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EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER COex31_01.htm
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER COex99_01.htm
EX-32.02 - EXHIBIT 32.01 - NORTHERN STATES POWER COex32_01.htm


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 Sept. 30, 2010

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).  oYes  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 Nov. 1, 2010
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 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). Additional information on Xcel Energy is available on various filings with the Securities and Exchange Commission (SEC).




NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands of dollars)
 
   
Three Months Ended Sept. 30,
   
Nine Months Ended Sept. 30,
 
   
2010
   
2009
   
2010
   
2009
 
Operating revenues
                       
 Electric
  $ 1,068,416     $ 916,338     $ 2,761,268     $ 2,573,004  
 Natural gas
    57,211       48,271       397,831       452,054  
 Other
    5,286       4,750       15,211       14,088  
Total operating revenues
    1,130,913       969,359       3,174,310       3,039,146  
                                 
Operating expenses
                               
 Electric fuel and purchased power
    457,805       369,349       1,182,538       1,065,658  
 Cost of natural gas sold and transported
    28,810       24,643       269,356       329,370  
 Cost of sales — other
    3,159       2,849       8,729       7,864  
 Other operating and maintenance expenses
    258,015       233,232       770,603       721,962  
 Conservation program expenses
    21,511       14,381       56,962       41,784  
 Depreciation and amortization
    105,670       90,776       301,210       291,893  
 Taxes (other than income taxes)
    38,269       37,681       117,876       109,893  
 Total operating expenses
    913,239       772,911       2,707,274       2,568,424  
                                 
Operating income
    217,674       196,448       467,036       470,722  
                                 
Other income (expense), net
    1,766       (1,026 )     1,409       (1,168 )
Allowance for funds used during construction — equity
    9,197       6,876       26,698       21,247  
                                 
Interest charges and financing costs
                               
Interest charges — includes other financing costs of $1,405, $1,424, $4,216 and $4,371, respectively
    50,407       47,651       149,940       147,563  
Allowance for funds used during construction — debt
    (4,115 )     (4,285 )     (13,592 )     (13,237 )
Total interest charges and financing costs
    46,292       43,366       136,348       134,326  
                                 
Income before income taxes
    182,345       158,932       358,795       356,475  
Income taxes
    72,558       66,383       140,829       137,829  
Net income
  $ 109,787     $ 92,549     $ 217,966     $ 218,646  
 
See Notes to Consolidated Financial Statements


NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands of dollars)

   
Nine Months Ended Sept.  30,
 
   
2010
   
2009
 
Operating activities
           
 Net income
  $ 217,966     $ 218,646  
 Adjustments to reconcile net income to cash provided by operating activities:
               
 Depreciation and amortization
    300,455       295,941  
 Nuclear fuel amortization
    78,150       59,520  
 Deferred income taxes
    174,603       139,343  
 Amortization of investment tax credits
    (2,338 )     (2,628 )
 Allowance for equity funds used during construction
    (26,698 )     (21,247 )
 Net realized and unrealized hedging and derivative transactions
    (8,534 )     2,940  
 Changes in operating assets and liabilities:
               
 Accounts receivable
    10,061       130,467  
 Accrued unbilled revenues
    52,331       86,993  
 Inventories
    (13,889 )     77,658  
 Recoverable purchased natural gas and electric energy costs
    27,401       232  
 Other current assets
    (60,131 )     (16,378 )
 Accounts payable
    (146,757 )     (66,970 )
 Net regulatory assets and liabilities
    5,101       (25,529 )
 Other current liabilities
    (3,590 )     (5,094 )
 Change in other noncurrent assets
    284       (225 )
 Change in other noncurrent liabilities
    (14,620 )     (35,086 )
Net cash provided by operating activities
    589,795       838,583  
                 
Investing activities
               
 Utility capital/construction expenditures
    (892,638 )     (652,863 )
 Allowance for equity funds used during construction
    26,698       21,247  
 Purchase of investments in external decommissioning fund
    (3,309,093 )     (1,278,554 )
 Proceeds from sale of investments in external decommissioning fund
    3,314,356       1,276,417  
 Investments in utility money pool arrangement
    (55,500 )     (55,500 )
 Repayments from utility money pool arrangement
    62,500       55,500  
 Advances to affiliate
    (218,200 )     (33,400 )
 Advances from affiliate
    229,800       33,400  
 Other investments
    444       (1,041 )
Net cash used in investing activities
    (841,633 )     (634,794 )
                 
Financing activities
               
 Proceeds from short-term borrowings, net
    -       57,000  
 Borrowings under utility money pool arrangement
    657,500       469,300  
 Repayments under utility money pool arrangement
    (657,500 )     (415,800 )
 Proceeds from issuance of long-term debt
    493,609       -  
 Repayment of long-term debt
    (175,029 )     (250,024 )
 Capital contributions from parent
    211,431       132,728  
 Dividends paid to parent
    (174,569 )     (174,246 )
Net cash provided by (used in) financing activities
    355,442       (181,042 )
                 
Net increase in cash and cash equivalents
    103,604       22,747  
Cash and cash equivalents at beginning of period
    46,303       12,343  
Cash and cash equivalents at end of period
  $ 149,907     $ 35,090  
                 
Supplemental disclosure of cash flow information:
               
 Cash paid for interest, net of amounts capitalized
  $ (160,079 )   $ (163,623 )
 Cash (paid) received for income taxes, net
    (18,846 )     26,506  
Supplemental disclosure of non-cash investing transactions:
               
 Property, plant and equipment additions in accounts payable
  $ 36,193     $ 13,149  
 
See Notes to Consolidated Financial Statements


NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands of dollars)
 
 
 
Sept. 30, 2010
   
Dec. 31, 2009
 
Assets
           
Current assets
           
 Cash and cash equivalents
  $ 149,907     $ 46,303  
 Notes receivable from affiliates
    3,900       15,500  
 Investments in utility money pool arrangement
    -       7,000  
 Accounts receivable, net
    299,072       300,103  
 Accounts receivable from affiliates
    22,215       31,245  
 Accrued unbilled revenues
    177,007       229,338  
 Inventories
    269,808       255,919  
 Recoverable purchased natural gas and electric energy costs
    3,027       30,428  
 Derivative instruments valuation
    40,815       59,482  
 Prepayments and other
    130,798       81,688  
 Total current assets
    1,096,549       1,057,006  
                 
Property, plant and equipment, net
    7,559,038       6,958,656  
                 
Other assets
               
 Nuclear decommissioning fund and other investments
    1,330,622       1,264,687  
 Regulatory assets
    788,887       797,663  
 Derivative instruments valuation
    113,152       117,216  
 Other
    29,397       23,581  
 Total other assets
    2,262,058       2,203,147  
 Total assets
  $ 10,917,645     $ 10,218,809  
                 
Liabilities and Equity
               
Current liabilities
               
 Current portion of long-term debt
  $ 24     $ 175,037  
 Accounts payable
    302,804       407,500  
 Accounts payable to affiliates
    43,719       83,759  
 Taxes accrued
    131,674       125,650  
 Accrued interest
    40,243       62,780  
 Dividends payable to parent
    58,654       58,415  
 Derivative instruments valuation
    37,077       24,661  
 Other
    69,847       59,353  
 Total current liabilities
    684,042       997,155  
                 
Deferred credits and other liabilities
               
 Deferred income taxes
    1,427,199       1,234,366  
 Deferred investment tax credits
    34,796       37,134  
 Asset retirement obligations
    832,015       797,476  
 Regulatory liabilities
    485,495       469,769  
 Pension and employee benefit obligations
    314,663       310,066  
 Derivative instruments valuation
    206,451       209,528  
 Other
    98,759       83,965  
 Total deferred credits and other liabilities
    3,399,378       3,142,304  
                 
Commitments and contingent liabilities
               
Capitalization
               
 Long-term debt
    3,337,638       2,838,141  
 Common stock – authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares
    10       10  
 Additional paid-in capital
    2,240,023       2,028,593  
 Retained earnings
    1,254,051       1,210,894  
 Accumulated other comprehensive income
    2,503       1,712  
 Total common stockholder’s equity
    3,496,587       3,241,209  
 Total liabilities and equity
  $ 10,917,645     $ 10,218,809  
 
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 Sept. 30, 2010 and Dec. 31, 2009; the results of its operations for the three and nine months ended Sept. 30, 2010 and 2009; and its cash flows for the nine months ended Sept. 30, 2010 and 2009.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after Sept. 30, 2010 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, 2009 balance sheet information has been derived from the audited 2009 consolidated financial statements.  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 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, 2009, filed with the SEC on March 1, 2010.  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 NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.
 
2.   Accounting Pronouncements
 
Recently Adopted
 
Consolidation of Variable Interest Entities — In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the FASB Accounting Standards Codification (ASC or Codification) were effective for interim and annual periods beginning after Nov. 15, 2009.  NSP-Minnesota implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures regarding variable interest entities, see Note 6 to the consolidated financial statements.
 
Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (Accounting Standards Update (ASU) No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010.  NSP-Minnesota implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures, see Note 9 to the consolidated financial statements.
 
