Northern States Power 10-Q 2013 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

or

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

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)

Minnesota	41-1967505
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
414 Nicollet Mall
Minneapolis, Minnesota	55401
(Address of principal executive offices)	(Zip Code)

(612) 330-5500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

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

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

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

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

Class	Outstanding at Aug. 5, 2013
Common Stock, $0.01 par value	1,000,000 shares

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

TABLE OF CONTENTS

PARTI —	FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 4 —	Controls and Procedures	38
PART II —	OTHER INFORMATION
Item 1 —	Legal Proceedings	38
Item 1A —	Risk Factors	38
Item 4 —	Mine Safety Disclosures	38
Item 5 —	Other Information	38
Item 6 —	Exhibits	39
SIGNATURES
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

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

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2013			2012			2013			2012
Operating revenues
Electric, non-affiliates	$	860,234		$	797,294		$	1,701,410		$	1,562,727
Electric, affiliates	110,997			110,756			221,135			219,707
Natural gas	107,451			59,069			342,737			255,583
Other	6,163			5,417			12,798			11,292
Total operating revenues	1,084,845			972,536			2,278,080			2,049,309
Operating expenses
Electric fuel and purchased power	416,178			362,146			805,079			727,474
Cost of natural gas sold and transported	64,767			25,545			223,537			159,735
Cost of sales — other	3,839			2,972			7,414			6,089
Operating and maintenance expenses	286,422			271,611			559,702			532,641
Conservation program expenses	21,178			22,487			46,057			50,171
Depreciation and amortization	103,735			99,923			212,820			198,903
Taxes (other than income taxes)	46,680			48,374			106,135			102,142
Total operating expenses	942,799			833,058			1,960,744			1,777,155
Operating income	142,046			139,478			317,336			272,154
Other (expense) income, net	(1,003		)	(882		)	1,150			1,523
Allowance for funds used during construction — equity	12,339			9,179			22,601			17,214
Interest charges and financing costs
Interest charges — includes other financing costs of $1,552, $1,476, $3,038 and $2,953 respectively	46,477			52,282			91,591			104,402
Allowance for funds used during construction — debt	(5,407		)	(4,937		)	(9,996		)	(9,215		)
Total interest charges and financing costs	41,070			47,345			81,595			95,187
Income before income taxes	112,312			100,430			259,492			195,704
Income taxes	34,611			36,118			79,826			54,406
Net income	$	77,701		$	64,312		$	179,666		$	141,298

See Notes to Consolidated Financial Statements

3

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2013			2012			2013			2012
Net income	$	77,701		$	64,312		$	179,666		$	141,298
Other comprehensive income (loss)
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $17, $30, $32 and $56, respectively	21			44			45			81
Derivative instruments:
Net fair value decrease, net of tax of $(17), $(11,680), $(8) and $(3,163), respectively	(24		)	(16,970		)	(19		)	(4,597		)
Reclassification of losses (gains) to net income, net of tax of $142, $(23), $277 and $(45), respectively	195			(34		)	388			(67		)
	171			(17,004		)	369			(4,664		)
Marketable securities:
Net fair value increase (decrease), net of tax of $0, $84, $(22) and $120, respectively	—			122			(32		)	174
Other comprehensive income (loss)	192			(16,838		)	382			(4,409		)
Comprehensive income	$	77,893		$	47,474		$	180,048		$	136,889

