Northern States Power 10-Q 2007 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2007
	or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                        to
	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	(I.R.S. Employer Identification No.)
incorporation or organization)
414 Nicollet Mall, Minneapolis,
Minnesota	55401
(Address of principal executive	(Zip Code)
offices)

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

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. Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer o                               Accelerated Filer o                               Non-Accelerated Filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o  No  x

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 July 30, 2007
Common Stock, $0.01 par value	1,000,000 shares

Northern States Power Co. (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.	Financial Statements (Unaudited)
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 4.	Controls and Procedures
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits
SIGNATURES
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

This Form 10-Q is filed by Northern States Power Co., 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).

2

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Operating revenues
Electric utility	$	853,328		$	732,723		$	1,645,882		$	1,453,127
Natural gas utility	118,944			92,179			467,159			454,143
Other	4,453			4,443			9,319			9,788
Total operating revenues	976,725			829,345			2,122,360			1,917,058
Operating expenses
Electric fuel and purchased power	401,721			309,702			772,194			604,696
Cost of natural gas sold and transported	85,958			64,005			368,758			368,723
Cost of sales — nonregulated and other	2,226			1,877			4,175			3,661
Other operating and maintenance expenses	225,802			241,270			472,603			465,285
Depreciation and amortization	108,356			105,525			217,136			209,199
Taxes (other than income taxes)	29,858			31,946			66,832			67,446
Total operating expenses	853,921			754,325			1,901,698			1,719,010
Operating income	122,804			75,020			220,662			198,048
Interest and other income, net (see Note 9)	979			2,830			2,010			3,707
Allowance for funds used during construction — equity	5,692			4,025			11,098			7,424
Interest charges and financing costs
Interest charges — includes other financing costs of $1,290, $1,796, $2,570 and $3,480, respectively	45,840			39,506			90,282			79,052
Allowance for funds used during construction — debt	(4,482		)	(3,481		)	(8,803		)	(6,490		)
Total interest charges and financing costs	41,358			36,025			81,479			72,562
Income before income taxes	88,117			45,850			152,291			136,617
Income taxes	31,743			15,730			53,414			47,555
Net income	$	56,374		$	30,120		$	98,877		$	89,062

See Notes to Consolidated Financial Statements

3

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Six Months Ended June 30,
	2007			2006
Operating activities
Net income	$	98,877		$	89,062
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	220,706			211,659
Nuclear fuel amortization	23,636			22,395
Deferred income taxes	90,572			(37,690		)
Amortization of investment tax credits	(2,422		)	(2,423		)
Allowance for equity funds used during construction	(11,098		)	(7,424		)
Net realized and unrealized hedging and derivative transactions	1,098			19,106
Changes in operating assets and liabilities:
Accounts receivable	(23,948		)	85,728
Accounts receivable from affiliates	17,340			20,216
Accrued unbilled revenues	54,395			114,437
Inventories	26,837			46,562
Recoverable purchased natural gas and electric energy costs	(18,114		)	2,478
Other current assets	(983		)	(5,044		)
Accounts payable	(87,973		)	(68,515		)
Net regulatory assets and liabilities	(23,572		)	7,838
Other current liabilities	(16,097		)	(22,172		)
Change in other noncurrent assets	(139		)	(5,158		)
Change in other noncurrent liabilities	32,866			11,154
Net cash provided by operating activities	381,981			482,209
Investing activities
Utility capital/construction expenditures	(539,040		)	(384,808		)
Allowance for equity funds used during construction	11,098			7,424
Purchase of investments in external decommissioning fund	(313,102		)	(11,570		)
Proceeds from sale of investments in external decommissioning fund	291,406			14,083
Investments in utility money pool arrangement	(366,400		)	(635,300		)
Repayments from utility money pool arrangement	185,600			434,800
Investments in and advances to affiliates	6,200			45,000
Other investments	404			4,781
Net cash used in investing activities	(723,834		)	(525,590		)
Financing activities
Proceeds from short-term borrowings, net	54,081			—
Proceeds from issuance of long-term debt	344,170			400,000
Repayment of long-term debt, including reacquisition premiums	(5		)	(75		)
Borrowings under utility money pool arrangement	297,700			—
Repayments under utility money pool arrangement	(297,700		)	—
Borrowings under 5-year unsecured credit facility	—			194,000
Repayments under 5-year unsecured credit facility	—			(444,000		)
Capital contributions from parent	65,280			155,857
Dividends paid to parent	(113,229		)	(164,572		)
Net cash provided by financing activities	350,297			141,210
Net increase in cash and cash equivalents	8,444			97,829
Cash and cash equivalents at beginning of period	16,019			38,542
Cash and cash equivalents at end of period	$	24,463		$	136,371
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	73,917		$	63,381
Cash paid for income taxes (net of refunds received)	(4,090		)	95,502
Supplemental disclosure of non-cash flow investing transactions:
Property, plant and equipment additions in accounts payable	$	20,360		$	33,536

See Notes to Consolidated Financial Statements

4

NSP-MINNESOTA

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	June 30, 2007			Dec. 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	24,463		$	16,019
Investments in utility money pool, weighted average yield of 5.40% at June 30, 2007	180,800			—
Notes receivable from affiliates	24,100			30,300
Accounts receivable, net of allowance for bad debts of $13,846 and $13,408, respectively	394,583			370,635
Accounts receivable from affiliates	15,596			32,936
Accrued unbilled revenues	165,639			220,034
Recoverable purchased natural gas and electric energy costs	35,787			17,673
Materials and supplies inventories	98,152			93,183
Fuel inventories	51,303			40,257
Natural gas inventories	42,164			85,016
Derivative instruments valuation	78,452			62,211
Prepayments and other	34,293			32,708
Total current assets	1,145,332			1,000,972
Property, plant and equipment, at cost:
Electric utility plant	8,380,563			8,245,632
Natural gas utility plant	874,143			859,533
Construction work in progress	1,180,386			917,275
Common utility and other property	444,272			416,635
Total property, plant and equipment	10,879,364			10,439,075
Less accumulated depreciation	(4,753,417		)	(4,590,719		)
Nuclear fuel — net of accumulated amortization: $1,261,553 and $1,237,917, respectively	176,516			140,152
Net property, plant and equipment	6,302,463			5,988,508
Other assets:
Nuclear decommissioning fund investments	1,292,386			1,200,688
Regulatory assets	329,060			372,349
Prepaid pension asset	288,188			276,571
Derivative instruments valuation	169,087			181,616
Other investments	30,488			30,892
Other	31,499			27,452
Total other assets	2,140,708			2,089,568
Total assets	$	9,588,503		$	9,079,048
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	185,035		$	40
Short-term debt	143,081			89,000
Accounts payable	379,191			468,727
Accounts payable to affiliates	23,877			39,139
Taxes accrued	99,947			126,104
Accrued interest	52,384			48,308
Dividends payable to parent	57,312			56,105
Derivative instruments valuation	29,912			36,167
Other	36,720			38,572
Total current liabilities	1,007,459			902,162
Deferred credits and other liabilities:
Deferred income taxes	810,640			708,772
Deferred investment tax credits	45,232			47,654
Asset retirement obligations	1,350,096			1,311,271
Regulatory liabilities	687,011			658,571
Derivative instruments valuation	241,511			248,981
Pension and employee benefit obligations	206,956			209,548
Other liabilities	101,611			69,229
Total deferred credits and other liabilities	3,443,057			3,254,026
Commitments and contingent liabilities (see Note 5)
Capitalization:
Long-term debt	2,462,643			2,299,188
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10			10
Additional paid in capital	1,626,760			1,561,480
Retained earnings	1,041,307			1,055,983
Accumulated other comprehensive income	7,267			6,199
Total common stockholder’s equity	2,675,344			2,623,672
Total liabilities and equity	$	9,588,503		$	9,079,048

See Notes to Consolidated Financial Statements

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota and its subsidiaries as of June 30, 2007, and Dec. 31, 2006; the results of its operations for the three months and six months ended June 30, 2007 and 2006; and its cash flows for the six months ended June 30, 2007 and 2006. Due to the seasonality of electric and natural gas sales of NSP-Minnesota, interim results are not necessarily an appropriate base from which to project annual results.