 
3.   Selected Balance Sheet Data
 
(Thousands of Dollars)
 
Sept. 30, 2010
   
Dec. 31, 2009
 
Accounts receivable, net
           
Accounts receivable
  $ 318,470     $ 322,778  
Less allowance for bad debts
    (19,398 )     (22,675 )
    $ 299,072     $ 300,103  
Inventories
               
Materials and supplies
  $ 114,520     $ 105,508  
Fuel
    90,582       99,705  
Natural gas
    64,706       50,706  
    $ 269,808     $ 255,919  
Property, plant and equipment, net
               
Electric plant
  $ 9,866,270     $ 9,679,288  
Natural gas plant
    967,411       948,708  
Common and other property
    494,374       472,624  
Construction work in progress
    1,134,542       587,080  
Total property, plant and equipment
    12,462,597       11,687,700  
Less accumulated depreciation
    (5,188,637 )     (5,030,836 )
Nuclear fuel
    1,798,905       1,737,469  
Less accumulated amortization
    (1,513,827 )     (1,435,677 )
    $ 7,559,038     $ 6,958,656  
 
4.   Income Taxes
 
Medicare Part D Subsidy Reimbursements  In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Based on this provision, NSP-Minnesota is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.
 
NSP-Minnesota expensed approximately $3.3 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  NSP-Minnesota does not expect the $3.3 million of additional tax expense to recur in future periods.  However, the 2010 effective tax rate (ETR) will increase due to additional tax expense of approximately $0.8 million associated with current year retiree health care accruals.
 
Federal AuditNSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  During the first quarter of 2010, the Internal Revenue Service (IRS) completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010.  The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return will expire in September 2011.  The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010.  As of Sept. 30, 2010, the IRS had not proposed any material adjustments to tax years 2008 and 2009.
 
State AuditsNSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Sept. 30, 2010, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006.  In 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years.  During the second quarter of 2010, the state of Minnesota informed Xcel Energy that its information requests related to the years 2002 through 2007 had been fulfilled and that the state does not intend to perform an audit on these years at this time.  There currently are 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 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)
 
Sept. 30, 2010
   
Dec. 31, 2009
 
Unrecognized tax benefit - Permanent tax positions
  $ 2.4     $ 2.7  
Unrecognized tax benefit - Temporary tax positions
    16.7       9.8  
Unrecognized tax benefit balance
  $ 19.1     $ 12.5  
 
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 were as follows:
 
(Millions of Dollars)
 
Sept. 30, 2010
   
Dec. 31, 2009
 
Tax benefits associated with NOL and tax credit carryforwards
  $ (3.9 )   $ (2.8 )
 
The increase in the unrecognized tax benefit balance of $4.7 million from June 30, 2010 to Sept. 30, 2010 and $6.6 million from Dec. 31, 2009 to Sept. 30, 2010 was due to the addition of uncertain tax positions related to current and prior years’ activity.  NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.
 
5.   Rate Matters
 
Except to the extent noted below, the circumstances set forth in Note 13 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.
 
Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)
 
Base Rate
 
NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $16.2 million for 2010, based on a return on equity (ROE) of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million.  The overall request seeks an additional $3.5 million, effective Jan. 1, 2011, for recovery of pension funding costs necessary to comply with federal law.  In December 2009, the MPUC approved an interim rate increase of $11.1 million, subject to refund.  Interim rates went into effect on Jan. 11, 2010.
 
NSP-Minnesota made several adjustments and is currently seeking an increase of $10.0 million based on a 10.6 percent ROE.  The Office of Energy Security (OES) revised its case and is now recommending an increase of approximately $7.5 million based on a 10.09 percent ROE.  NSP-Minnesota and the Minnesota Office of Attorney General (OAG) agreed on treatment of pension issues, for future rate proceedings, and NSP-Minnesota is no longer seeking a 2011 step-in of pension expense.  The OAG continued to recommend further adjustments in bad debt expense, distribution operating and maintenance (O&M) expenses and the cost of debt.
 
In October 2010, the administrative law judge (ALJ) issued his report and recommended a rate increase of approximately $8 million, based on a 10.09 percent ROE.  A decision from the MPUC is anticipated late in the fourth quarter of 2010.
 

Electric, Purchased Gas and Resource Adjustment Clauses
 
Transmission Cost Recovery (TCR) Rider — The MPUC has approved a TCR rider that allows annual adjustments to retail electric rates to provide recovery of certain incremental transmission investments between rate cases.  In April 2010, the MPUC approved the 2010 TCR rider that will recover approximately $10.8 million in 2010.  In October 2010, NSP-Minnesota filed its 2011 rider recovery request, seeking approval to recover approximately $12.9 million during 2011.
 
Renewable Energy Standard (RES) Rider — The MPUC has approved a RES rider to recover the costs for utility-owned projects implemented in compliance with the Minnesota RES.  In April 2010, the MPUC approved the 2010 RES rider that resulted in $38.4 million in revenue recovery beginning May 1, 2010.  In October 2010, NSP-Minnesota filed its 2011 rider recovery request, seeking approval to recover approximately $67.8 million during 2011.
 
State Energy Policy (SEP) Rider — In March 2010, NSP-Minnesota filed a request to recover approximately $2.5 million of Minnesota electric retail revenue requirements, and $0.7 million of natural gas retail revenue requirements during the July 2010-June 2011 timeframe related to SEP mandates.  In September 2010, the MPUC issued an order approving NSP-Minnesota’s petition with a rate implementation date of Oct. 1, 2010.
 
Metropolitan Emissions Reduction Project (MERP) Rider — In December 2009, the MPUC authorized NSP-Minnesota to recover the 2010 revenue requirements related to environmental improvement projects amounting to approximately $116.7 million in 2010 through the MERP rider.  In October 2010, NSP-Minnesota filed a request to recover approximately $111.4 million during 2011.  Final MPUC action is pending.
 
Renewable Development Fund (RDF) Rider  The MPUC has approved an RDF rider that allows annual adjustments to retail electric rates to provide for the recovery of RDF program and project expenses.  In June 2010, the MPUC authorized NSP-Minnesota to recover $22.9 million in RDF expenses in 2010 through the RDF rider.  The primary components of RDF costs are legislatively mandated expenses such as renewable energy production incentive payments, RDF grant project payments, and RDF program administrative costs.  In October 2010, NSP-Minnesota filed its annual request to recover $19.2 million in expenses for 2011.  Final MPUC action is pending.
 
Annual Automatic Adjustment Report for 2008/2009 — In September 2009, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2008 through June 30, 2009.  During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the fuel clause adjustment (FCA).  In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the purchased gas adjustment (PGA).  In June 2010, the OES filed comments recommending approval of the 2008/2009 natural gas automatic adjustment report.  FCA and PGA recovery remains provisional and potentially subject to refund until the MPUC issues an order approving the automatic adjustment report for the period.  Final MPUC action is pending.
 
Annual Automatic Adjustment Report for 2009/2010 — In September 2010, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2009 through June 30, 2010.  During that time period, $749.5 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the FCA.  In addition, approximately $354.5 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the PGA.  FCA and PGA recovery remains provisional and potentially subject to refund until the MPUC issues an order approving the automatic adjustment report for the period.  Final MPUC action is pending.
 
6.   Commitments and Contingent Liabilities
 
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 13, 14 and 15 to the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 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.
 

Commitments
 
Variable Interest Entities  Effective Jan. 1, 2010, NSP-Minnesota adopted new guidance on consolidation of variable interest entities contained in ASC 810 Consolidation.  The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.
 
Purchased Power Agreements  NSP-Minnesota has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.
 
NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2034.  In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments.  Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.
 
NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants.  Under certain purchased power agreements with these entities, 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 NSP-Minnesota purchases.  These purchased power agreements have been determined by NSP-Minnesota to create variable interests in the independent power producing entities; therefore, certain independent power producing entities are variable interest entities.
 
NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.
 
NSP-Minnesota has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, historical and estimated future fuel and electricity prices, and financing activities.  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.  As of Sept. 30, 2010 and Dec. 31, 2009, NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.
 
Environmental Contingencies
 
NSP-Minnesota has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, NSP-Minnesota believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense.
 
Site Remediation — NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including sites of former manufactured gas plants operated by NSP-Minnesota, its predecessors or other entities; and third party sites, such as landfills, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes.  At Sept. 30, 2010 and Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.3 million, of which $0.2 million was considered to be a current liability.
 
Third Party and Other Environmental Site Remediation
 
Asbestos Removal — Some of NSP-Minnesota’s facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated.  NSP-Minnesota has recorded an estimate for final removal of the asbestos as an asset retirement obligation.  See additional discussion of asset retirement obligations in Note 14 of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2009.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.
 

Other Environmental Requirements
 
Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Rulemaking — In December 2009, in response to the U.S. Supreme Court’s decision in Massachusetts vs. EPA, 549 U.S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere.  The EPA has promulgated permit requirements for GHGs for large new and modified stationary sources, such as power plants.  These regulations will become applicable in 2011.
 
Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions.  The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota.  In 2008, the U.S. Court of Appeals for the District of Columbia vacated and remanded CAIR.  In July 2010, the EPA issued the proposed Clean Air Transport Rule (CATR), which would replace CAIR by requiring SO2 and NOx reductions in 31 states and the District of Columbia.  The EPA is proposing to reduce these emissions through federal implementation plans for each affected state.  The EPA’s preferred approach would set emission limits for each state and allow limited interstate emissions trading.  As proposed, CATR will impact Minnesota for annual SO2 and NOx emissions.  NSP-Minnesota is analyzing the proposed rule to determine whether emission reductions are needed from its facilities.  Until CATR becomes final, NSP-Minnesota will continue activities to support CAIR compliance.  In November 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective in December 2009.  Cost estimates are therefore not included at this time for NSP-Minnesota.
 
Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules.  The EPA has agreed to finalize Maximum Achievable Control Technology emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace the CAMR.  NSP-Minnesota anticipates that the EPA will require affected facilities to demonstrate compliance within three to five years.
 
Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants.  For NSP-Minnesota, the Act covers units at the A.S. King and Sherco generating facilities.  NSP-Minnesota installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.
 
In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A.S. King mercury emission reduction plans.  A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A.S. King scheduled for December 2010.  In November 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.
 
In December 2009, NSP-Minnesota filed its mercury control plan at Sherco Units 1 and 2 with the MPUC and the Minnesota Pollution Control Agency (MPCA).  In June 2010, the MPCA filed its comments on the Sherco Unit 1 and 2 mercury plan and believes the plan to be appropriate under the Act.  The MPUC is expected to either approve or disapprove the plan by Dec. 15, 2010.  Assuming that the plan is approved, NSP-Minnesota expects to file for recovery of the costs to implement the plan through the mercury cost recovery rider.
 
Regional Haze Rules  In June 2005, the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.
 
NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft state implementation plan (SIP) that are equivalent to the reductions made under CAIR.
 

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 visibility impairment and, if so, whether the level of controls proposed by MPCA is appropriate.
 
The MPCA determined that this certification does not alter the proposed SIP.  The SIP proposes BART controls for the Sherco generating facilities that are designed to improve visibility in the national parks, but does not require Selective Catalytic Reduction (SCR) on Units 1 and 2.  The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs.  In December 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval.  The EPA is expected to complete its review of the SIP, as well as the Sherco Units 1 and 2 BART determination before the end of 2010.
 
Federal Clean Water Act — The federal Clean Water Act (CWA) requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts.  In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants.  Several lawsuits were filed against the EPA challenging the phase II rulemaking.  In April 2009, the U.S. Supreme Court issued a decision in Entergy Corp. vs. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds, the rule’s compliance requirements and associated deadlines will remain unknown.  As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.
 
As part of NSP-Minnesota’s 2009 CWA permit renewal for the Black Dog plant, the MPCA required that the plant submit a plan for compliance with the CWA.  The compliance plan was submitted for MPCA review and approval in April 2010.  The MPCA is currently reviewing the proposal in consultation with the EPA.  NSP-Minnesota anticipates approval of the plan by the end of 2010.
 
Proposed Coal Ash Regulation —  In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as a special waste (subject to many of the requirements for hazardous waste) or as a solid (nonhazardous) waste.  Coal ash is currently exempt from hazardous waste regulation.  The EPA’s proposal would result in more comprehensive and expensive requirements related to management and disposal of coal ash.  The EPA has extended the public comment period on the proposed rule until Nov. 19, 2010.  The EPA is also seeking comment on what regulations are appropriate for the beneficial reuse of coal ash.  The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.
 
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 of them.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Minnesota’s financial position and results of operations.
 
Environmental Litigation
 
State of Connecticut vs. Xcel Energy Inc. et al. In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of NSP-Minnesota, to force reductions in carbon dioxide (CO2) emissions.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by each company is a public nuisance.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds.  On appeal in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the lower court decision.  In August 2010, defendants filed a petition for review with the U.S. Supreme Court.
 

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of NSP-Minnesota, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds.  Plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit.  In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court.  A subsequent petition by defendants, including Xcel Energy, for en banc review was granted.  On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit ruled that it lacked an en banc quorum of nine active members to hear the case.  It dismissed the appeal, which resulted in the reinstatement of the district court’s opinion dismissing the case.  Plaintiffs subsequently filed with the U.S. Supreme Court a writ of mandamus, which is a procedure requesting the court to order the Fifth Circuit to review plaintiffs’ earlier appeal.  Defendants intend to oppose this request.
 
Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 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, the parent company of NSP-Minnesota, and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 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.  All briefs related to this appeal have been filed.  It is unknown when the Ninth Circuit will render a final opinion.
 
United States vs. Xcel Energy Inc. et al. — In June 2010, the U.S. Department of Justice and the EPA filed a complaint in the U.S. District Court in Minnesota against Xcel Energy, alleging that Xcel Energy has failed to fully respond to certain information requests issued by the EPA.  Over the last ten years, Xcel Energy has responded to numerous information requests from the EPA pursuant to section 114 of the Clean Air Act (CAA).  The requests focused on past projects undertaken at Xcel Energy’s Sherco and Black Dog plants to determine whether these projects were carried out in compliance with the New Source Review requirements.  Xcel Energy has complied with these requests and produced thousands of pages of documents.  In June 2009, the EPA issued a supplemental information request which, among other things, asked for ten years of prospective capital project documentation related to projects that may be undertaken in the future at the plants.  Xcel Energy believed that the request for future project information exceeded the EPA’s CAA authority and filed a motion to dismiss the lawsuit.  The EPA filed a motion for preliminary injunction in which it narrowed its request to two years of prospective capital project documentation.  On Sept. 27, 2010, the court denied Xcel Energy’s motion to dismiss and ruled that two years of future documentation is reasonable, but rejected the request for ten years of documentation.  The court granted the EPA’s motion for a preliminary injunction and ruled that a limited set of responsive documents be produced.  Xcel Energy is complying with this order.
 
Employment, Tort and Commercial Litigation
 
Siewert vs. Xcel Energy — In 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems.  Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system.  Plaintiffs claim losses of approximately $7 million.  NSP-Minnesota denies all allegations.  In December 2008, the Court of Appeals issued a decision ordering dismissal of plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial.  The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review and heard oral arguments in December 2009.  It is uncertain when the Minnesota Supreme Court will render a decision.
 
Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota.  At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004.  In September 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In December 2007, the court denied the DOE’s motion for reconsideration.  In February 2008, the DOE filed an appeal to the U.S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue.  It is uncertain when the Court will issue a decision.  Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved.  Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.
 
 
In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U.S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract.  This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel.  Per the court’s scheduling order, NSP-Minnesota believes that it has suffered damages in excess of $250 million.  The DOE claims NSP-Minnesota is entitled to at most approximately $55 million.  Trial is expected to take place in early 2011.
 
EnviroTech Remediation Services, Inc. vs. Brandenburg Industrial Services Co., NSP- Minnesota, et al. — In 2009, a mechanic’s lien foreclosure lawsuit was served against NSP-Minnesota by EnviroTech Remediation Services, Inc. (EnviroTech), and other defendants.  EnviroTech’s claims against NSP-Minnesota arise out of mechanics’ liens recorded by EnviroTech and its subcontractors against NSP-Minnesota’s High Bridge generating plant property in St. Paul, Minn., in the amount of approximately $7.0 million plus attorneys’ fees and interest.  EnviroTech is a subcontractor to Brandenburg Industrial Services Co. (Brandenburg), a general construction company hired by NSP-Minnesota to perform demolition services and asbestos and lead abatement work at the old High Bridge generating plant.  Brandenburg subcontracted part of its asbestos and lead abatement work to EnviroTech.  EnviroTech claims it and its subcontractors furnished additional work and materials during performance of the Brandenburg/EnviroTech subcontract.  EnviroTech seeks additional compensation from Brandenburg and NSP-Minnesota for the claimed extra work and materials.  Further, EnviroTech notified NSP-Minnesota of an additional $3.0 million claim in the lawsuit for destruction of business against Brandenburg and NSP-Minnesota.
 
In June 2010, NSP-Minnesota participated in court-ordered mediation with EnviroTech and Brandenburg.  The parties did not reach resolution at the mediation, but subsequently reached a settlement in principle.  The parties continue to work to finalize settlement terms.
 
7.   Short-Term Borrowings and Other Financing Instruments
 
Commercial Paper — At Sept. 30, 2010 and Dec. 31, 2009, NSP-Minnesota had no commercial paper outstanding.  The total commercial paper available for issuance was $482 million.
 
Money Pool Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other.  The holding company 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 the holding company.
 
The following table presents money pool investments for NSP-Minnesota:
 
(Millions of Dollars)
 
Sept. 30, 2010
   
Dec. 31, 2009
 
Money pool investments
  $ -     $ 7  
Weighted average interest rate
    N/A       0.36 %
Money pool borrowing limit
  $ 250     $ 250  
 
8.   Long-Term Borrowings and Other Financing Instruments
 
In August 2010, NSP-Minnesota issued $250 million of 1.95 percent first mortgage bonds, series due Aug. 15, 2015 and $250 million of 4.85 percent first mortgage bonds, series due Aug. 15, 2040.  NSP-Minnesota added the net proceeds from the sale of the bonds to its general funds and applied a portion of the proceeds to the repayment of short-term debt, including short-term debt incurred to fund the repayment at maturity of $175 million of 4.75 percent first mortgage bonds due Aug. 1, 2010.  The balance of the net proceeds was used for general corporate purposes, including the funding of capital expenditures.
 
 
9.   Derivative Instruments and 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.
 
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 instruments.  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.
 
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 a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.
 