See Notes to Consolidated Financial Statements

4

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30
	2013			2012
Operating activities
Net income	$	179,666		$	141,298
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	215,375			201,290
Nuclear fuel amortization	49,485			49,765
Deferred income taxes	86,471			91,672
Amortization of investment tax credits	(1,339		)	(1,351		)
Allowance for equity funds used during construction	(22,601		)	(17,214		)
Net realized and unrealized hedging and derivative transactions	761			(626		)
Changes in operating assets and liabilities:
Accounts receivable	(61,455		)	(83,951		)
Accrued unbilled revenues	6,608			39,555
Inventories	3,551			57,811
Other current assets	44,212			(25,456		)
Accounts payable	(14,054		)	(62,066		)
Net regulatory assets and liabilities	29,939			(7,165		)
Other current liabilities	10,159			(29,202		)
Pension and other employee benefit obligations	(66,292		)	(73,610		)
Change in other noncurrent assets	15,662			(23,952		)
Change in other noncurrent liabilities	(9,698		)	(5,607		)
Net cash provided by operating activities	466,450			251,191
Investing activities
Utility capital/construction expenditures	(763,109		)	(469,026		)
Proceeds from insurance recoveries	50,000			24,000
Allowance for equity funds used during construction	22,601			17,214
Purchases of investments in external decommissioning fund	(890,700		)	(371,361		)
Proceeds from the sale of investments in external decommissioning fund	887,500			371,361
Investments in utility money pool arrangement	(20,000		)	—
Repayments from utility money pool arrangement	20,000			—
Change in restricted cash	—			94,959
Other, net	(1,198		)	(1,333		)
Net cash used in investing activities	(694,906		)	(334,186		)
Financing activities
Repayments of short-term borrowings, net	(196,000		)	(26,000		)
Borrowings under utility money pool arrangement	526,000			555,000
Repayments under utility money pool arrangement	(506,000		)	(475,000		)
Proceeds from issuance of long-term debt	395,150			—
Capital contributions from parent	120,000			145,621
Dividends paid to parent	(117,447		)	(116,081		)
Net cash provided by financing activities	221,703			83,540
Net change in cash and cash equivalents	(6,753		)	545
Cash and cash equivalents at beginning of period	28,842			26,005
Cash and cash equivalents at end of period	$	22,089		$	26,550
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(77,865	)	$	(96,391	)
Cash received (paid) for income taxes, net	33,262			(21,957		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	155,462		$	170,877

See Notes to Consolidated Financial Statements

5

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	June 30, 2013			Dec. 31, 2012
Assets
Current assets
Cash and cash equivalents	$	22,089		$	28,842
Accounts receivable, net	323,060			325,143
Accounts receivable from affiliates	23,631			26,660
Accrued unbilled revenues	223,056			229,664
Inventories	257,207			260,758
Regulatory assets	176,205			156,223
Derivative instruments	85,642			56,232
Prepayments and other	212,494			94,019
Total current assets	1,323,384			1,177,541
Property, plant and equipment, net	10,018,636			9,546,968
Other assets
Nuclear decommissioning fund and other investments	1,521,250			1,514,156
Regulatory assets	1,060,051			1,039,675
Derivative instruments	47,550			66,480
Other	43,799			56,438
Total other assets	2,672,650			2,676,749
Total assets	$	14,014,670		$	13,401,258
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	9		$	2
Short-term debt	25,000			221,000
Borrowings under utility money pool arrangement	20,000			—
Accounts payable	426,137			367,021
Accounts payable to affiliates	50,401			69,739
Regulatory liabilities	90,644			53,159
Taxes accrued	142,355			175,929
Accrued interest	59,294			58,135
Dividends payable to parent	59,308			58,757
Derivative instruments	17,820			20,117
Provision for rate refund	47,842			686
Other	77,365			102,229
Total current liabilities	1,016,175			1,126,774
Deferred credits and other liabilities
Deferred income taxes	2,109,096			1,944,910
Deferred investment tax credits	29,354			30,304
Regulatory liabilities	438,700			432,471
Asset retirement obligations	1,697,844			1,655,402
Derivative instruments	160,599			174,471
Pension and employee benefit obligations	356,089			422,496
Other	100,066			89,423
Total deferred credits and other liabilities	4,891,748			4,749,477
Commitments and contingencies
Capitalization
Long-term debt	3,888,328			3,488,638
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at June 30, 2013 and Dec. 31, 2012, respectively	10			10
Additional paid in capital	2,701,501			2,581,501
Retained earnings	1,539,725			1,478,057
Accumulated other comprehensive loss	(22,817		)	(23,199		)
Total common stockholder’s equity	4,218,419			4,036,369
Total liabilities and equity	$	14,014,670		$	13,401,258

