
  2012     2011  
Balance at Jan. 1
  $ 12,417     $ 2,392  
Purchases
    37,297       33,609  
Settlements
    (21,560 )     (16,001 )
Net transactions recorded during the period:
               
(Losses) gains recognized in earnings (a)
    (9 )     72  
Gains (losses) recorded as regulatory assets and liabilities
    5,644       (16,076 )
Balance at June 30
  $ 33,789     $ 3,996  
 
(a)
These amounts relate to commodity derivatives held at the end of the period.
 
NSP-Minnesota recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for the three and six months ended June 30, 2012 and 2011.
 
 
Fair Value of Long-Term Debt
 
As of June 30, 2012 and Dec. 31, 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
   
June 30, 2012
   
Dec. 31, 2011
 
   
Carrying
         
Carrying
       
(Thousands of Dollars)
 
Amount
   
Fair Value
   
Amount
   
Fair Value
 
Long-term debt, including current portion
  $ 3,339,401     $ 4,046,627     $ 3,338,897     $ 4,066,367  

The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of June 30, 2012 and Dec. 31, 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

9. 
Other Income (Expense), Net

Other income (expense), net consisted of the following:
   
Three Months Ended June 30
   
Six Months Ended June 30
 
(Thousands of Dollars)
 
2012
   
2011
   
2012
   
2011
 
Interest (expense) income
  $ (83 )   $ (126 )   $ 3,756     $ 2,953  
Other nonoperating income
    168       138       472       332  
Insurance policy expense
    (967 )     (1,217 )     (2,705 )     (1,606 )
Other (expense) income, net
  $ (882 )   $ (1,205 )   $ 1,523     $ 1,679  

10. 
Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Minnesota’s chief operating decision maker.  NSP-Minnesota evaluates performance based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each reportable segment.

NSP-Minnesota has the following reportable segments: regulated electric, regulated natural gas and all other.

·
NSP-Minnesota’s regulated electric utility segment generates electricity which is transmitted and distributed in Minnesota, North Dakota and South Dakota.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.
·
NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota.
·
Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from continuing operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
 
 
   
Regulated
   
Regulated
   
All
   
Reconciling
   
Consolidated
 
(Thousands of Dollars)
 
Electric
   
Natural Gas
   
Other
   
Eliminations
   
Total
 
Three Months Ended June 30, 2012
                             
Operating revenues from external customers
  $ 908,050     $ 59,069     $ 5,417     $ -     $ 972,536  
Intersegment revenues
    144       139       -       (283 )     -  
Total revenues
  $ 908,194     $ 59,208     $ 5,417     $ (283 )   $ 972,536  
Net income (loss)
  $ 64,921     $ (2,811 )   $ 2,202     $ -     $ 64,312  
                                         
Three Months Ended June 30, 2011
                                       
Operating revenues from external customers
  $ 908,070     $ 96,922     $ 5,534     $ -     $ 1,010,526  
Intersegment revenues
    171       148       -       (319 )     -  
Total revenues
  $ 908,241     $ 97,070     $ 5,534     $ (319 )   $ 1,010,526  
Net income
  $ 61,870     $ 74     $ 3,279     $ -     $ 65,223  
                                         
Six Months Ended June 30, 2012
                                       
Operating revenues from external customers
  $ 1,782,434     $ 255,583     $ 11,292     $ -     $ 2,049,309  
Intersegment revenues
    267       380       -       (647 )     -  
Total revenues
  $ 1,782,701     $ 255,963     $ 11,292     $ (647 )   $ 2,049,309  
Net income
  $ 124,202     $ 11,486     $ 5,610     $ -     $ 141,298  
                                         
Six Months Ended June 30, 2011
                                       
Operating revenues from external customers
  $ 1,812,207     $ 380,648     $ 10,563     $ -     $ 2,203,418  
Intersegment revenues
    296       339       -       (635 )     -  
Total revenues
  $ 1,812,503     $ 380,987     $ 10,563     $ (635 )   $ 2,203,418  
Net income
  $ 130,174     $ 21,149     $ 6,075     $ -     $ 157,398  