At Sept. 30, 2010, accumulated other comprehensive income (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.
 
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, gas for resale, and vehicle fuel.
 
At Sept. 30, 2010, NSP-Minnesota had vehicle fuel related contracts designated as cash flow hedges extending through December 2012.  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 nine months ended Sept. 30, 2010 and 2009.
 
At Sept. 30, 2010, accumulated OCI related to commodity derivative cash flow hedges included $0.4 million of net losses 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 income, subject to applicable customer margin-sharing mechanisms.
 
The following table details the gross notional amounts of commodity forwards, options, and financial transmission rights at Sept. 30, 2010 and Dec. 31, 2009:
 
(Amounts in Thousands) (a)(b)
 
Sept. 30, 2010
   
Dec. 31, 2009
 
Megawatt hours (MWh) of electricity
    52,812       34,374  
MMBtu of natural gas
    16,928       9,777  
Gallons of vehicle fuel
    670       2,021  
 
(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.

 
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated OCI, included as a component of common stockholder’s equity, is detailed in the following table:
             
     Three Months Ended Sept. 30,  
(Thousands of Dollars)
 
2010
   
2009
 
Accumulated other comprehensive income related to cash flow hedges at July 1
  $ 4,368     $ 4,797  
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges
    25       (6,533 )
After-tax net realized losses on derivative transactions reclassified into earnings
    306       471  
Accumulated other comprehensive income (loss) related to cash flow hedges at Sept. 30
  $ 4,699     $ (1,265 )

     Nine Months Ended Sept. 30,  
(Thousands of Dollars)
 
2010
   
2009
 
Accumulated other comprehensive income related to cash flow hedges at Jan. 1
  $ 3,941     $ 3,053  
After-tax net unrealized losses related to derivatives accounted for as hedges
    (108 )     (5,972 )
After-tax net realized losses on derivative transactions reclassified into earnings
    866       1,654  
Accumulated other comprehensive income (loss) related to cash flow hedges at Sept. 30
  $ 4,699     $ (1,265 )
 
NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2010 and Sept. 30, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions for these periods were recognized.
 
The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2010 and Sept. 30, 2009, respectively, on OCI, regulatory assets and liabilities, and income:
                                
   
Three Months Ended Sept. 30, 2010
 
    Fair Value Changes Recognized During the Period in:     Pre-Tax Amounts Reclassified into Income During the Period from:        
(Thousands of Dollars)
 
Other Comprehensive Income (Loss)
   
Regulatory Assets and Liabilities
   
Other Comprehensive Income (Loss)
   
Regulatory Assets and Liabilities
   
Pre-Tax Gains Recognized During the Period in Income
 
Derivatives designated as cash flow hedges
                             
Interest rate
  $ -     $ -     $ (27 )(a)   $ -     $ -  
Vehicle fuel and other commodity
    42       -       548
(e)
    -       -  
Total
  $ 42     $ -     $ 521     $ -     $ -  
                                         
Other derivative instruments
                                     
 
Trading commodity
   -      -      -      -      4,888 (b)
Electric commodity
    -       6,569       -       (8,259 )(c)     -  
Natural gas commodity
    -       (11,794 )     -       -       -  
Total
  $ -     $ (5,225 )   $ -     $ (8,259
)
 
$ 4,888  
 
 
   
Nine Months Ended Sept. 30, 2010
 
   
Fair Value Changes Recognized During the Period in:
   
Pre-Tax Amounts Reclassified into Income During the Period from:
       
(Thousands of Dollars)
 
Other Comprehensive Income (Loss)
   
Regulatory Assets and Liabilities
   
Other Comprehensive Income (Loss)
   
Regulatory Assets and Liabilities
   
Pre-Tax Gains Recognized During the Period in Income
 
Derivatives designated as cash flow hedges
                             
Interest rate
  $ -     $ -     $ (81 )(a)   $ -     $ -  
Vehicle fuel and other commodity
    (184 )     -       1,548 (e)     -       -  
Total
  $ (184 )   $ -     $ 1,467     $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 11,015 (b)
Electric commodity
    -       (3,014 )     -       (13,097 )(c)     -  
Natural gas commodity
    -       (19,638 )     -       586 (d)     -  
Total
  $ -     $ (22,652 )   $ -     $ (12,511 )   $ 11,015  

   
Three Months Ended Sept. 30, 2009
 
   
Fair Value Changes Recognized During the Period in:
   
Pre-Tax Amounts Reclassified into Income During the Period from:
       
(Thousands of Dollars)
 
Other Comprehensive Income (Loss)
   
Regulatory Assets and Liabilities
   
Other Comprehensive Income (Loss)
   
Regulatory Assets and Liabilities
   
Pre-Tax Gains Recognized During the Period in Income
 
Derivatives designated as cash flow hedges
                             
Interest rate
  $ (10,865 )   $ -     $ (54 )(a)   $ -     $ -  
Vehicle fuel and other commodity
    (182 )     -       852 (e)     -       -  
Total
  $ (11,047 )   $ -     $ 798     $ -     $ -  
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 3,200 (b)
Electric commodity
    -       (8,012 )     -       1,284 (c)     -  
Natural gas commodity
    -       6,527       -       -       -  
Total
  $ -     $ (1,485 )   $ -     $ 1,284     $ 3,200  
 
 
   
Nine Months Ended Sept.  30, 2009
 
   
Fair Value Changes Recognized During the Period in:
    Pre-Tax Amounts Reclassified into Income During the Period from:        
(Thousands of Dollars)
 
Other Comprehensive Income (Loss)
   
Regulatory Assets and Liabilities
    Other Comprehensive Income (Loss)    
Regulatory Assets and Liabilities
    Pre-Tax Gains (Losses) Recognized During the Period in Income  
Derivatives designated as cash flow hedges
                             
Interest rate
  $ (10,865 )   $ -     $ (161 )(a)   $ -     $ -  
Electric commodity
            (18,600 )             (4,755 )(c)        
Natural gas commodity
    -       (810 )     -       8,915 (d)     (6,951 )(d)
Vehicle fuel and other commodity
    767       -       2,959 (e)     -       -  
Total
  $ (10,098 )   $ (19,410 )   $ 2,798     $ 4,160     $ (6,951 )
                                         
Other derivative instruments
                                       
Trading commodity
  $ -     $ -     $ -     $ -     $ 4,724 (b)
Electric commodity
    -       35,329       -       898 (c)     -  
Natural gas commodity
    -       5,451       -       -       -  
Other
    -       -       -       -       200 (b)
Total
  $ -     $ 40,780     $ -     $ 898     $ 4,924  
 
(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 other O&M expenses.
 
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. If the credit ratings at NSP-Minnesota at Sept. 30, 2010 and Dec. 31, 2009 were downgraded below investment grade, no contracts underlying NSP-Minnesota’s derivative liabilities would have required the posting of collateral or contract settlement upon the downgrade.
 
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. As of Sept. 30, 2010 and Dec. 31, 2009, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.
 
Fair Value Measurements
 
ASC 820 Fair Value Measurements and Disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:
 
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported 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 reported 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 reported date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
 
 
Recurring Fair Value Measurements
 
The following table presents, for each of the hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at Sept. 30, 2010:
                                     
   
Sept. 30, 2010
 
   
Fair Value
                   
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Fair Value Total
   
Counterparty Netting (c)
   
Total
 
Current derivative assets
                                   
Derivatives designated as cash flow hedges:
                                   
Vehicle fuel and other commodity
  $ -     $ 31     $ -     $ 31     $ (31 )   $ -  
Other derivative instruments:
                                               
Trading commodity
    260       19,638       1       19,899       (8,168 )     11,731  
Electric commodity
    -       -       5,282       5,282       (1,129 )     4,153  
Total current derivative assets
  $ 260     $ 19,669     $ 5,283     $ 25,212     $ (9,328 )     15,884  
Purchased power agreements (b)
                                            24,931  
Current derivative instruments valuation
                                          $ 40,815  
Noncurrent derivative assets
                                               
Derivatives designated as cash flow hedges:
                                               
Vehicle fuel and other commodity
  $ -     $ 57     $ -     $ 57     $ -     $ 57  
Other derivative instruments:
                                               
Trading commodity
    -       34,334       -       34,334       (4,741 )     29,593  
Total noncurrent derivative assets
  $ -     $ 34,391     $ -     $ 34,391     $ (4,741 )     29,650  
Purchased power agreements (b)
                                            83,502  
Noncurrent derivative instruments valuation
                                          $ 113,152  
Other recurring fair value assets
                                               
Cash equivalents
  $ -     $ 65,000     $ -     $ 65,000     $ -     $ 65,000  
Nuclear decommissioning fund: (a)
                                               
Cash equivalents
    -       42,117       -       42,117       -       42,117  
Commingled funds
    -       114,845       -       114,845       -       114,845  
International equity funds
    -       57,155       -       57,155       -       57,155  
Debt securities:
                                               
Government securities
    -       209,806       -       209,806       -       209,806  
U.S. corporate bonds
    -       317,295       -       317,295       -       317,295  
Foreign securities
    -       2,258       -       2,258       -       2,258  
Municipal bonds
    -       81,759       -       81,759       -       81,759  
Asset-backed securities
    -       -       34,494       34,494       -       34,494  
Mortgage-backed securities
    -       -       64,396       64,396       -       64,396  
Equity securities (common stock)
    390,993       -       -       390,993       -       390,993  
Total nuclear decommissioning fund
  $ 390,993     $ 825,235     $ 98,890     $ 1,315,118     $ -     $ 1,315,118  
 