See Notes to Consolidated Financial Statements

6

NSP-MINNESOTA AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of June 30, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2013 and 2012; and its cash flows for the six months ended June 30, 2013 and 2012.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after June 30, 2013 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2012 balance sheet information has been derived from the audited 2012 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2012.  These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q.  Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations.  For further information, refer to the consolidated financial statements and notes thereto, included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2012, filed with the SEC on Feb. 25, 2013.  Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2012, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin (NSP System) is operated on an integrated basis and managed by NSP-Minnesota. The electric production and transmission costs of the NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A Federal Energy Regulatory Commission (FERC) approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System. Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

2. Accounting Pronouncements

Recently Adopted

Balance Sheet Offsetting — In December 2011, the Financial Accounting Standards Board (FASB) issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (Accounting Standards Update (ASU) No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Minnesota implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 8 for the required disclosures.

Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated other comprehensive income and amounts reclassified out of accumulated other comprehensive income.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  NSP-Minnesota implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 12 for the required disclosures.

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3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	340,947		$	345,563
Less allowance for bad debts	(17,887		)	(20,420		)
	$	323,060		$	325,143

(Thousands of Dollars)	June 30, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	140,405	$	134,952
Fuel	91,468		80,307
Natural gas	25,334		45,499
	$	257,207	$	260,758

(Thousands of Dollars)	June 30, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	12,541,409		$	12,322,677
Natural gas plant	1,036,595			1,027,632
Common and other property	496,121			493,322
Construction work in progress	1,278,541			951,199
Total property, plant and equipment	15,352,666			14,794,830
Less accumulated depreciation	(5,682,091		)	(5,594,064		)
Nuclear fuel	2,142,145			2,090,801
Less accumulated amortization	(1,794,084		)	(1,744,599		)
	$	10,018,636		$	9,546,968

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2012 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit— NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015.  In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011.  As of June 30, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

State Audits— NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of June 30, 2013, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009.  There are currently no state income tax audits in progress.

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

8

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	June 30, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	5.7	$	2.8
Unrecognized tax benefit — Temporary tax positions	18.0		16.7
Total unrecognized tax benefit	$	23.7	$	19.5

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	June 30, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(19.0	)	$	(16.8	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $21 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits at June 30, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2013 or Dec. 31, 2012.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 and in Note 5 to NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter period ended March 31, 2013, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Base Rate

Minnesota 2012 Electric Rate Case—In November 2012, NSP-Minnesota filed a request with the MPUC for an increase in annual revenues of approximately $285 million, or 10.7 percent.  The rate filing is based on a 2013 forecast test year, a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent.  In January 2013, interim rates of approximately $251 million became effective, subject to refund.

In March 2013, NSP-Minnesota filed rebuttal testimony and revised the requested annual revenue increase to approximately $219.7 million, or 8.23 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion and an equity ratio of 52.56 percent.  The updated request reflects alternate proposals in several key areas including:

• Deferral of depreciation expenses and property taxes related to Sherco Unit 3 for 2012 and 2013 and removal of avoided 2013 operating and maintenance (O&M) expense due to the extended outage at Sherco Unit 3.

• Removal of Monticello 2013 license costs from plant in service and deferral of 2013 depreciation expense for the primary Monticello life cycle management (LCM) / extended power uprate (EPU) project until after an MPUC order finding the costs prudent.

• Removal of Prairie Island EPU project costs, reflecting the MPUC decision to cancel the project in December 2012.

• Adjustments to compensation and benefits recovery including Annual Incentive Plan (AIP) to reflect prior MPUC decisions establishing a limitation at 15 percent of base pay using a four-year average AIP target, pension expense and active healthcare costs.