11. 
Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

   
Three Months Ended June 30
 
   
2012
   
2011
   
2012
   
2011
 
               
Postretirement Health
 
(Thousands of Dollars)
 
Pension Benefits
   
Care Benefits
 
Service cost
  $ 7,336     $ 8,015     $ 24     $ 23  
Interest cost
    12,301       13,043       1,814       1,911  
Expected return on plan assets
    (16,836 )     (18,528 )     (109 )     (144 )
Amortization of transition obligation
    -       -       336       336  
Amortization of prior service cost (credit)
    2,955       3,293       (30 )     (30 )
Amortization of net loss
    10,196       7,707       853       607  
Net periodic benefit cost
    15,952       13,530       2,888       2,703  
Cost not recognized due to the effects of regulation
    (9,083 )     (10,140 )     -       -  
Net benefit cost recognized for financial reporting
  $ 6,869     $ 3,390     $ 2,888     $ 2,703  
 
 
   
Six Months Ended June 30
 
   
2012
   
2011
   
2012
   
2011
 
               
Postretirement Health
 
(Thousands of Dollars)
 
Pension Benefits
   
Care Benefits
 
Service cost
  $ 14,706     $ 14,008     $ 48     $ 44  
Interest cost
    24,610       25,973       3,565       3,686  
Expected return on plan assets
    (33,658 )     (37,121 )     (219 )     (288 )
Amortization of transition obligation
    -       -       673       673  
Amortization of prior service cost (credit)
    5,910       6,585       (59 )     (59 )
Amortization of net loss
    20,065       14,368       1,602       1,174  
Net periodic benefit cost
    31,633       23,813       5,610       5,230  
Cost not recognized due to the effects of regulation
    (17,141 )     (17,450 )     -       -  
Net benefit cost recognized for financial reporting
  $ 14,492     $ 6,363     $ 5,610     $ 5,230  

In January 2012, contributions of $190.5 million were made across four of Xcel Energy’s pension plans, of which $79.3 million was attributable to NSP-Minnesota.  Xcel Energy does not expect additional pension contributions during 2012.

In June 2012, to manage volatility in equity pricing within the pension master trust, Xcel Energy entered into equity collar contracts with a net-zero cost at initiation on a portion of the equity securities.  The equity collar strategy is designed to reduce potential equity losses while limiting gains, resulting in lower equity volatility for the pension plans.  At June 30, 2012, the mark-to-market value of these arrangements was not material to the value of the pension trust assets.  These arrangements will expire in December 2012.

Item 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries.  It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on NSP-Minnesota’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements.  Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.
 
 
Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by  regulatory bodies; availability or cost of capital; employee workforce factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2011, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.
 
Results of Operations

NSP-Minnesota’s net income was approximately $141.3 million for the six months ended June 30, 2012, compared with approximately $157.4 million for the same period in 2011. The decrease is primarily due to the unfavorable impact of warmer than normal winter weather, higher property taxes, higher O&M expenses and sluggish electric sales, which were partially offset by the positive impact of summer weather and a lower effective tax rate.

Electric Revenues and Margins

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin.  The following table details the electric revenues and margin:

    Six Months Ended June 30  
(Millions of Dollars)   2012     2011  
Electric revenues
  $ 1,782     $ 1,812  
Electric fuel and purchased power
    (727 )     (753 )
Electric margin
  $ 1,055     $ 1,059  
 
 
The following summarizes the components of the changes in electric revenues and margin for the six months ended June 30:

Electric Revenues
 
(Millions of Dollars)
 
2012 vs. 2011
 
Fuel and purchased power cost recovery
  $ (16 )
Differences in Minnesota retail rates (2011 interim compared to 2012 settlement) (a)
    (8 )
Conservation revenue (offset by expenses)
    (7 )
Estimated impact of weather
    (7 )
Trading
    (6 )
Retail sales decrease (excluding weather impact)
    (5 )
Transmission revenue
    10  
Retail rate increases (North Dakota and South Dakota)
    5  
Interchange agreement billing with NSP-Wisconsin
    4  
Total decrease in electric revenues
  $ (30 )

(a)
NSP-Minnesota reduced depreciation expense and revenues by approximately $16 million in the first half of 2012 to reflect the settlement in the Minnesota electric rate case.