1.   Significant Accounting Policies

Except to the extent updated or described below, 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, 2006 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Income Taxes — Consistent with prior periods and upon adoption of Financial Accounting Standard Board (FASB) Interpretation No. 48 – “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”, NSP-Minnesota records interest and penalties related to income taxes as interest charges in the Consolidated Statements of Income.

Reclassifications — Certain amounts in the Consolidated Statements of Cash Flows have been reclassified from prior-period presentation to conform to the 2007 presentation. The reclassifications reflect the presentation of unbilled revenues, recoverable purchased natural gas and electric energy costs and regulatory assets and liabilities as separate items rather than components of other assets and other liabilities within net cash provided by operating activities.  In addition, activity related to derivative transactions have been combined into net realized and unrealized hedging and derivative transactions.  These reclassifications did not affect total net cash provided by (used in) operating, investing or financing activities within the Consolidated Statements of Cash Flows.

2.   Recently Issued Accounting Pronouncements

Fair Value Measurements (Statement of Financial Accounting Standards (SFAS) 157) — In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.  NSP-Minnesota is evaluating the impact of SFAS 157 on its financial condition and results of operations and does not expect the impact of adoption to be material.

The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (SFAS 159) — In February 2007, the FASB issued SFAS 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after Nov. 15, 2007.  NSP-Minnesota is evaluating the impact of SFAS 159 on its financial condition and results of operations and does not expect the impact of adoption to be material.

3.   Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — In July 2006, the FASB issued Interpretation FIN 48.  FIN 48 prescribes how a company should recognize, measure, present and disclose uncertain tax positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, NSP-Minnesota adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which is reported as an adjustment to the beginning balance of retained earnings, was not material.  Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated income tax returns.  Xcel Energy has been audited by the Internal Revenue Service (IRS) through tax year 2003, with a limited exception for 2003 research tax credits.  The IRS commenced an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003) in the third quarter of 2006, and that examination is anticipated to be complete by March 31, 2008.  As of

6

June 30, 2007, the IRS had not proposed any material adjustments to tax years 2003 through 2005.  The statute of limitations applicable to Xcel Energy’s 2000 through 2002 federal income tax returns expired as of June 30, 2007.

NSP-Minnesota is currently under examination by the state of Minnesota for years 1998 through 2000.  No material adjustments have been proposed as of June 30, 2007.  As of June 30, 2007, NSP-Minnesota’s earliest open tax years in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 1998.

The amount of unrecognized tax benefits was $22.5 million and  $25.9 million on Jan. 1, 2007 and June 30, 2007, respectively.  Of these amounts, $4.1 million and $2.3 million were offset against the tax benefits associated with net tax credit carryovers as of Jan. 1, 2007 and June 30, 2007, respectively.

Included in the unrecognized tax benefit balance was $5.5 million and $3.8 million of tax positions on Jan. 1, 2007 and June 30, 2007, respectively, which if recognized would affect the annual effective tax rate.  In addition, the unrecognized tax benefit balance included $17.0 million and $22.1 million of tax positions on Jan. 1, 2007 and June 30, 2007, respectively, 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 effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.  The change in the unrecognized tax benefit balance from April 1, 2007 to June 30, 2007, was due to the addition of similar uncertain tax positions relating to second quarter activity and the resolution of certain federal audit matters.

NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state tax audits progress.  However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a range of the possible change.

The interest expense liability related to unrecognized tax benefits on Jan. 1, 2007, was not material.  The change in the interest expense liability from Jan. 1, 2007, to June 30, 2007, was not material.  No amounts were accrued for penalties.

4.Rate Matters

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

Midwest Independent Transmission System Operator, Inc. (MISO) Long-Term Transmission Pricing — In October 2005, MISO filed a proposed change to its Transmission and Energy Markets Tariff (TEMT) to regionalize future cost recovery of certain high voltage transmission projects to be constructed for reliability improvements. The proposal, called the Regional Expansion Criteria Benefits phase I (RECB I) proposal, would recover 20 percent of eligible transmission costs from all transmission service customers in the MISO 15 state region, with 80 percent recovered on a sub-regional basis for projects 345 kilovolt (KV) and above.  Projects above 100 KV but less than 345 KV will be recovered 100 percent on a subregional basis.  The proposal would exclude certain projects that had been planned prior to the October 2005 filing, and would require new generators to fund 50 percent of the cost of network upgrades associated with their interconnection. In February 2006, the FERC generally approved the RECB I proposal, but set the 20 percent limitation on regionalization for additional proceedings. Various parties filed requests for rehearing. On Nov. 29, 2006, the FERC issued an order on rehearing upholding the February 2006 order and approving the 20 percent limitation. On Dec. 13, 2006, the Public Service Commission of Wisconsin (PSCW) filed an appeal of the RECB I order.

In addition, in October 2006, MISO filed additional changes to its TEMT to regionalize future recovery of certain transmission projects (345 KV and above) constructed to provide access to lower cost generation supplies. The filing, known as Regional Expansion Criteria Benefits phase II (RECB II), would provide regional recovery of 20 percent of the project costs and sub-regional recovery of 80 percent, based on a benefits analysis. MISO proposed that the RECB II tariff be effective April 1, 2007.

On March 15, 2007, the FERC issued orders separately upholding the Nov. 29, 2006 order, accepting the RECB I pricing proposal, and approving most aspects of the RECB II proposal.  Various parties filed requests for rehearing of the RECB II order in April 2007.  The requests are pending FERC action.

Transmission service rates in the MISO region presently use a rate design in which the transmission cost depends on the location of the load being served (referred to as “license plate” rates). Costs of existing transmission facilities are thus not regionalized. MISO is required to file a successor rate methodology in August 2007, to be effective Feb. 1, 2008.  On April 19, 2007, FERC issued an order overruling a 2006 initial decision by a FERC administrative law judge (ALJ) recommending regionalization of the cost of existing transmission facilities in the PJM Interconnection, Inc. (PJM), another Regional Transmission Organization (RTO).  FERC ordered PJM to continue to license plate rates for existing facilities.  As a result, MISO will not propose to regionalize the recovery of the costs of existing transmission facilities in the Aug. 1, 2007, filing. 