• Adjustment of pension recoveries to reflect amortized recovery of 2008 market losses.

• Recovery of coal pile and ash pond remediation costs at the Black Dog plant through a 15 year amortization.

• Updated forecast for property taxes.

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• Updated forecast with 6 months of actual sales, customer and weather data through December 2012, and updated economic assumptions based on a December 2012 economic forecast, proposing a refund if sales are higher than forecast on a weather-normalized basis.

• Correction to the original filing and other adjustments.

In April 2013, intervenors filed surrebuttal testimony, including the Minnesota Department of Commerce (DOC), Office of Attorney General (OAG), Minnesota Chamber (MCC), Xcel Large Industrials (XLI), Commercial Group, Industrial, Commercial and Institutional Customers, and Energy Cents Coalition.  The DOC recommended a revenue increase of $89.6 million, based on a 9.83 percent ROE, an average electric rate base of approximately $6.1 billion and an equity ratio of 52.56 percent. Subsequently, the DOC’s recommendation was revised to approximately $98.6 million, largely to reflect updated information.

In its surrebuttal testimony, the OAG recommended no recovery for the Prairie Island EPU project, stating it should have been written off in 2012 when cancellation of the project was approved by the MPUC.  The DOC is also not supportive of recovery of the Prairie Island EPU cancelled EPU costs.  The OAG suggests pension recovery in rates exceeds benefit payout because of changes made to benefit plans and recommends correction for an alleged over-collection of funds to pay for future benefits which may never be paid out.  The OAG supports the DOC in adjustments to recovery of annual incentive compensation and does not find NSP-Minnesota’s Sherco Unit 3 proposal warranted.  XLI and MCC also opposed recovery of Sherco Unit 3 costs and Monticello EPU costs.

Through the hearing and briefing process, NSP-Minnesota revised its rate request to approximately $209 million to reflect updated property tax information, resolution of concerns regarding Wisconsin wholesale customers and other adjustments. The $209 million revenue requirement reflects a requested deficiency of $259 million combined with $50 million of rate mitigation through deferral mechanisms.

Administrative Law Judge (ALJ) Recommendation

On July 3, 2013, the Minnesota ALJ issued her report and recommended a rate increase of approximately $127 million, based on a ROE of 9.83 percent, an equity ratio of 52.56 percent and an electric rate base of $6.233 billion. In addition, the ALJ recommendation included approximately $51 million in deferrals of which NSP-Minnesota estimates $34 million will affect net income. The deferrals are related to Sherco Unit 3 and pension.

The ALJ indicated that Sherco Unit 3 should be considered “used and useful” for rate making purposes, but that a portion of the Monticello LCM/EPU would not be considered “used and useful” until NSP-Minnesota obtains the uprate license from the Nuclear Regulatory Commission (NRC). The ALJ also found that the prudency of the cost increases for the Monticello LCM/EPU project and cost recovery for the cancelled Prairie Island EPU project should be determined in the next Minnesota rate case. In addition, the ALJ recommended accepting NSP-Minnesota’s position on the inclusion of the pension market loss and incentive compensation and the DOC’s position on the sales forecast.

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The table below reconciles the final position of NSP-Minnesota, the DOC and the ALJ.

(Millions of Dollars)	NSP-Minnesota Request			DOC Recommendation			ALJ Recommendation
NSP-Minnesota original request	$	285		$	285		$	285
ROE	—			(43		)	(43		)
Sherco Unit 3	(35		)	(40		)	(38		)
Reduced recovery for the nuclear plants	(11		)	(9		)	(14		)
Incentive compensation	(3		)	(20		)	(4		)
Sales forecast	(1		)	(26		)	(26		)
Pension	(10		)	(25		)	(13		)
Employee benefits	(4		)	(6		)	(6		)
Black Dog remediation	(5		)	(5		)	(5		)
NSP-Wisconsin wholesale allocation	(7		)	(7		)	(7		)
Other, net	—			(5		)	(2		)
Recommended rate increase	209			99			127
Preliminary estimated impact of cost deferrals	50			5			34
Estimated impact on 2013 pre-tax income	$	259		$	104		$	161

The MPUC has scheduled deliberations for Aug. 6 and 8, 2013. The MPUC is expected to reach a decision on the issues at the deliberations and issue an order in September 2013.

NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with the interim rates of approximately $16 million and $47 million, as of March 31 and June 30, 2013, respectively.

Pending Regulatory Proceedings — North Dakota Public Service Commission (NDPSC)

Base Rate

North Dakota 2012 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent.  The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent.  In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund. In June 2013, NSP-Minnesota revised its rate increase to $16 million, reflecting updated information. There were no intervenors in this proceeding.

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On July 17, 2013, NDPSC Advocacy Staff filed direct testimony prepared by their rate case consultants. Staff’s testimony recommended a 9.0 percent ROE and other revenue requirement adjustments, which resulted in an overall rate reduction of approximately $2.1 million. Primary revenue requirement adjustments include:

(Millions of Dollars)	Revenue requirement adjustments as filed by the Staff
NSP-Minnesota revised request	$	16.0
Use of a one month coincident peak demand allocator for certain rate base and operation expenses	(20.0		)
ROE	(5.2		)
Incentive compensation	(0.8		)
Adjustment for various O&M expenses	(0.7		)
Calculation of federal income taxes	6.3
Modified cost of capital and increased capital structure to 53.42 percent	1.4
Other, net	0.9
Recommended rate decrease	$	(2.1	)

Additionally, NDPSC Staff recommends customers in NSP-Minnesota’s North Dakota jurisdiction be excluded from paying for costs of certain purchased power agreements.

Next steps in the procedural schedule are expected to be as follows:

• Rebuttal Testimony – Aug. 12, 2013

• Technical Hearings – Aug. 27-28, 2013

• Initial Briefs – Sept. 20, 2013

• Reply Briefs/Proposed Findings – October 2013

A final NDPSC decision on the case is expected in the fourth quarter of 2013.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2012 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Purchased Power Agreements

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

NSP-Minnesota had approximately 1,069 megawatts (MW) and 1,064 MW of capacity under long-term purchased power agreements as of June 30, 2013 and Dec. 31, 2012, respectively, with entities that have been determined to be variable interest entities.  NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  These agreements have expiration dates through the year 2028.

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Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the U.S. Environmental Protection Agency (EPA) proposed a GHG NSPS for newly constructed power plants. The proposal requires that carbon dioxide (CO₂) emission rates be equal to a natural gas combined-cycle plant, even if the plant is coal-fired. The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and that installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. On June 25, 2013, President Obama issued a memorandum directing the EPA to re-propose GHG emission standards for new power plants and develop GHG emission standards for existing power plants. It is not possible to evaluate the impact of these regulations until the upcoming proposals and final requirements are known.

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) and nitrogen oxide (NOx) from utilities in the eastern half of the United States, including Minnesota.  The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule.  The rule also would have created an emissions trading program.

In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA.  The D.C. Circuit stated that the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement.  Although the D.C. Circuit had denied all requests for rehearing, in June 2013, the U.S. Supreme Court elected to review the D.C. Circuit’s 2012 decision to vacate the CSAPR. The Court has ordered the parties to file briefs in the appeal this fall and will likely issue a decision by June 2014.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions.  The CAIR does not currently apply to Minnesota.

Federal Clean Water Act - Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals (CCR). Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. The EPA is also seeking comment on the interaction between the ELG proposal and its proposed CCR rule, which is another proposed rule that would also regulate surface impoundments that store coal combustion byproducts (coal ash) and whether to regulate coal ash as hazardous or nonhazardous waste. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 1, 2017 but no later than July 1, 2022. The impact of this rule on NSP-Minnesota is uncertain at this time.