Electric Margin
 
(Millions of Dollars)
 
2012 vs. 2011
 
Differences in Minnesota retail rates (2011 interim compared to 2012 settlement) (a)
  $ (8 )
Conservation revenue (offset by expenses)
    (7 )
Estimated impact of weather
    (7 )
Retail sales decrease (excluding weather impact)
    (5 )
Transmission revenue, net of costs
    6  
Interchange agreement billing with NSP-Wisconsin
    6  
Retail rate increases (North Dakota and South Dakota)
    5  
Other, net
    6  
Total decrease in electric margin
  $ (4 )

(a)
NSP-Minnesota reduced depreciation expense and revenues by approximately $16 million in the first half of 2012 to reflect the settlement in the Minnesota electric rate case.
 
Natural Gas Revenues and Margins
 
The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases.  However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.  The following table details natural gas revenues and margin:
 
    Six Months Ended June 30  
(Millions of Dollars)   2012     2011  
Natural gas revenues
  $ 256     $ 381  
Cost of natural gas sold and transported
    (160 )     (258 )
Natural gas margin
  $ 96     $ 123  
 
 
The following summarizes the components of the changes in natural gas revenues and margin for the six months ended June 30:

Natural Gas Revenues

(Millions of Dollars)
 
2012 vs. 2011
 
Purchased natural gas adjustment clause recovery
  $ (98 )
Estimated impact of weather
    (15 )
Conservation revenue (offset by expenses)
    (11 )
Other, net
    (1 )
Total decrease in natural gas revenues
  $ (125 )

Natural Gas Margin

(Millions of Dollars)
 
2012 vs. 2011
 
Estimated impact of weather
  $ (15 )
Conservation revenue (offset by expenses)
    (11 )
Other, net
    (1 )
Total decrease in natural gas margin
  $ (27 )

Non-Fuel Operating Expenses and Other Items

O&M Expenses O&M expenses increased $15.8 million, or 3.1 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The following summarizes the components of the changes for the six months ended June 30:

(Millions of Dollars)
 
2012 vs. 2011
 
Higher employee benefit costs
  $ 8  
Higher plant generation costs
    6  
Other, net (including management cost savings initiatives)
    2  
Total increase in O&M expenses
  $ 16  

 
·
Higher employee benefit costs are primarily due to higher pension expense.
 
·
Higher plant generation costs related to increased labor costs for outages and overhauls in 2012.

Conservation Program Expenses Conservation program expenses decreased $18.2 million, or 26.7 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The decrease is primarily attributable to a lower gas rider rate, as well as the timing of recovery of electric conservation improvement program expenses.  Conservation program expenses are generally recovered in major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization Depreciation and amortization expense decreased $5.9 million, or 2.9 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  This decrease is primarily due to a change in depreciation lives for certain assets to reflect the settlement in the Minnesota and South Dakota electric rate cases, resulting in a reduction in depreciation expense of $16 million, partially offset by normal system expansion.

Taxes (Other Than Income Taxes) Taxes (other than income taxes) increased $16.2 million, or 18.8 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The increases are due to an increase in property taxes primarily in Minnesota.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased $4.6 million, or 14.8 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The decrease is primarily due to construction projects related to the Monticello extended power uprate that went into service in 2011.
 
 
Income Taxes — Income tax expense decreased $27.6 million for the first six months of 2012, compared with the same period in 2011.  The decrease in income tax expense was primarily due to lower pretax earnings and a tax benefit associated with a carryback.  The effective tax rate was 27.8 percent for the first six months of 2012, compared with 34.3 percent for the same period in 2011.  The lower effective tax rate for the first six months of 2012 was primarily due to the completion of 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, NSP-Minnesota recognized a discrete tax benefit of approximately $15 million.  Without this tax benefit, the effective tax rate for the first six months of 2012 would have been 35.5 percent.