7

The March 15, 2007 FERC orders regarding RECB I and II also required MISO to re-examine the cost allocation for new reliability improvements and economic projects in the August 2007 compliance filing.

Proposals to regionalize transmission costs could shift the costs of NSP-Minnesota transmission investments to other MISO transmission service customers, but would also shift the costs of transmission investments of other participants in MISO to NSP-Minnesota.

Revenue Sufficiency Guarantee Charges — On April 25, 2006, the FERC issued an order determining that MISO had incorrectly applied its TEMT regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The RSG charges are collected from certain MISO customers and paid to others. On Oct. 26, 2006, the FERC issued an order granting rehearing in part and reversed the prior ruling requiring MISO to issue retroactive refunds and ordered MISO to submit a compliance filing to implement prospective changes. In late November 2006, however, certain parties filed further requests for rehearing challenging the reversal regarding refunds and the effective date.

On March 15, 2007, the FERC issued orders separately denying rehearing of the Oct. 26, 2006, order and rejecting certain aspects of the MISO compliance filings submitted in November 2006. The FERC ordered MISO to submit a revised compliance filing. As of June 30, 2007, NSP-Minnesota had a reserve of $1.9 million.

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

NSP-Minnesota Electric Rate Case — In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent. This increase was based on a requested 11 percent return on common equity (ROE), a projected common equity to total capitalization ratio of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006.

On Sept. 1, 2006, the MPUC issued a written order granting an electric revenue increase of approximately $131 million for 2006 based on an authorized ROE of 10.54 percent. The scheduled rate increase has been reduced in 2007 to $115 million to reflect the return of Flint Hills Resources, a large industrial customer, to the NSP-Minnesota system. The MPUC Order became effective in November 2006, and final rates were implemented on Feb. 1, 2007.

On March 13, 2007, a citizen intervenor submitted a brief asking that the Minnesota Court of Appeals remand to the MPUC with direction to determine the correct amount of income tax collected in rates but not paid to taxing authorities, order the refund or credit to ratepayers for taxes collected in rates but not paid, order the refund to ratepayers of the amount of interim rates collected in January and February of 2006 in violation of the previous merger order and provide other equitable relief. The citizen intervenor passed away on May 15, 2007.  The estate has filed a request with the Minnesota Court of Appeals that the appeal continue with the estate listed as the appellant.

NSP-Minnesota Natural Gas Rate Case — In November 2006, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $18.5 million, which represents an increase of 2.4 percent. The request is based on 11.0 percent ROE, a projected equity ratio of 51.98 percent and a natural gas rate base of $439 million. Interim rates, subject to refund, were set at a $15.9 million increase and went into effect on Jan. 8, 2007.

On April 10, 2007, NSP-Minnesota filed its rebuttal testimony and revised its requested relief to $16.8 million. The revised request was caused primarily by an updated ROE estimate of 10.75 percent and an update to the sales forecast.

On April 24, 2007, the Minnesota Department of Commerce (MDOC) filed surrebuttal testimony recommending a rate increase of $10.9 million based on an updated ROE of 9.5 percent. The Office of Attorney General (OAG) filed surrebuttal testimony that continued to recommend a 9.26 percent ROE and made reference to the fact that Xcel Energy’s consolidated taxes are significantly lower than those requested for recovery, but made no specific recommendations on this issue.

On July 26, 2007, the ALJ issued a recommended decision.  While NSP-Minnesota is in the process of completing a detailed evaluation of the recommended decision, NSP-Minnesota believes it is generally consistent with the MDOC recommended annual revenue increase of approximately $10.9 million, based on ROE of 9.5 percent.   The MPUC final order is expected in September 2007.

North Dakota Gas Rate Case — In December 2006, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase North Dakota natural gas rates by $2.8 million, an increase of 3.0 percent. The request is based on 11.3 percent return on equity, a projected equity ratio of 51.59 percent and a natural gas rate base of $46.6 million. Interim rates, subject to refund, were set at a $2.2 million increase and went into effect on Feb. 13, 2007. On April 24, 2007, NSP-Minnesota and the NDPSC staff filed a settlement agreement.

8

On June 13, 2007 the NDPSC approved a settlement agreement with final rates going into effect on July 1, 2007.  The key provisions in the settlement include:

·A $2.3 million annual revenue increase;

·An authorized return on equity of 10.75 percent;

·A residential natural gas base rate freeze until 2010 (exclusive of changes in purchased gas costs);

·An earnings sharing mechanism, which will result in customer refunds should NSP-Minnesota’s natural gas operations in North Dakota exceed its authorized ROE during 2007, 2008 or 2009; and

·Fully decoupled residential rates.

MISO Day 2 Market Cost Recovery — On Dec. 20, 2006, the MPUC issued an order ruling that NSP-Minnesota may recover all MISO Day 2 costs, except Schedules 16 and 17, through its FCA.

·NSP-Minnesota is refunding Schedule 16 and 17 costs recovered through the FCA in 2005 ($2.2. million) to customers through the FCA in equal monthly installments beginning March 2007.

·NSP-Minnesota is recovering 50 percent of Schedule 16 and 17 costs starting in 2006 in the final rates established in the 2005 electric rate case.

·NSP-Minnesota is allowed to defer 100 percent of the Schedule 16 and 17 costs not included in rates for a three-year period before starting the amortization.

·The MPUC ruling on Schedules 16 and 17 costs will have no impact on net income in 2007.

On April 9, 2007, the OAG filed an appeal of the MPUC order to the Minnesota Court of Appeals. NSP-Minnesota and the other affected utilities intervened in the appeal and will urge the court to uphold the MPUC order.  The date for a court decision in the appeal is not known.

Transmission Cost Recovery —In November 2006, the MPUC approved the replacement of the Renewable Cost Recovery (RCR) rider with a Transmission Cost Recovery (TCR) rider pursuant to 2005 legislation. The TCR mechanism would allow recovery of incremental transmission investments between rate cases.

On Oct. 27, 2006, NSP-Minnesota filed for approval of recovery of $14.7 million in 2007 under the TCR tariff. The RCR rate factors will remain in effect until the TCR factors are implemented. On March 8, 2007, the MPUC voted to approve the recommendation of the MDOC to allow recovery of $13.1 million in 2007, but ruled $1.6 million of costs should be allocated to wholesale transmission service customers. This ruling will reduce recovery in Minnesota electric rates by $1.6 million in 2007.

On Feb. 28, 2007, NSP-Minnesota filed for South Dakota Public Utilities Commission (SDPUC) approval of a Transmission Cost Recovery Rider (TCRR).  NSP-Minnesota proposed to recover $0.8 million in transmission related costs outside a general rate case.  The tariff proposal is now pending SDPUC action.

Fixed Bill Complaint — In January 2007, the OAG filed a complaint with the MPUC regarding the fixed monthly gas payment programs of NSP-Minnesota and another unaffiliated natural gas utility. This program generally allows customers to elect a fixed monthly payment for natural gas service that will not change for one year regardless of changes in natural gas costs or consumption due to weather. The complaint seeks termination of the program or modification, and seeks interim relief that would allow customers to exit the program.