 
   
Sept. 30, 2010
 
   
Fair Value
                   
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Fair Value Total
   
Counterparty Netting (c)
   
Total
 
Current derivative liabilities
                                   
Derivatives designated as cash flow hedges:
                                   
Vehicle fuel and other commodity
  $ -     $ 465     $ -     $ 465     $ (31 )   $ 434  
Other derivative instruments:
                                               
Trading commodity
    52       15,448       6       15,506       (10,969 )     4,537  
Electric commodity
    -       -       1,130       1,130       (1,130 )     -  
Natural gas commodity
    577       17,678       -       18,255       -       18,255  
Total current derivative liabilities
  $ 629     $ 33,591     $ 1,136     $ 35,356     $ (12,130 )     23,226  
Purchased power agreements (b)
                                            13,851  
Current derivative instruments valuation
                                          $ 37,077  
Noncurrent derivative liabilities
                                               
Other derivative instruments:
                                               
Trading commodity
  $ -     $ 20,669     $ -     $ 20,669     $ (4,741 )   $ 15,928  
Natural gas commodity
    -       190       -       190       -       190  
Total noncurrent derivative liabilities
  $ -     $ 20,859     $ -     $ 20,859     $ (4,741 )     16,118  
Purchased power agreements (b)
                                            190,333  
Noncurrent derivative instruments valuation
                                          $ 206,451  
 
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $15.5 million of miscellaneous investments.
(b)
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, 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.
(c)
ASC 815 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.
 
NSP-Minnesota recognizes transfers between levels as of the beginning of each period. The following table presents the transfers that occurred between levels during the three and nine months ended Sept. 30, 2010.
             
   
From Level 3 to Level 2 (a) (b)
 
(Thousands of Dollars)
 
Three Months Ended
Sept. 30, 2010
   
Nine Months Ended
Sept. 30, 2010
 
Trading commodity derivatives not designated as cash flow hedges:
           
Current assets
  $ 569     $ 5,384  
Noncurrent assets
    12,313       21,450  
Current liabilities
    (776 )     (2,851 )
Noncurrent liabilities
    (8,436 )     (12,345 )
Total
  $ 3,670     $ 11,638  
 
(a) 
The transfer of amounts from Level 3 to Level 2 is due to the valuation of certain long term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.
(b) 
There were no transfers of amounts from Level 2 to Level 3.

 
The following tables present, for each of the hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2009:

   
Dec. 31, 2009
 
   
Fair Value
                   
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Fair Value Total
   
Counterparty Netting (c)
   
Total
 
Current derivative assets
                                   
Other derivative instruments:
                                   
Trading commodity
  $ -     $ 13,748     $ 6,253     $ 20,001     $ (11,640 )   $ 8,361  
Electric commodity
    -       -       23,540       23,540       1,425       24,965  
Natural gas commodity
    -       1,580       -       1,580       54       1,634  
Total current derivative assets
  $ -     $ 15,328     $ 29,793     $ 45,121     $ (10,161 )     34,960  
Purchased power agreements (b)
                                            24,522  
 Current derivative instruments valuation
                                          $ 59,482  
Noncurrent derivative assets
                                               
Derivatives designated as cash flow hedges:
                                               
Vehicle fuel and other commodity
  $ -     $ 85     $ -     $ 85     $ -     $ 85  
Other derivative instruments:
                                               
Trading commodity
    -       7,040       11,610       18,650       (4,193 )     14,457  
Natural gas commodity
    -       31       -       31       1       32  
Total noncurrent derivative assets
  $ -     $ 7,156     $ 11,610     $ 18,766     $ (4,192 )     14,574  
Purchased power agreements (b)
                                            102,642  
Noncurrent derivative instruments valuation
                                          $ 117,216  
Other recurring fair value assets
                                               
Nuclear decommissioning fund: (a)
                                               
 Cash equivalents
  $ -     $ 28,134     $ -     $ 28,134     $ -     $ 28,134  
 Debt securities:
                                               
Government securities
    -       74,126       -       74,126       -       74,126  
U.S. corporate bonds
    -       312,844       -       312,844       -       312,844  
Foreign securities
    -       9,445       -       9,445       -       9,445  
Municipal bonds
    -       149,088       -       149,088       -       149,088  
Asset-backed securities
    -       -       11,918       11,918       -       11,918  
Mortgage-backed securities
    -       -       81,189       81,189       -       81,189  
Equity securities (common stock)
    581,995       -       -       581,995       -       581,995  
Total nuclear decommissioning fund
  $ 581,995     $ 573,637     $ 93,107     $ 1,248,739     $ -     $ 1,248,739  
 
 
   
Dec. 31, 2009
 
   
Fair Value
                   
(Thousands of Dollars)
 
Level 1
   
Level 2
   
Level 3
   
Fair Value Total
   
Counterparty Netting (c)
   
Total
 
Current derivative liabilities
                                   
Derivatives designated as cash flow hedges:
                                   
Vehicle fuel and other commodity
  $ -     $ 1,905     $ -     $ 1,905     $ -     $ 1,905  
Other derivative instruments:
                                               
Trading commodity
    -       14,248       3,731       17,979       (15,503 )     2,476  
Electric commodity
    -       -       3,276       3,276       1,425       4,701  
Natural gas commodity
    -       640       -       640       54       694  
Other commodity
    -       -       360       360       -       360  
Total current derivative liabilities
  $ -     $ 16,793     $ 7,367     $ 24,160     $ (14,024 )     10,136  
Purchased power agreements (b)
                                            14,525  
Current derivative instruments valuation
                                          $ 24,661  
Noncurrent derivative liabilities
                                               
Other derivative instruments:
                                               
Trading commodity
  $ -     $ 4,895     $ 6,799     $ 11,694     $ (4,197 )   $ 7,497  
Natural gas commodity
    -       364       -       364       1       365  
Total noncurrent derivative liabilities
  $ -     $ 5,259     $ 6,799     $ 12,058     $ (4,196 )     7,862  
Purchased power agreements (b)
                                            201,666  
Noncurrent derivative instruments valuation
                                          $ 209,528  
 
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $17.0 million of miscellaneous investments.
(b)
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, 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.
(c)
ASC 815 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 methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options.  Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers.  Electric commodity derivatives include financial transmission rights (FTRs), for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management’s forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.

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.


Cash equivalents are recorded at cost plus accrued interest to approximate fair value.  Changes in the observed trading prices and liquidity of cash equivalents, including money market funds, are also monitored as additional support for determining fair value.  Equity securities are valued using quoted prices in active markets.  The fair values for commingled funds and international equity funds 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.  Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated prepayments.  Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.

The following tables present the changes in Level 3 recurring fair value measurements for the three and nine months ended Sept. 30, 2010 and 2009:
 
    Three Months Ended Sept. 30,  
    2010     2009  
          Nuclear Decommissioning
Fund
          Nuclear Decommissioning
Fund
 
(Thousands of Dollars)
  Commodity
Derivatives,
Net
   
Mortgage-
Backed
Securities
   
Asset-
Backed
Securities
   
Commodity
Derivatives,
Net
   
Mortgage-
Backed
Securities
   
Asset-Backed
Securities
 
Balance at July 1
  $ 9,207     $ 65,059     $ 40,067     $ 46,637     $ 72,230     $ 14,107  
Purchases and settlements, net
    1,029       (1,949 )     (5,744 )     (265 )     7,332       (1,542 )
Transfers (out of) into Level 3
    (3,670 )     -       -       720       -       -  
(Losses) gains recognized in earnings
    (9,110 )     -       -       2,228       -       -  
Gains (losses) recognized as regulatory assets and liabilities
    6,691       1,286       171       (6,688 )     5,820       286  
Balance at Sept. 30
  $ 4,147     $ 64,396     $ 34,494     $ 42,632     $ 85,382     $ 12,851  
 
   
Nine Months Ended Sept. 30,
 
    2010     2009  
          Nuclear Decommissioning
Fund
          Nuclear Decommissioning
Fund
 
(Thousands of Dollars)
 
Commodity
Derivatives,
Net
    Mortgage-
Backed
Securities
   
Asset-
Backed
Securities
   
Commodity
Derivatives,
Net
   
Mortgage-
Backed
Securities
   
Asset-Backed
Securities
 
Balance at Jan. 1
  $ 27,237     $ 81,189     $ 11,918     $ 23,247     $ 98,461     $ 10,962  
Purchases and settlements, net
    133       (21,647 )     22,189       (316 )     (22,702 )     366  
Transfers (out of) into Level 3
    (11,638 )     -       -       701       -       -  
Losses recognized in earnings
    (8,364 )     -       -       (2,603 )     -       -  
(Losses) gains recognized as regulatory assets and liabilities
    (3,221 )     4,854       387       21,603       9,623       1,523  
Balance at Sept. 30
  $ 4,147     $ 64,396     $ 34,494     $ 42,632     $ 85,382     $ 12,851  
 
Losses on Level 3 commodity derivatives recognized in earnings for the three and nine months ended Sept. 30, 2010 include $1.6 million of net unrealized losses and $4.5 million of net unrealized gains, respectively, relating to commodity derivatives held at Sept. 30, 2010.  Gains and losses on Level 3 commodity derivatives recognized in earnings for the three and nine months ended Sept. 30, 2009 include $3.4 million and $4.9 million of net unrealized gains, respectively, relating to commodity derivatives held at Sept. 30, 2009.  Realized and unrealized gains and losses on commodity trading activities are included in electric revenues.  Realized and unrealized gains and losses on non-trading derivative instruments are recorded in OCI or deferred as regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.
 