Public Utility Regulation

NSP System Resource Plans In December 2011, NSP-Minnesota filed an update to the 2011 through 2025 resource plan with the MPUC.  To account for slower projected economic growth and the loss of NSP-Wisconsin’s wholesale customers, NSP-Minnesota modified the current plan to include a recommendation to withdraw the Black Dog repowering project certificate of need (CON) and to reassess the wind procurement plan and resource contingency plan in detail.  In May 2012, an ALJ granted NSP-Minnesota’s request to withdraw the CON application; the ALJ decision is pending MPUC action.

The resource plan update also notified the MPUC that there have been changes in the size, timing, and cost estimates for the extended power uprate project at the Prairie Island nuclear generating plant.  In March 2012, NSP-Minnesota made a change of circumstances (COC) filing providing a new economic and project design analysis and seeking MPUC guidance before proceeding with the extended power uprate project.  The COC filing indicated the costs of the Prairie Island uprate project have increased, and the cost savings relative to other resource options have declined and may even be negative under certain assumptions.  The COC filing is pending MPUC action.  Some elements of the resource plan remain unchanged such as the extension of certain contracts, the Monticello nuclear generating plant extended power uprate project and the commitment to specific conservation improvement program annual achievements.

CapX2020 CON In 2009, the MPUC granted CONs to construct one 230 kilovolt (KV) electric transmission line and three 345 KV electric transmission lines as part of the CapX2020 project.  The estimated cost of the four major transmission projects is $1.9 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total cost.  The remainder of the costs will be borne by other utilities in the upper Midwest.  These cost estimates will be revised after the regulatory process is completed.

The MPUC has issued route permits for the Minnesota portion of the Fargo, N.D. to St. Cloud, Minn. project, the Brookings, S.D. project, the Bemidji, Minn. to Grand Rapids, Minn. project and for the portions of the new transmission lines between Hampton, Minn. and La Crosse, Wis. to be constructed in Minnesota.  In June 2011, the SDPUC approved a facility permit for a portion of the Brookings, S.D. project.  The North Dakota Public Service Commission granted a CPCN in January 2011.  It is expected the NDPSC will approve the remaining required Certificate of Corridor Compatibility and Route Permit activities in North Dakota in August 2012.

In December 2011, the Monticello, Minn. to St. Cloud, Minn. 345 KV project was placed in service and MISO granted the final approval of the Brookings, S.D. project as a multi-value project.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards.  State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters.  See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011.  In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000)  In July 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development.  On April 18, 2012, the Minnesota Governor signed legislation that preserves the rights of incumbent utilities to construct and own transmission interconnected to their systems.  This legislation is similar to the legislation previously passed in North Dakota and South Dakota.  Therefore, Order 1000 is expected to have limited impacts on future transmission development and ownership in the NSP System in Minnesota, North Dakota, and South Dakota.  The NSP System is the integrated electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is managed by NSP-Minnesota. Compliance filings to address these new requirements are due October 2012, and are effective prospectively.
 
 
In May 2012, the FERC issued Order 1000-A, its order on rehearing of Order 1000.  Order 1000-A declined all motions for rehearing and offered limited clarification of aspects of the final rule.  Several parties filed requests for clarification of Order 1000-A.  Several appeals of Order 1000 have also been filed and these appeals have been consolidated into the D.C. Circuit.  These appeals are expected to be heard over the next 12 months with a ruling expected sometime in mid-2013.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant.  See Note 12 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 for further discussion regarding the nuclear generating plants.  Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes.  The discharge and handling of such wastes are controlled by federal regulation.  High-level radioactive wastes primarily include used nuclear fuel.  Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact the operations of the nuclear generating plants.  The event at the nuclear generating plant in Fukushima, Japan in 2011 could impact the NRC’s deliberations on NSP-Minnesota’s power uprates and could also result in additional regulation, which could require additional capital expenditures or operating expenses.  The NRC has created an internal task force that has developed recommendations on whether it should require immediate emergency preparedness and mitigating enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures, and licensing processes.  In July 2011, the task force released its recommendations in a written report which recommends actions to enhance U.S. nuclear generating plant readiness to safely manage severe events.