On July 16, 2007, the MPUC issued its order suspending the program until the MPUC determines it is in the public interest.  Other terms of the order include: low income housing energy assistance program customers will be allowed to immediately exit the fixed monthly gas payment program retroactive to the start of the current program year without incurring an exit fee; NSP-Minnesota is directed to attempt to resolve all stranded cost issues with the OAG.  If a settlement is not reached, NSP-Minnesota may submit a proposal to the MPUC for resolution; NSP-Minnesota must submit a revised tariff reflecting suspension of the program within 20 days of the order.  Prior to issuance of the order, NSP-Minnesota determined that it could not reach a settlement with the OAG and filed its proposal to resolve the phase out of the program on July 6, 2007.

Mercury Cost Recovery — On Dec. 29, 2006, NSP-Minnesota requested approval of a Mercury Emissions Reduction Rider tariff and associated rate adjustments. The request is designed to recover approximately $5.4 million during 2007 from Minnesota electric retail customers for costs associated with implementing both the mercury and other environmental improvement portions of the Mercury Emissions Reduction Act of 2006. The MDOC reviewed the filing and provided comments indicating that further action of an environmental improvement plan was required before this filing could be

9

approved.  NSP-Minnesota subsequently withdrew the filing and will continue accruing costs associated with our compliance with the 2006 Mercury Reduction Act in a deferred account for future recovery.

Annual Automatic Adjustment Report for 2005 — On Sept. 2, 2006, NSP-Minnesota filed its annual automatic adjustment report for the period from July 1, 2005 through June 30, 2006, which is the basis for the MPUC review of charges that flow through the FCA mechanism. The MDOC filed comments on April 18, 2007 asserting that NSP-Minnesota had not demonstrated the reasonableness of its cost assignment of certain market energy charges from the MISO Day 2 market between daily sales of excess generation and native energy needs. The MDOC indicated that NSP-Minnesota should provide additional support for its methodology in its reply comments, which were filed on June 1, 2007.  NSP-Minnesota argued the cost assignment is consistent with the methodology approved in both a 2000 MPUC investigation of FCA cost allocations and the Dec. 20, 2006 MPUC order authorizing FCA recovery of most MISO Day 2 charges.  The 2006 annual automatic adjustment report is pending final MPUC action.

Annual Review of Remaining Lives Depreciation Filing — On June 4, 2007, as part of its annual review of remaining lives depreciation filing, NSP-Minnesota recommended lengthening the life of the Monticello nuclear plant by 20 years retroactive to Jan. 1, 2007 as well as certain other smaller life adjustments.  On July 9, 2007, the MDOC recommended approval of the longer lives and sought a small adjustment to rate base in future rate cases to reflect this change so close to NSP-Minnesota’s last rate case.  On July 19, NSP-Minnesota filed replies specifying the calculation of any potential future adjustment.  Assuming the MPUC approves this filing, 2007 depreciation expense would decrease by approximately $31 million.  The MPUC is expected to rule on this filing during the third quarter of 2007.

5.Commitments and Contingent Liabilities

Except as noted below, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2006 and Notes 4 and 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q 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 unresolved contingencies that are material to NSP-Minnesota’s financial position.

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 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 and some other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including the following categories of sites:

·the site of a former manufactured gas plant (MGP) operated by NSP-Minnesota’s subsidiaries or predecessors; and

·third party sites, such as landfills, to which NSP-Minnesota is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.

NSP-Minnesota records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

Estimates are revised as facts become known.  At June 30, 2007, the liability for the cost of remediating these sites was estimated to be $1.1 million, of which $0.2 million was considered to be a current liability.  Some of the cost of remediation may be recovered from:

10

·insurance coverage;

·other parties that have contributed to the contamination; and

·customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined.  Estimates have been recorded for NSP-Minnesota’s future costs for these sites.

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 removed.  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 11 of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2006.  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

Clean Air Interstate Rule — In March 2005, the Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule (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.  CAIR addresses the transportation of fine particulates, ozone and emission precursors to nonattainment downwind states.  CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions.  Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOX that will result in significant emission reductions.  It will be based on stringent emission controls and forms the basis for a cap-and-trade program.  State emission budgets or caps decline over time.  States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

NSP- Minnesota has generating facilities that will be impacted by CAIR.  On May 30, 2007, the Minnesota Pollution Control Agency (MPCA) issued a notice for implementing the CAIR. This notice stated that Minnesota will administer the CAIR and the EPA’s Federal Implementation Plan.  Preliminary estimates of capital expenditures associated with compliance with CAIR for the NSP System (Minnesota and Wisconsin) range from $30 million to $40 million.

While NSP-Minnesota expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives.  NSP-Minnesota believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time.  The EPA’s CAMR  uses a national cap-and-trade system, where compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to achieve a 70 percent reduction in mercury emissions.  It affects all coal- and oil-fired generating units across the country that are greater than 25 MW.  Compliance with this rule occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018.  States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states.  Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state.  Similar to the CAIR, states can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

NSP-Minnesota currently estimates that it can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury allowances. NSP-Minnesota’s preliminary analysis for phase I compliance suggests capital costs of approximately $22.7 million for the mercury control equipment and continuous monitoring equipment at the A.S. King, Sherburne County (Sherco) and Black Dog generating facilities. The analysis indicates increased operating and maintenance expenses of approximately $22.6 million, beginning in 2010. Additional costs will be incurred to meet phase II requirements in 2018.

Minnesota Mercury Legislation — On May 2, 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. Under the Act, NSP-Minnesota has installed, and will maintain and operate continuous mercury emission monitoring systems or other monitoring methods approved by the MPCA. The information obtained will be used to establish a baseline from

11

which to measure mercury emission reductions. Mercury emission reduction plans must be filed by utilities by Dec. 31, 2007 (dry scrubbed units) and Dec. 31, 2009 (wet scrubbed units) that propose to implement technologies most likely to reduce emissions by 90 percent. Implementation would occur by Dec. 31, 2009 for one of the dry scrubbed units, Dec. 31, 2010 for the remaining dry scrubbed unit and Dec. 31, 2014 for wet scrubbed units. The cost of controls will be determined as part of the engineering analysis portion of the mercury reduction plans and is currently estimated to range from  $22.7 to $280.2 million for the mercury control and continuous monitoring equipment, with increased operating and maintenance expenses estimated to range from approximately $22.6 million to $48.4 million.  The lower values include costs to achieve a 50 percent mercury reduction for Sherco units 1 and 2, beginning in 2010.  The higher values include costs to try to achieve a 90 percent mercury reduction for Sherco units 1 and 2, beginning in 2010 and escalating to 2013. The lower cost estimates are also included above as part of the total cost estimate to comply with CAMR. Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004. Cost recovery provisions of the Act also apply to these other environmental initiatives. On Sept. 15, 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act. On Jan. 11, 2007, the MPUC approved this request for deferred accounting with a cap of $6.3 million.

Regional Haze Rules — On June 15, 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.

The EPA requires states to develop implementation plans to comply with BART by December 2007. NSP-Minnesota submitted its BART alternatives analysis for Sherco units 1 and 2 on Oct. 26, 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  At this time, the MPCA is not requiring any BART specific controls that go beyond controls required for CAIR compliance.