 
10.   Financial Instruments

The estimated fair values of NSP-Minnesota’s recorded financial instruments are as follows:
 
    Sept. 30, 2010     Dec. 31, 2009  
(Thousands of Dollars)
 
Carrying
Amount
   
Fair Value
   
Carrying
Amount
   
Fair Value
 
Nuclear decommissioning fund
  $ 1,315,118     $ 1,315,118     $ 1,248,739     $ 1,248,739  
Other investments
    50       50       695       695  
Long-term debt, including current portion
    3,337,662       3,834,629       3,013,178       3,238,854  
 
The fair value of cash and cash equivalents, notes and accounts receivable, notes and accounts payable and short-term debt are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.   The fair value of NSP-Minnesota’s nuclear decommissioning fund is based on published trading data and pricing models, generally using the most observable inputs available for each class of security.  The fair values of NSP-Minnesota’s other investments are estimated based on quoted market prices for those or similar investments.  The fair value of NSP-Minnesota’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Sept. 30, 2010 and Dec. 31, 2009.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.

Letters of Credit NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Sept. 30, 2010 and Dec. 31, 2009, there were $6.4 million and $6.9 million of letters of credit outstanding, respectively.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

11. Other Income (Expense), Net

Other income (expense), net, consisted of the following:

   
Three Months Ended Sept. 30,
   
Nine Months Ended Sept. 30,
 
(Thousands of Dollars)
 
2010
   
2009
   
2010
   
2009
 
Interest income
  $ 3,291     $ 1,270     $ 4,485     $ 3,574  
Other nonoperating income
    5       23       27       -  
Insurance policy expense
    (1,516 )     (2,319 )     (3,068 )     (4,725 )
Other nonoperating expense
    (14 )     -       (35 )     (17 )
Other income (expense), net
  $ 1,766     $ (1,026 )   $ 1,409     $ (1,168 )
 
12. Segment Information

NSP-Minnesota has the following reportable segments:  regulated electric, regulated natural gas and all other.  Commodity trading operations are not a reportable segment and are included in the regulated electric segment.  All other revenues 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.
 
(Thousands of Dollars)
 
Regulated
Electric
   
Regulated
Natural Gas
   
All
Other
   
Reconciling
Eliminations
   
Consolidated
Total
 
Three Months Ended Sept. 30, 2010
                             
Operating revenues from external customers
  $ 1,068,416     $ 57,211     $ 5,286     $ -     $ 1,130,913  
Intersegment revenues
    160       4,030       -       (4,190 )     -  
Total revenues
  $ 1,068,576     $ 61,241     $ 5,286     $ (4,190 )   $ 1,130,913  
Segment net income (loss)
  $ 119,385     $ (8,674 )   $ (924 )   $ -     $ 109,787  
                                         
Three Months Ended Sept. 30, 2009
                                       
Operating revenues from external customers
  $ 916,338     $ 48,271     $ 4,750     $ -     $ 969,359  
Intersegment revenues
    90       354       -       (444 )     -  
Total revenues
  $ 916,428     $ 48,625     $ 4,750     $ (444 )   $ 969,359  
Segment net income (loss)
  $ 98,538     $ (6,837 )   $ 848     $ -     $ 92,549  
                                         
(Thousands of Dollars)
 
Regulated
Electric
   
Regulated
Natural Gas
   
All
Other
   
Reconciling
Eliminations
   
Consolidated
Total
 
Nine Months Ended Sept. 30, 2010
                                       
Operating revenues from external customers
  $ 2,761,268     $ 397,831     $ 15,211     $ -     $ 3,174,310  
Intersegment revenues
    308       7,797       -       (8,105 )     -  
Total revenues
  $ 2,761,576     $ 405,628     $ 15,211     $ (8,105 )   $ 3,174,310  
Segment net income
  $ 205,762     $ 7,535     $ 4,669     $ -     $ 217,966  
                                         
Nine Months Ended Sept. 30, 2009
                                       
Operating revenues from external customers
  $ 2,573,004     $ 452,054     $ 14,088     $ -     $ 3,039,146  
Intersegment revenues
    282       1,469       -       (1,751 )     -  
Total revenues
  $ 2,573,286     $ 453,523     $ 14,088     $ (1,751 )   $ 3,039,146  
Segment net income
  $ 202,257     $ 11,054     $ 5,335     $ -     $ 218,646  
 
13. Comprehensive Income

The components of total comprehensive income are shown below:

   
Three Months Ended Sept. 30,
   
Nine Months Ended Sept. 30,
 
(Thousands of Dollars)
 
2010
   
2009
   
2010
   
2009
 
Net income
  $ 109,787     $ 92,549     $ 217,966     $ 218,646  
Other comprehensive income (loss):
                               
Unrealized gains (losses) — marketable securities
    54       89       (43 )     333  
Changes in unrecognized amounts of pension and retiree medical benefits
    26       33       76       97  
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges
    25       (6,533 )     (108 )     (5,972 )
After-tax net realized losses on derivative transactions reclassified into earnings
    306       471       866       1,654  
Other comprehensive income (loss)
    411       (5,940 )     791       (3,888 )
Comprehensive income
  $ 110,198     $ 86,609     $ 218,757     $ 214,758  

 
14.  Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.

Components of Net Periodic Benefit Cost
 
   
Three Months Ended Sept. 30,
 
   
2010
   
2009
   
2010
   
2009
 
(Thousands of Dollars)
 
Pension Benefits
   
Postretirement Health
Care Benefits
 
Xcel Energy Inc.
                       
Service cost
  $ 18,286     $ 16,365     $ 1,002     $ 1,166  
Interest cost
    41,253       42,448       10,695       12,603  
Expected return on plan assets
    (58,080 )     (64,135 )     (7,132 )     (5,694 )
Amortization of transition obligation
    -       -       3,611       3,611  
Amortization of prior service cost (credit)
    5,165       6,155       (1,233 )     (681 )
Amortization of net loss
    12,078       3,114       2,910       4,832  
Net periodic benefit cost
    18,702       3,947       9,853       15,837  
Costs not recognized and additional cost recognized due to the effects of regulation
    (6,630 )     (723 )     972       972  
Net benefit cost recognized for financial reporting
  $ 12,072     $ 3,224     $ 10,825     $ 16,809  
                                 
NSP-Minnesota
                               
Net periodic benefit cost
  $ 8,377     $ 723     $ 2,660     $ 3,355  
Costs not recognized due to the effects of regulation
    (6,630 )     (723 )     -       -  
Net benefit cost recognized for financial reporting
  $ 1,747     $ -     $ 2,660     $ 3,355  
 
   
Nine Months Ended Sept. 30,
 
   
2010
   
2009
   
2010
   
2009
 
(Thousands of Dollars)
 
Pension Benefits
   
Postretirement Health
Care Benefits
 
Xcel Energy Inc.
                       
Service cost
  $ 54,860     $ 49,095     $ 3,005     $ 3,499  
Interest cost
    123,758       127,343       32,085       37,809  
Expected return on plan assets
    (174,239 )     (192,404 )     (21,397 )     (17,082 )
Amortization of transition obligation
    -       -       10,833       10,833  
Amortization of prior service cost (credit)
    15,493       18,464       (3,699 )     (2,044 )
Amortization of net loss
    36,236       9,342       8,732       14,497  
Net periodic benefit cost
    56,108       11,840       29,559       47,512  
Costs not recognized and additional cost recognized due to the effects of regulation
    (20,270 )     (2,169 )     2,918       2,918  
Net benefit cost recognized for financial reporting
  $ 35,838     $ 9,671     $ 32,477     $ 50,430  
                                 
NSP-Minnesota
                               
Net periodic benefit cost
  $ 25,131     $ 2,169     $ 7,982     $ 10,064  
Costs not recognized due to the effects of regulation
    (20,270 )     (2,169 )     -       -  
Net benefit cost recognized for financial reporting
  $ 4,861     $ -     $ 7,982     $ 10,064  
 

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).

Forward-Looking Statements

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 the 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.

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 the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; 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; 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; environmental laws and regulations; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing 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, 2009, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2010.

Market Risks

NSP-Minnesota is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31, 2009.  Commodity price and interest rate risks for NSP- Minnesota are mitigated in most jurisdictions due to cost-based rate regulation.

NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning.  Those investments are exposed to price fluctuations in equity markets and changes in interest rates.  However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in investment fair value do not affect NSP-Minnesota’s consolidated results of operations.  Distress in the financial markets may impact the fair value of the debt and equity securities in the nuclear decommissioning trust funds, and pension and postretirement health care plan trusts, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash.  As of Sept. 30, 2010, there have been no material changes to market risks from that set forth in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009.