In March 2012, the NRC issued three orders and a request for additional information to all licensees.  The orders included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation, and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant.  The request for additional information included requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards, and to assess the emergency preparedness staffing and communications capabilities at each plant.  NSP-Minnesota expects that complying with these requirements will cost approximately $20 to $50 million at the Monticello and Prairie Island plants.  Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance begin in the second quarter of 2015 with all units being fully compliant by December 2016.  NSP-Minnesota believes the costs associated with compliance 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.

NRC Waste Confidence Decision (WCD) — In June 2012, the D.C. Circuit issued a ruling to vacate and remand the NRC’s WCD.  The WCD assesses how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available.  The D.C. Circuit remanded the WCD to the NRC and directed them to prepare an environmental impact statement if there are significant impacts or an environmental assessment to support a finding of no significant impact.  NSP-Minnesota is reviewing the decision and believes that there will not be an immediate impact for operations at the Prairie Island or Monticello nuclear generating plants.

Nuclear Plant Power Uprates

Prairie Island Nuclear Extended Power Uprate — In 2009, the MPUC approved a CON for an extended power uprate of approximately 164 MW for Prairie Island Units 1 and 2.  Recent analysis of the extended power uprate submittals to the NRC concluded that significant additional design work beyond NSP-Minnesota’s estimated schedule and cost plan would be required for a successful application submittal.  The analysis demonstrates the magnitude of the benefits is substantially lower than originally anticipated.  As a result, NSP-Minnesota completed an economic and new project design analysis and submitted a COC filing with the MPUC in March 2012.  As part of the analysis, potential prospective risks were identified that could further reduce the anticipated economic benefits of the project.  NSP-Minnesota asked the MPUC to confirm that the extended power uprate project is in the best interest of customers prior to NSP-Minnesota making the significant investments necessary to complete an application and undertake the NRC licensing process.  Public comments have been received both in support of and challenging the continuation of the project.  NSP-Minnesota is working to facilitate interaction between parties to ensure a common understanding of the benefits and challenges to the project before the MPUC renders a decision.  The COC filing is pending MPUC action.
 
 
Monticello Nuclear Plant Extended Power Uprate —  In 2008, NSP-Minnesota filed for both state and federal approvals of an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello nuclear generating plant.  The MPUC approved the CON for the extended power uprate in 2008.  The filing was placed on hold by the NRC staff to address concerns raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance.  NSP-Minnesota has been working with the industry and regulatory agencies to address this issue and expects to submit an update to the application for approval to the NRC in the fourth quarter of 2012, which could result in approval of the extended power uprate project by the NRC in the second quarter of 2013.  NSP-Minnesota is planning to implement the equipment changes needed to support the Monticello life extension and power uprate projects in the planned spring 2013 refueling outage.

Item 4 CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of June 30, 2012, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting.

Part II OTHER INFORMATION

Item 1 LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota.  NSP-Minnesota has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings.  See Note 5 to the consolidated financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2011, which is incorporated herein by reference.

Item 4 MINE SAFETY DISCLOSURES

None.

Item 5 OTHER INFORMATION

None.
 
 
Item 6 EXHIBITS

*Indicates incorporation by reference
Furnished, herewith, not filed.  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
 
3.01*
 
Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*
 
By-Laws of Northern Power Corp. as Amended on Aug. 1, 2000 and June 3, 2008 (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
 
Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
Statement pursuant to Private Securities Litigation Reform Act of 1995.
101 
 
The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.
 
 
SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
    Northern States Power Company (a Minnesota corporation)
     
Aug. 3, 2012
   
 
By:
/s/ JEFFREY S. SAVAGE
   
Jeffrey S. Savage
   
Vice President and Controller
     
   
/s/ TERESA S. MADDEN
   
Teresa S. Madden
   
Senior Vice President, Chief Financial Officer and Director
 
 
35