Voluntary Capacity Upgrade and Emissions Reduction Filing — On Jan. 2, 2007, NSP-Minnesota submitted a filing to the MPUC for a major emissions reduction project at Sherco Units 1, 2 and 3 to reduce emissions and expand capacity by installing NOx controls (low NOx burners, overfire air and  Selective Catalytic Reduction), installing mercury control systems, replacing the wet scrubbers on units 1 and 2 with semi-dry scrubbers, retrofitting different sections of the turbines on all three units, replacing generators and other associated equipment on all three units, and installing additional cooling capacity. The projected cost of this project is approximately $905 million and encompasses the higher value mercury control costs discussed above in the Minnesota Mercury Legislation section. NSP-Minnesota’s investments are subject to MPUC approval of a cost recovery mechanism.

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the “best technology available” 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 in the United States Court of Appeals for the Second Circuit challenging the phase II rulemaking. On Jan. 25, 2007, the court issued its decision and remanded virtually every aspect of the rule to the EPA for reconsideration. The EPA announced on March 20, 2007, it will suspend the deadlines and refer any implementation to each state’s best professional judgment until the EPA is able to fully respond to the court-ordered remands. As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved.

Legal Contingencies

In the normal course of business, NSP-Minnesota is subject to claims and litigation arising from prior and current operations. NSP-Minnesota is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition when it can be reasonably estimated.

Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court in Hennepin County asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with rent payments allegedly due and owed by NSP-Minnesota to MAC for the use of its property for a substation that serves MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the court granted MAC’s motion on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-Minnesota to continue making rent payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March and April of 2006. The parties entered into settlement negotiations in May 2006, and

12

in August 2006 reached an oral settlement of the dispute. The parties are negotiating the final form of the settlement documents and it is expected that the action will be formally dismissed in the near future.

Siewert  vs. Xcel Energy — Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action 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’ expert report on the economic damage to their dairy farm states that the total present value of plaintiffs’ loss is $6.8 million.  NSP-Minnesota denies all allegations, has made motions to exclude the testimony of Plaintiffs’ experts, and both sides have made motions for summary judgment.  A hearing on the various motions is currently scheduled for Aug. 28, 2007.  Trial is scheduled to commence in January 2008.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. Although NSP-Minnesota is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on NSP-Minnesota. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or natural gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit.  On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals.  On June 21, 2007 the Second Circuit Court of Appeals issued an order requesting the parties to file a letter brief informing the Second Circuit Court of Appeals of their views about the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal.  Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “ pollutant” subject to regulation by the EPA under the Clean Air Act.  In response to the request of the Second Circuit Court of Appeals, the defendant utilities filed a letter brief on July 6, 2007, stating the position that the United States Supreme Court’s decision supports the arguments raised by them on appeal.  It is unknown when the Second Circuit Court of Appeals will rule on the appeal.

Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in Minnesota State District Court in Hennepin County, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. NSP-Minnesota filed a motion for dismissal on the pleadings, which was heard on Aug. 16, 2006. In November 2006, the court issued an order denying NSP-Minnesota’s motion. On Nov. 28, 2006, pursuant to a motion by NSP-Minnesota, the court certified the issues raised in NSP-Minnesota’s original motion as important and doubtful. This certification permits NSP-Minnesota to file an appeal, and it has done so.  Briefs have been filed, but a date for oral argument has not yet been set.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court for the Southern District of Mississippi. Although NSP-Minnesota is not named as a party to this litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse effect on NSP-Minnesota. 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 in support of their claim, several legal theories, including 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. On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.  Oral arguments related to some of the defenses raised by the defendants, including Xcel Energy, have been set for Aug. 30, 2007.

AmeriPride Services vs. NSP - In August 2006, a complaint was served on NSP-Minnesota, alleging that on or about Sept. 2, 2004, fires occurred on the premises of AmeriPride Services, a linen and apparel service facility in Minneapolis, and that the cause of the fire was NSP-Minnesota’s failure to properly repair a primary underground cable after two prior failures in the same cable. AmeriPride claims damages slightly in excess of $2 million, and asserts claims of negligence, gross negligence, negligent inspection and maintenance, negligent design, negligent failure to install equipment to discontinue power, negligent

13

continuation of power, and negligent misrepresentation. The matter went to mediation on March 29, 2007, and a confidential settlement agreement was reached. The settlement did not have a material impact on NSP-Minnesota.

Schiltgen vs. Northern States Power Co. et al. — In November 2006, a suit was filed against NSP-Minnesota and others in the Minnesota State District Court in Washington County, alleging that negligence on the part of NSP-Minnesota and others led to severe injuries when the plaintiff contacted an electrical distribution line while working with a portable grain auger. NSP-Minnesota denies all allegations asserted against it and will vigorously defend itself against them.  Mediation has been scheduled for October 2007, dispositive motions will be heard in December 2007, and trial is currently scheduled to commence on March 10, 2008.

6.Short-term Borrowings and Other Financing Instruments

As of June 30, 2007, NSP-Minnesota had $143.1 million of short-term debt outstanding at a weighted average interest rate of 5.40 percent.

7.Long-term Borrowings and Other Financing Instruments

On June 26, 2007, NSP-Minnesota issued $350 million of 6.20 percent first mortgage bonds, series due July 1, 2037.  NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper.

On June 29, 2007, NSP-Minnesota announced that it will redeem all of its outstanding 8.00 percent Notes, Series due 2042.  The redemption will take place on Aug. 1, 2007.  NSP-Minnesota will redeem the notes at a redemption price equal to 100 percent of the principal amount of the notes ($25.00), plus accrued and unpaid interest on the notes, if any, to the redemption date.

8.Derivative Valuation and Financial Impacts

NSP-Minnesota uses a number of different derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.

All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS 133 -“Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), are recorded at fair value. The presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance.

NSP-Minnesota records the fair value of its derivative instruments in its Consolidated Balance Sheet as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions that NSP-Minnesota is currently engaged in are discussed below.

Cash Flow Hedges

NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates.

As of June 30, 2007, NSP-Minnesota had various commodity-related contracts designated as cash flow hedges extending through May 2008. The fair value of these cash flow hedges is deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale.

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 designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income.

As of June 30, 2007, NSP-Minnesota had net gains of approximately $0.4 million in Accumulated Other Comprehensive Income related to interest rate cash flow hedge contracts that it expects to recognize in earnings during the next 12 months.

14

Gains or losses on hedging transactions for the sales of energy or energy-related products are recorded as a component of revenues, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. NSP-Minnesota is allowed to recover in natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility. There was immaterial ineffectiveness in the second quarter of 2007.

The impact of qualifying cash flow hedges on NSP-Minnesota’s Accumulated Other Comprehensive Income, included as a component of stockholder’s equity, are detailed in the following table:

	Six months ended June 30,
(Millions of dollars)	2007			2006
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	9.4		$	—
After-tax net unrealized gains related to derivatives accounted for as hedges	1.2			9.7
After-tax net realized gains on derivative transactions reclassified into earnings	(0.2		)	—
Accumulated other comprehensive income related to cash flow hedges at June 30	$	10.4		$	9.7

Derivatives Not Qualifying for Hedge Accounting

NSP-Minnesota enters into certain commodity-based derivative transactions not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in accordance with SFAS 133 and are recorded within Operating Revenues on the Consolidated Statement of Income.