Results of Operations

NSP-Minnesota’s net income was approximately $218.0 million for the first nine months of 2010, compared with approximately $218.6 million for the first nine months of 2009. Earnings slightly declined for the first nine months of 2010 largely due to higher O&M expenses and depreciation expense, offset by the positive impact of warmer temperatures and weather normalized sales growth in the current quarter.
 

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 tables detail the electric revenues and margin:
 
   
Nine Months Ended Sept. 30,
 
(Millions of Dollars)
 
2010
   
2009
 
Electric revenues
  $ 2,761     $ 2,573  
Electric fuel and purchased power
    (1,183 )     (1,066 )
Electric margin
  $ 1,578     $ 1,507  
 
The following summarizes the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30:

Electric Revenues
 
(Millions of Dollars)
   
2010 vs. 2009
 
Fuel and purchased power cost recovery
 
$
74
 
Estimated impact of weather
   
40
 
Interchange agreement billing with NSP-Wisconsin
   
26
 
Conservation revenue and incentive (partially offset by expenses)
   
24
 
Non-fuel riders
   
22
 
Retail rate increase (South Dakota)
   
8
 
Retail sales increase (excluding weather impact)
   
6
 
Firm wholesale
   
(16
)
Other, net
   
4
 
Total increase in electric revenues
 
$
188
 
 
Electric Margin
 
(Millions of Dollars)
   
2010 vs. 2009
 
Estimated impact of weather
 
$
40
 
Conservation revenue and incentive (partially offset by expenses)
   
24
 
Non-fuel riders
   
22
 
Interchange agreement billing with NSP-Wisconsin
   
11
 
Retail rate increase (South Dakota)
   
8
 
Retail sales increase (excluding impact of weather)
   
6
 
Firm wholesale
   
(9
)
Deferred fuel adjustments
   
(20
)
Other, net
   
(11
)
Total increase in electric margin
 
$
71
 
 
Natural Gas Revenues and Margins

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases.  However, due to purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.  The following tables detail natural gas revenues and margin:
 
   
Nine Months Ended Sept. 30,
 
(Millions of Dollars)
 
2010
   
2009
 
Natural gas revenues
  $ 398     $ 452  
Cost of natural gas sold and transported
    (269 )     (329 )
Natural gas margin
  $ 129     $ 123  
 
The following summarizes the components of the changes in natural gas revenues and margin for the nine months ended Sept. 30:

Natural Gas Revenues
 
(Millions of Dollars)
 
2010 vs. 2009
 
Purchased natural gas adjustment clause recovery
  $ (54 )
Estimated impact of weather
    (6 )
Conservation revenue and incentive (partially offset by expenses)
    5  
Rate increase (Minnesota interim)
    4  
Other, net
    (3 )
Total decrease in natural gas revenues
  $ (54 )
 
Natural Gas Margin
 
(Millions of Dollars)
   
2010 vs. 2009
 
Conservation revenue and incentive (partially offset by expenses)
 
$
5
 
Rate increase (Minnesota interim)
   
4
 
Estimated impact of weather
   
(6
)
Other, net
   
3
 
Total increase in natural gas margin
 
$
6
 
 
Non-Fuel Operating Expense and Other Items

O&M Expenses O&M expenses for the first nine months of 2010 increased $48.6 million, or 6.7 percent, compared with the first nine months of 2009.  The following summarizes the components of the changes for the nine months ended Sept. 30:
 
(Millions of Dollars)
   
2010 vs. 2009
 
Higher employee benefit costs
 
$
11
 
Nuclear outage costs, net of deferral
   
10
 
Higher plant generation costs
   
10
 
Higher nuclear plant operation costs
   
10
 
Higher labor costs
   
7
 
Other, net
   
1
 
Total increase in other operating and maintenance expenses
 
$
49
 
 
 
Higher employee benefit costs are primarily related to performance based incentive compensation as well as pension costs.
 
Higher nuclear outage costs are due to the timing and cost of nuclear refueling outages.
 
Higher plant generation costs are primarily attributable to higher levels of scheduled maintenance and overhaul work.
 
Higher nuclear plant operation costs are due to higher labor costs and regulatory fees.
 
Higher labor costs are primarily due to an increase in compliance requirements and higher overtime for storm restoration work.

Conservation Program Expenses Conservation program expenses increased $15.2 million, or 36.3 percent, for the first nine months of 2010, compared with the first nine months of 2009.  The higher expense was primarily attributable to the expansion of programs and regulatory commitments.  NSP-Minnesota has established conservation incentive programs designed to encourage its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas and/or electric system.  This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers.  NSP-Minnesota recovers conservation program expenses concurrently through riders and base rates.

Depreciation and Amortization Depreciation and amortization expense increased by approximately $9.3 million, or 3.2 percent, for the first nine months of 2010, compared with the first nine months of 2009.  In September 2009, as a result of the MPUC decisions, in the Minnesota electric rate case, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, effective Jan. 1, 2009.  In addition, in June 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants.  Excluding the one time decrease recognized in 2009, the change in depreciation expense from 2009 to 2010 is primarily due to normal system expansion.
 

Taxes (Other Than Income Taxes) Taxes (other than income taxes) increased by approximately $8.0 million, or 7.3 percent, for the first nine months of 2010, compared with the first nine months of 2009.  The increase was primarily due to increased property taxes.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased by approximately $5.8 million, or 16.8 percent, for the first nine months of 2010 compared with the same period in 2009.  NSP-Minnesota’s overall increase was primarily due to a slightly higher AFUDC equity rate.

Income Taxes — Income tax expense increased by $3.0 million for the first nine months of 2010, compared with the first nine months of 2009.  The increase in income tax expense was primarily due to increased state unitary tax expense and a write-off of tax benefits previously recorded  for Medicare Part D subsidies in 2010, partially offset by additional tax expense related to prior year true-ups in 2009.  The effective tax rate was 39.3 percent for the first nine months of 2010, compared with 38.7 percent for the same period in 2009.  The higher effective tax rate for the first nine months of 2010 was primarily due to a higher forecasted annual effective tax rate and the write-off of tax benefits related to Medicare Part D subsidies in 2010, partially offset by additional tax expense related to prior year true-ups in 2009.  The higher forecasted annual effective tax rate for 2010, as compared to 2009, was primarily due to increased state unitary tax expense in 2010, partially offset by increased plant-related deductions in 2010.

Factors Affecting Results of Continuing Operations

Public Utility Regulation

2010 Minnesota Resource Decisions and Plan In May 2010, NSP-Minnesota signed new power purchase and exchange agreements with Manitoba Hydro that will extend purchases through 2025.  The existing agreements provide for the purchase of 850 MW, which start to expire April 30, 2015.  NSP-Minnesota filed for approval with the MPUC in June 2010.

NSP-Minnesota filed its 2011-2025 resource plan in August 2010.  In addition to the extension of contracts with Manitoba Hydro and previously approved life extensions and capacity increases at NSP-Minnesota’s nuclear generating plants,  the near term actions in the  plan include continued expansion of demand side management programs to 1.5 percent of sales annually, the acquisition of up to 250 MW of additional wind power to be in service by 2012 if priced competitively, and the replacement of the remaining 270 MW of coal-fired generation at the Black Dog generating plant with a 680 MW natural gas, combined-cycle unit by 2016.

NSP-Minnesota Transmission Certificate of Need (CON) — In April 2009, the MPUC granted a CON to construct three 345 kilovolt (KV) electric transmission lines as part of the CapX 2020 project.  The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion.  The allocation of the project cost to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million.  These cost estimates will be revised after the regulatory process is completed.  The MPUC also included a condition assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy.  In September 2009, two intervenors appealed the MPUC’s CON decisions in the Minnesota Court of Appeals.  On June 8, 2010, the court issued its decision affirming the MPUC’s order granting the CONs for the three 345 KV lines.  In May 2010, NSP-Minnesota and other CapX 2020 utilities notified the MPUC that the in-service date for the Brookings, S.D. to Hampton, Minn. project is expected to be delayed to the second quarter of 2015, more than one year after the date provided in the MPUC CON decision.  The MPUC deliberated on the notice of change and decided to not act on that notice.  Instead, the MPUC ordered NSP-Minnesota to provide a report in January 2011 to update the status of the project.

As part of the regulatory process for the CapX 2020 345 KV projects, NSP-Minnesota and Great River Energy have filed four route permit applications with the MPUC.  Permit applications for the remaining parts of the three lines are expected to be filed in adjoining states in 2010.  Two filed route permit applications have completed the evidentiary hearing processes, and the MPUC issued route permits for the Monticello, Minn. to St. Cloud, Minn. project and five of the six segments of the Brookings, S.D. to Hampton, Minn. project.  One segment of the Brookings, S.D. to Hampton, Minn. line was referred back to the ALJ to develop more information concerning the appropriate location to cross the Minnesota River.  The other two route applications are expected to be sent to an evidentiary hearing later in 2010 or early 2011.

 In July 2009, the MPUC approved the CON application for a 230 KV CapX 2020 transmission line between Bemidji, Minn. to Grand Rapids, Minn.  Route permit hearings were concluded in May 2010, and an MPUC decision is anticipated in the fourth quarter of 2010.  The Bemidji, Minn. to Grand Rapids, Minn. line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million, with construction expected to be completed in 2012.  The estimated project cost to NSP-Minnesota is approximately $26 million.
 