Normal Purchases or Normal Sales Contracts

NSP-Minnesota enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS 133 as normal purchases or normal sales.

NSP-Minnesota evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS 133. None of the contracts entered into within the commodity trading operations qualify for a normal designation.

9. Detail of Interest and Other Income, Net

Interest and other income, net of nonoperating expenses, for the three and six months ended June 30 consisted of the following:

	Three months ended June 30,						Six months ended June 30,
(Thousands of dollars)	2007			2006			2007			2006
Interest income	$	2,050		$	3,921		$	4,088		$	5,808
Equity income in unconsolidated affiliates	420			294			750			559
Other nonoperating income	5			302			27			390
Other nonoperating expense	(1,496		)	(1,687		)	(2,855		)	(3,050		)
Total interest and other income, net	$	979		$	2,830		$	2,010		$	3,707

15

10.Segment Information

NSP-Minnesota has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility. Commodity trading operations are not a reportable segment and commodity trading results are included in the Regulated Electric Utility segment.

(Thousands of dollars)	Regulated  Electric Utility		Regulated  Natural Gas  Utility			All Other		Reconciling  Eliminations			Consolidated Total
Three months ended June 30, 2007
Revenues from:
External customers	$	853,328	$	118,944		$	4,453	$	—		$	976,725
Internal customers	46		5,126			—		(5,172		)	—
Total revenue	$	853,374	$	124,070		$	4,453	$	(5,172	)	$	976,725
Segment net income	$	53,395	$	201		$	2,778	$	—		$	56,374
Three months ended June 30, 2006
Revenues from:
External customers	$	732,723	$	92,179		$	4,443	$	—		$	829,345
Internal customers	137		631			—		(768		)	—
Total revenue	$	732,860	$	92,810		$	4,443	$	(768	)	$	829,345
Segment net income (loss)	$	34,301	$	(4,695	)	$	514	$	—		$	30,120

(Thousands of dollars)	Regulated  Electric Utility		Regulated  Natural Gas  Utility		All Other		Reconciling Eliminations			Consolidated Total
Six months ended June 30, 2007
Revenues from:
External customers	$	1,645,882	$	467,159	$	9,319	$	—		$	2,122,360
Internal customers	259		8,955		—		(9,214		)	—
Total revenue	$	1,646,141	$	476,114	$	9,319	$	(9,214	)	$	2,122,360
Segment net income	$	70,682	$	21,663	$	6,532	$	—		$	98,877
Six months ended June 30, 2006
Revenues from:
External customers	$	1,453,127	$	454,143	$	9,788	$	—		$	1,917,058
Internal customers	206		1,552		—		(1,758		)	—
Total revenue	$	1,453,333	$	455,695	$	9,788	$	(1,758	)	$	1,917,058
Segment net income	$	74,265	$	10,986	$	3,811	$	—		$	89,062

11. Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended June 30,					Six months ended June 30,
(Millions of dollars)	2007			2006		2007			2006
Net income	$	56.4		$	30.1	$	98.9		$	89.1
Other comprehensive income:
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 8)	1.7			9.7		1.2			9.7
After-tax net realized gains on derivative transactions reclassified into earnings (see Note 8)	(0.1		)	—		(0.2		)	—
Other comprehensive income	1.6			9.7		1.0			9.7
Comprehensive income	$	58.0		$	39.8	$	99.9		$	98.8

16

12. Benefit Plans and Other Postretirement

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 June 30,
	2007			2006			2007			2006
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	14,555		$	14,380		$	1,205		$	1,479
Interest cost	43,028			38,197			11,635			13,287
Expected return on plan assets	(66,525		)	(67,551		)	(7,582		)	(7,110		)
Amortization of transition obligation	—			—			3,677			3,577
Amortization of prior service cost (credit)	6,487			7,421			(545		)	(545		)
Amortization of net loss	4,555			4,165			2,106			5,875
Net periodic benefit cost (credit)	2,100			(3,388		)	10,496			16,563
Credits not recognized due to the effects of regulation	2,894			3,893			—			—
Additional cost recognized due to the effects of regulation	—			—			973			973
Net benefit cost recognized for financial reporting	$	4,994		$	505		$	11,469		$	17,536
NSP-Minnesota
Net periodic benefit cost (credit)	$	(2,390	)	$	(3,564	)	$	2,797		$	4,415
Additional cost recognized due to the effects of regulation	2,894			3,894			—			—
Net benefit cost recognized for financial reporting	$	504		$	330		$	2,797		$	4,415

	Six months ended June 30,
	2007			2006			2007			2006
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	31,040		$	30,814		$	2,906		$	3,316
Interest cost	82,626			77,706			25,238			26,470
Expected return on plan assets	(132,416		)	(134,032		)	(15,200		)	(13,378		)
Amortization of transition obligation	—			—			7,288			7,222
Amortization of prior service cost (credit)	12,974			14,848			(1,090		)	(1,090		)
Amortization of net loss	8,422			8,676			7,100			12,398
Net periodic benefit cost (credit)	2,646			(1,988		)	26,242			34,938
Credits not recognized due to the effects of regulation	5,574			6,318			—			—
Additional cost recognized due to the effects of regulation	—			—			1,946			1,946
Net benefit cost recognized for financial reporting	$	8,220		$	4,330		$	28,188		$	36,884
NSP-Minnesota
Net periodic benefit cost (credit)	$	(4,580	)	$	(5,687	)	$	6,881		$	8,577
Additional cost recognized due to the effects of regulation	5,574			6,319			—			—
Net benefit cost recognized for financial reporting	$	994		$	632		$	6,881		$	8,577

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

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

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of NSP-Minnesota 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 notes.

17

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. 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; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions 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, 2006 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended June 30, 2007.

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, 2006.

Commodity price and interest rate risks for NSP-Minnesota are mitigated in most jurisdictions due to cost-based rate regulation. At June 30, 2007, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2006.

NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission, 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.

RESULTS OF OPERATIONS

NSP-Minnesota’s net income was approximately $98.9 million for the first six months of 2007, compared with approximately $89.1 million for the first six months of 2006.

Electric Utility, Short-term Wholesale and Commodity Trading Margins — Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for customers, most fluctuations in energy costs do not materially affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from NSP-Minnesota’s generation assets and energy and capacity purchased to serve native load. Commodity trading is not associated with NSP-Minnesota’s generation assets or the energy or capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

Margins from commodity trading activity conducted at NSP-Minnesota are partially redistributed to Public Service Company of Colorado and Southwestern Public Service Company, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue. Trading revenues are reported net of trading costs (i.e. on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include fuel, purchased power, transmission, broker fees and other related costs. Short–term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable.

18

The following table details base electric utility, short-term wholesale and commodity trading revenues and margin:

(Millions of dollars)	Base Electric Utility			Short-term Wholesale			Commodity Trading			Consolidated Total
Six months ended June 30, 2007
Electric utility revenues (excluding commodity trading)	$	1,561		$	84		$	—		$	1,645
Electric fuel and purchased power	(694		)	(78		)	—			(772		)
Commodity trading revenues	—			—			67			67
Commodity trading costs	—			—			(66		)	(66		)
Gross margin before operating expenses	$	867		$	6		$	1		$	874
Margin as a percentage of revenues	55.5		%	7.1		%	1.5		%	51.1		%
Six months ended June 30, 2006
Electric utility revenues (excluding commodity trading)	$	1,393		$	59		$	—		$	1,452
Electric fuel and purchased power	(552		)	(53		)	—			(605		)
Commodity trading revenues	—			—			53			53
Commodity trading costs	—			—			(52		)	(52		)
Gross margin before operating expenses	$	841		$	6		$	1		$	848
Margin as a percentage of revenues	60.4		%	10.2		%	1.9		%	56.3		%

The following summarizes the components of the changes in base electric revenues and base electric margin for the six months ended June 30:

Base Electric Revenues

(Millions of dollars)	2007 vs. 2006
Fuel and purchased power cost recovery	$	83
Interchange agreement billing with NSP-Wisconsin	28
Sales growth (excluding weather impact)	16
Metropolitan emissions reduction project (MERP) rider	14
Transmission revenue	13
Estimated impact of weather	7
Conservation and non-fuel riders	(6		)
Other	13
Total increase in base electric revenues	$	168

Base Electric Margin

(Millions of dollars)	2007 vs. 2006
Sales growth (excluding weather impact)	$	15
MERP rider	14
Estimated impact of weather	7
Interchange agreement billing with NSP-Wisconsin	5
Transmission fee classification change	(9		)
Conservation and non-fuel riders	(6		)
Purchased capacity costs	(5		)
Other, including sales mix, other fuel recovery and purchased capacity costs	5
Total increase in base electric margin	$	26

19

Natural Gas Utility Margins — The following table details the change in natural gas revenues and margin. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

	Six months ended  June 30,
(Millions of dollars)	2007			2006
Natural gas utility revenues	$	467		$	454
Cost of natural gas sold and transported	(369		)	(369		)
Natural gas utility margin	$	98		$	85

The following summarizes the components of the changes in natural gas revenues and margin for the six months ended June 30:

Natural Gas Revenues

(Millions of dollars)	2007 vs. 2006
Estimated impact of weather on firm sales volume	$	24
Base rate changes – Minnesota (interim) and North Dakota	8
Sales growth (excluding weather impact)	3
Purchased gas adjustment clause recovery	(20		)
Other	(2		)
Total increase in natural gas revenues	$	13

Natural Gas Margin

(Millions of dollars)	2007 vs. 2006
Base rate changes – Minnesota (interim)and North Dakota	$	8
Estimated impact of weather on firm sales volume	4
Sales growth (excluding weather impact)	2
Transportation and other	(1		)
Total increase in natural gas margin	$	13

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses — The following summarizes the components of the changes in other utility operating and maintenance expense for the six months ended June 30:

(Millions of dollars)	2007 vs. 2006
Higher nuclear plant operation costs	$	10
Higher combustion/hydro costs	8
Higher consulting fees	3
Higher nuclear plant outage expenses	2
Transmission fee classification change	(9		)
Lower conservation incentive program costs	(4		)
Lower employee benefit costs	(3		)
Total increase in other utility operating and maintenance expense	$	7

Depreciation and Amortization – Depreciation and amortization expense increased by approximately $7.9 million, or 3.8 percent, for the first six months of 2007, compared with the first six months of 2006. The increase was primarily due to planned system expansion.

Interest Charges – Interest charges increased by approximately $11.2 million, or 14.2 percent, for 2007, compared with 2006. The increase was due to the issuance of new long-term debt in June 2006, partially offset by a July 2006 bond

20

retirement. In addition, interest expense was accrued during the first six months of 2007 for the Minnesota electric interim rate and wholesale margin ratepayer sharing refunds.

Allowance for funds used during construction, equity and debt (AFDC) – AFDC is a non-cash amount capitalized as a part of construction costs representing the cost of financing the construction. Generally, these costs are recovered from customers, in future rates, as the related property is depreciated. NSP-Minnesota’s MERP project consists of converting two coal-fueled electric generating plants located in the Minneapolis - St. Paul metropolitan area to natural gas, and installing advanced pollution control equipment at a third coal-fired plant. The projects are expected to begin operations between 2007 and 2009. AFDC, resulting in part from these projects, increased by approximately $6.0 million, or 43.0 percent for the first six months of 2007, compared with the same period in 2006.

Income taxes – Income tax expense increased by approximately $5.9 million for the first six months of 2007 compared with the first six months of 2006.  The increase in tax expense was primarily due to an increase in pretax income.  The effective tax rate was 35.1 percent for the first six months of 2007, compared with 34.8 percent for the same period in 2006.

Regulation

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 4 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — The Energy Act repealed the Public Utility Holding Company Act of 1935 effective Feb. 8, 2006. In addition, the Energy Act required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act. Since August 2005, the FERC has completed or initiated proceedings to modify its regulations on a number of subjects. In addition to the previous disclosure in Item 1 of NSP Minnesota’s Form 10-K for the year ended Dec. 31, 2006, the FERC issued final rules making certain reliability standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance effective June 18, 2007.

While NSP-Minnesota cannot predict the ultimate impact the new regulations will have on its operations or financial results, NSP-Minnesota is taking actions that are intended to comply with and implement these new rules and regulations as they become effective.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services. FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to a Regional Transmission Organization (RTO). NSP-Minnesota is a member of the MISO. Each RTO separately files regional transmission tariff rates for approval by the FERC. All members within that RTO are then subjected to those rates.

On Feb. 15, 2007, the FERC issued final rules adopting revisions to its 1996 open access transmission rules. NSP-Minnesota submitted the initial required revisions to its Open Access Transmission Tariff (OATT) on July 13, 2007, as required.

In addition, in January 2007, the FERC issued interim and proposed rules to modify the current FERC rules governing the functional separation of the NSP-Minnesota electric transmission function from the wholesale sales and marketing function. The proposed rules are pending final FERC action.

While NSP-Minnesota cannot predict the ultimate impact the new regulations will have on its operations or financial results, NSP-Minnesota is taking actions that are intended to comply with and implement these new rules and regulations as they become effective.

Centralized Regional Wholesale Markets — FERC rules require RTOs to operate centralized regional wholesale energy markets. The FERC required the MISO to begin operation of a “Day 2” wholesale energy market on April 1, 2005. MISO uses security constrained regional economic dispatch and congestion management using Locational Marginal Pricing (LMP) and Financial Transmission Rights (FTRs). The Day 2 market is intended to provide more efficient generation dispatch over the 15 state MISO region.

On Feb. 15, 2007, the MISO filed for FERC approval to establish a “Day 3” centralized regional wholesale ancillary services market (ASM) in 2008. The ASM is intended to provide further efficiencies in generation dispatch by allowing for regional regulation and contingency reserve services through a bid-based market mechanism. In addition, MISO would consolidate

21

the operation of 22 existing North American Electric Reliability Council (NERC) approved balancing authorities (the entity responsible for maintaining reliable operations for a defined geographic region) into a single regional balancing authority. The ASM and balancing authority consolidation are expected to benefit NSP-Minnesota’s integrated operation by reducing the total cost of intermittent generation resources such as wind energy.  On June 21, 2007, the FERC issued an order rejecting the ASM. The FERC stated the ASM could still be implemented in 2008.