 
Nuclear Plant Power Uprates and Life Extension

Prairie Island Life Extension — In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively.  The Prairie Island Indian Community (PIIC) filed contentions in the NRC license renewal proceeding in August 2008, which was referred to the Atomic Safety and Licensing Board (ASLB) for review.  The ASLB granted the PIIC hearing request and has admitted seven of the 11 contentions filed.  To date, all seven contentions that were originally admitted have been resolved and removed from the ASLB docket.

Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions.  The ASLB has admitted one of the contentions and has issued a decision denying the other three.  On Sept. 30, 2010, the NRC Commissioners reversed the ASLB’s decision to admit the one contention.  The ASLB was directed to terminate its hearing process.  As a result, the NRC staff is proceeding with the remaining items necessary to process Prairie Island’s license renewal application and NSP-Minnesota anticipates receiving a final decision on the Prairie Island license renewal sometime in the first quarter of 2011.

Monticello Nuclear Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello facility.  The filing was placed on hold by the NRC staff to address concerns raised by the Advisory Committee for Reactor Safety (ACRS) related to containment pressure associated with pump performance.  The industry submitted a white paper and the NRC staff recommended that the matter be addressed through specific filings to demonstrate any potential risk and mitigation measures.  In a letter to the NRC staff, the ACRS indicated that modifications to the plant should be evaluated and made where practical.  NSP-Minnesota is working with the NRC to supplement its filing as necessary to address the issues and expects to complete the license proceeding in 2011.
 
Prairie Island Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 164 MW for NSP-Minnesota’s Prairie Island Units 1 and 2.  The MPUC approved the extended power uprate in December 2009.  NSP-Minnesota cannot file for NRC approval of the extended power uprate until after the NRC renews the plants’ current operating licenses, which is expected in late 2010 or early 2011.  The extended power uprates are scheduled to be implemented during the 2014 and 2015 refueling outages.
 
Summary of Recent Federal Regulatory Developments

The Federal Energy Regulatory Commission (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 (NERC) mandatory electric reliability standards.  State and local agencies have jurisdiction over many of NSP-Minnesota’s utility 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, 2009.  In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

Midwest Independent Transmission System Operator, Inc. (MISO) Cost Allocation Tariff — In October 2009, the FERC approved a proposal by MISO and its transmission owners, including NSP-Minnesota and NSP-Wisconsin, to change the cost allocation procedures in the MISO tariff associated with interconnection of new generation.  The approved tariff required the interconnecting generator to fund 90 or 100 percent of the costs of network upgrades required for interconnection (depending on voltage) on an interim basis until MISO and its stakeholders develop a replacement tariff to be filed with FERC in July 2010.  On July 15, 2010, MISO and certain transmission owners, including NSP-Minnesota and NSP-Wisconsin, filed the required replacement tariff.  The cost allocation provisions of the tariff provide for (1) regional allocation and recovery of costs associated with transmission expansion projects identified through the MISO transmission planning process as Multi-Value Projects (MVPs), which are projects that meet certain key planning objectives and (2) the allocation to generators of most costs for other network upgrades required to interconnect the generator to the MVPs or the existing transmission system.  MISO proposed the tariff changes be effective July 16, 2010.  Comments on the July 2010 MISO tariff filing were filed on Sept. 10, 2010, and a significant number of comments, both in support and in opposition of the tariff changes, were submitted.  The filing is pending FERC action.
 

MISO vs. PJM Interconnection, L.L.C. (PJM) Complaint Proceedings — In March 2010, MISO filed two complaints against PJM at the FERC alleging that PJM violated generation redispatch requirements under the Joint Operating Agreement between the two regional transmission organizations (RTOs), and alleging that incorrect modeling of certain generators by PJM resulted in underpayments by PJM of up to $135 million to generators in MISO (including the NSP System, whereby NSP-Minnesota and NSP-Wisconsin share all generation and transmission costs through the Interchange Agreement, which is a FERC-approved tariff) for redispatch provided from 2002 to 2009.  MISO asked the FERC to direct PJM to pay the underpaid amount, plus interest.  In April 2010, PJM filed a complaint against MISO, alleging that MISO dispatched generation in the MISO region improperly under the RTO Joint Operating Agreement, and requested that the FERC order MISO to pay PJM up to $25 million.  Xcel Energy intervened in the complaint proceedings in support of MISO.  Informal settlement discussions have failed to resolve the issues, and the FERC issued an order setting the disputes for hearing and formal settlement discussions.  Settlement discussions are continuing.  The outcome of the complaint proceedings is uncertain.  If MISO were to prevail, NSP-Minnesota could receive a portion of the payments to MISO from PJM.  If PJM were to prevail, NSP-Minnesota could be required to reimburse MISO for a portion of the payments to PJM.

Rate Increase for Grandfathered Transmission Service Customers — In May 2010, NSP-Minnesota filed to revise the transmission service rate (known as Tm-1) applicable to eight wholesale customers taking service under a “grandfathered” rate schedule.  The change would set the Tm-1 transmission service rate equal to the similar rate under the MISO Tariff.  NSP-Minnesota proposed the rate change be accepted effective Aug. 1, 2010, but placed into effect Jan. 1, 2011.  The affected Tm-1 customers intervened in the rate filing and protested the increase.  In July 2010, the FERC accepted the rate filing and allowed the rates to go into effect on Jan. 1, 2011, subject to refund and settlement judge procedures.  The matter is now in settlement discussions.  The proposed rates would increase NSP-Minnesota wholesale transmission revenues by approximately $5 million effective Jan. 1, 2011, however, a share of the increase would be included as a revenue credit to retail rates in retail rate proceedings starting in 2011.

Electric Reliability Standards Compliance

Compliance Audits
In 2008, the NSP System filed a self-report with the Midwest Reliability Organization (MRO) regional entity relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain critical infrastructure protection (CIP) standards.  In 2009, the NSP System reached agreement with the MRO that would resolve all open audit findings and self reports by payment of a non-material penalty.  In April 2010, the NSP System executed a definitive settlement agreement.  The settlement agreement is pending approval at the NERC and will also need to be approved by the FERC.

In March 2010, the MRO conducted a compliance spot check to evaluate compliance with the NERC Critical Energy Infrastructure (CIP) standards, which were effective July 1, 2008.  The draft non-public report issued by the MRO in July 2010 found that the Xcel Energy utility subsidiaries may not be in compliance with several of the CIP standards.  Xcel Energy provided comments disagreeing with many of the conclusions of the draft report.  The regional entity audit function issued a non-public final report in August 2010 alleging violations of certain CIP requirements, including certain violations common to all Xcel Energy utility subsidiaries; at that time, the spot check report was transferred to the MRO enforcement function.  Xcel Energy continues to dispute the alleged violations and is working to resolve issues with the MRO enforcement functions.  To what extent the regional entities or NERC may seek to impose penalties for violations of CIP standards is unknown at this time.
 
NERC Compliance Investigations
As a result of a series of transmission line outages, on Sept. 18, 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection.  In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada.  The initial transmission line outages occurred on the NSP System.  In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the September 2007 event.  Because the event affected more than one region, the NERC took over the investigation.  In January 2010, the NERC issued a preliminary report alleging the NSP System violated certain NERC reliability standards.  The report represents the preliminary conclusions of the NERC and is subject to additional procedures at NERC, and ultimately FERC review.  Xcel Energy disagrees with the many aspects of the preliminary report and filed its response with NERC in February 2010.  The final outcome of the NERC compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC.  NSP-Minnesota is fully cooperating with the investigation.  The final outcome of the NERC compliance investigation, and whether and to what extent NERC may seek to impose penalties for standards violations, is unknown at this time.
 


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 Sept. 30, 2010, 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.



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

Additional Information

See Notes 5 and 6 of the consolidated financial statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference.  Reference also is made to Item 3 and Notes 13 and 14 of NSP-Minnesota’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2009 for a description of certain legal proceedings presently pending.


Except to the extent updated or described below, 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, 2009, which is incorporated herein by reference.

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG, and federal legislation has been introduced in both houses of Congress. Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA. On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. The EPA finalized GHG efficiency standards for light duty vehicles in spring 2010 and has promulgated  permitting requirements for GHGs for large new and modified stationary sources, such as power plants.  These regulations will become applicable in 2011.  We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 6, Commitments and Contingent Liabilities, in the notes to the consolidated financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
 

Many of the federal and state climate change legislative proposals, such as the American Clean Energy and Security Act and the proposed Kerry-Lieberman legislation, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.



*Indicates incorporation by reference

3.01*
 
Articles of Incorporation and Amendments of Northern Power Corp. (renamed NSP-Minnesota on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*
 
By-Laws (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
4.01*
 
 
Supplemental Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250,000,000 principal amount of 1.950% First Mortgage Bonds, Series due Aug. 15, 2015 and $250,000,000 principal amount of 4.850% First Mortgage Bonds, Series due Aug. 15, 2040.  (Exhibit 4.01 to Form 8-K dated Aug. 3, 2010 (file no. 001-31387)).
 
Principal Executive Officer’s and 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.



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 on Nov. 1, 2010.

Northern States Power Company (a Minnesota corporation)
(Registrant)

 
/s/ TERESA S. MADDEN
 
Teresa S. Madden
 
Vice President and Controller
   
 
/s/ DAVID M. SPARBY
 
David M. Sparby
 
Vice President and Chief Financial Officer
 
 
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