Market Based Rate Rules — On June 21, 2007, the FERC issued a final order amending its regulations governing its market-based rate authorizations to electric utilities such as NSP-Minnesota.  The FERC reemphasized its commitment to market-based pricing, but is revising the tests it’s using to assess whether a utility has market power and has emphasized that it intends to exercise greater oversight where it has market-based rate authorizations.  NSP-Minnesota has been granted market-based rate authority and will be subject to the new rule.  NSP-Minnesota is presently analyzing the new rule.

Other Regulatory Matters

Excelsior Energy Inc. (Excelsior) —  In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project. Excelsior filed this petition making claims pursuant to Minnesota statutes relating to an Innovative Energy Project and Clean Energy Technology. NSP-Minnesota opposed the petition.

The MPUC referred this matter to a contested case hearing to act on Excelsior’s petition. The contested case proceeding considered a 603 megawatt (MW) unit in phase I and a second 603 MW unit in phase II of the Mesaba Energy Project.

On April 12, 2007, NSP-Minnesota received the ALJ’s findings regarding phase I of the contested case. The findings constitute a recommendation and is not binding upon the MPUC. The following summarize the four enumerated recommendations in the findings:

·That Excelsior’s petition asking the MPUC to approve, amend, or modify the terms and conditions of the power purchase agreement (PPA) be denied and that the PPA be disapproved.

·In the event the MPUC approves the PPA, that it first be amended through negotiations among Excelsior, NSP-Minnesota and the MDOC to address the deficiencies identified in the findings, then returned to the MPUC for final approval.

·Excelsior’s petition asking the MPUC to determine that the project and its IGCC technology is, or is likely to be, a least-cost resource, thus obligating NSP-Minnesota to use the plant’s generation for at least two percent of the energy supplied to NSP-Minnesota’s retail customers, be denied.

·Excelsior’s petition asking the MPUC to determine that at least 13 percent of the energy supplied to NSP-Minnesota’s retail customers should come from the Units I and II of the Mesaba Energy Project by 2013 be considered in phase 2 of this matter.

The MPUC has scheduled the case for hearing on July 31, 2007 and Aug. 1, 2007.  Phase 2 of the contested case is currently underway.

Renewable Energy Standard — The 2007 Minnesota legislature adopted a Renewable Energy Standard requiring NSP-Minnesota to acquire 30 percent of its energy requirements by 2020 from qualifying renewable sources, of which 25 percent must be wind energy. The legislation allows all NSP-Minnesota renewable resources to count toward meeting the standard and provides greater flexibility toward meeting the standard.  Costs associated with complying with the standard are recoverable through automatic recovery mechanisms.

Conservation and Demand-Side Management Legislation – The 2007 Minnesota legislature adopted a bill establishing a statewide goal to reduce energy demand by 1.5 percent per year and fossil fuel use by 15 percent.  The bill requires utilities to propose conservation and demand-side management programs that achieve at least 1.0 percent per year reduction in energy demand, subject to certain limitations regarding excessive costs for customers, threatened reliability or other negative consequences.  The bill also allows utilities to fund internal infrastructure changes that will contribute to lower energy use and provides for cost recovery outside a rate case for such projects.

NSP-Minnesota Base Load Acquisition Proceeding — On Nov. 1, 2006, NSP-Minnesota filed a proposal with the MPUC for a purchase of 375 MW of capacity and energy from Manitoba Hydro for the period 2015-2025 and the purchase of 380 MW of wind energy to fulfill the base load need identified in the 2004 resource plan. The proposal included a signed term sheet with Manitoba Hydro and a process to acquire the wind energy. Alternative suppliers were entitled to submit competing proposals to the MPUC by Dec. 18, 2006. An alternate supplier proposed a 375 MW share of a lignite plant

22

located in North Dakota and 380 MW of wind energy generation, with an option for Xcel Energy ownership in both components. The MPUC referred the matter to a contested case proceeding.  On July 20, 2007, NSP-Minnesota filed a petition asking the ALJ to suspend the proceeding until NSP-Minnesota can complete analysis of the impact of the RES and conservation goals on its need for additional resources.

Additional Base Load Capacity Projects for Sherco, Monticello and Prairie Island — NSP-Minnesota has committed to file for necessary approvals for projects to increase the capacity and provide additional base load generation from its Sherco, Monticello and Prairie Island generating facilities by Sept. 1, 2007.  On July 20, 2007, NSP-Minnesota filed a Notice of Changed Circumstance with the MPUC seeking to delay these proceedings until NSP-Minnesota can complete analysis of the impact of the RES and conservation goals on its need for additional resources.

NSP-Minnesota Transmission Certificates of Need — In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades for up to 825 MW of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota. In March 2003, the MPUC granted four certificates of need to NSP-Minnesota, thereby approving construction, subject to certain conditions. The initial projected cost of the transmission upgrades was approximately $160 million. The MPUC granted a routing permit for the first major transmission facilities in the development program in 2004. The remaining routing permit proceedings were completed in 2005.

In late 2006, NSP-Minnesota filed two applications for certificates of need with the MPUC for four additional transmission lines in southwestern Minnesota and Chisago County. On June 21, 2007, an ALJ recommended approval of the three 115 KV southwestern Minnesota projects.  Evidentiary hearings regarding the Chisago County project are expected to commence in September 2007.

In addition, NSP-Minnesota along with ten other transmission providers, have announced plans to file certificate of need applications by Aug. 17, 2007, for three 345KV transmission lines serving Minnesota and parts of surrounding states.

FCA Investigation — In 2003, the MPUC opened an investigation to consider the continuing usefulness of fuel clause adjustments for electric utilities in Minnesota. There was no further activity until the MPUC issued a notice for comments on April 5, 2007, to continue the statewide investigation.

Pursuant to the notice, utilities in Minnesota, the MDOC and the OAG filed initial and reply comments on April 30, 2007 and June 1, 2007, respectively.  The utilities generally argued the 2003 investigation could be closed, with remaining issues addressed in the separate investigation initiated by the Dec. 20, 2006 order in the MISO Day 2 cost recovery docket.   The MPUC is now expected to decide whether to continue or close the 2003 investigation.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in 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 Securities and Exchange Commission 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 the end of the period covered by this report, 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 our disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

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

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

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

23

matters. See Notes 4 and 5 of the 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 Note 11 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2006 for a description of certain legal proceedings presently pending.

Item 1A. Risk Factors

NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its 2006 Annual Report on Form 10-K, which is incorporated herein by reference. There have been no material changes to the risk factors.

Item 6. Exhibits

The following Exhibits are filed with this report:

4.01	Supplemental Indenture, dated June 1, 2007, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Company, as successor Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007).
31.01	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
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

24

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on July 30, 2007.

Northern States Power Co. (a Minnesota corporation)

(Registrant)

/s/ TERESA S. MADDEN
	Teresa S. Madden
	Vice President and Controller
/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Vice President and Chief Financial Officer

25