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

In 2009, the Minnesota Pollution Control Agency (MPCA) approved the state implementation plan (SIP) and submitted it to the EPA for approval.  The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks.  The MPCA concluded Selective Catalytic Reduction (SCR) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA’s source-specific BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO₂.  The combustion controls have been installed on Sherco Units 1 and 2.  The scrubber upgrades are underway and scheduled to be completed by January 2015.

The EPA’s preliminary review of the SIP in 2011 indicated that SCR controls should be added to Sherco Units 1 and 2.  Subsequently, the EPA and MPCA both determined that CSAPR meets BART requirements for purposes of the SIP.  In addition, the MPCA retained its source-specific BART determination for Sherco Units 1 and 2 from the 2009 SIP. The EPA approved the SIP for electric generating units, and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the SIP, but avoided characterizing them as BART limits.

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In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the SIP to the U.S. Court of Appeals for the Eighth Circuit.  The Court denied intervention in the case to NSP-Minnesota and other regulated parties who petitioned to intervene.  In June 2013, the Court ordered this case to be held in abeyance until the U.S. Supreme Court decides the CSAPR case.

The estimated cost for meeting the BART, regional haze and other Clean Air Act requirements is approximately $50 million, of which $34 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2.  NSP-Minnesota anticipates that all costs associated with BART compliance will be fully recoverable through regulatory recovery mechanisms.  If the above litigation results in further EPA proceedings concerning the SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

In addition to the regional haze rules, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program.  In 2009, the U.S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI or what that proposal will entail.  In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club.  The lawsuit alleges that the EPA has failed to perform a nondiscretionary duty to determine BART for the Sherco Units 1 and 2 under the RAVI program.  The EPA filed an answer denying the allegations and asserting that it did not have a nondiscretionary duty under the RAVI program.  The Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the U.S. Court of Appeals for the Eighth Circuit.

Legal Contingencies

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

Environmental Litigation

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in the U.S. District Court for the Northern District of California against Xcel Energy and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO₂ and other greenhouse gases contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In October 2012, the Ninth Circuit affirmed the U.S. District Court’s dismissal and subsequently rejected plaintiffs’ request for rehearing.  In May 2013, the U.S. Supreme Court denied plaintiffs’ request for review, which brings this litigation to a close.  No accrual has been recorded for this matter.

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Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in the U.S. District Court in Mississippi.  The complaint alleges defendants’ CO₂ emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.  In May 2013, the Fifth Circuit affirmed the district court’s dismissal of this lawsuit. It is uncertain whether plaintiffs will seek further review of this decision. Although Xcel Energy believes the likelihood of loss is remote based upon existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota.  NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact.  NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011.  NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011.  In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements.  enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco’s lawsuit is without merit.  On Oct. 22, 2012, NSP-Minnesota filed a motion for summary judgment.  In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor.  On April 23, 2013 enXco filed a notice of appeal to the Eighth Circuit.  It is uncertain when the Eighth Circuit will decide this appeal.  Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

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

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million.  The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation.  NSP-Minnesota received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, and the third installment of $20.7 million in October 2012.  NSP-Minnesota’s third claim submission, in the amount of $42.8 million, was filed May 15, 2013 for costs incurred in 2012. The DOE has until Sept. 1, 2013 to accept or deny the claim, in whole or in part.  Amounts received from the first installments were subsequently credited to customers, except for approved reductions such as legal costs, customer credit amounts still in process at June 30, 2013, and amounts set aside to be credited through another regulatory mechanism.

In NSP-Wisconsin’s 2012 Electric and Gas Rate Case, the Public Service Commission of Wisconsin (PSCW) authorized NSP-Wisconsin to utilize the proceeds from the second and third installments to be included as a reduction of the 2013 electric rate increase.  In December 2012, the MPUC approved NSP-Minnesota’s triennial nuclear decommissioning filing which required NSP-Minnesota to place the Minnesota retail portion of the DOE settlement payments for the third installment of $15.3 million and the anticipated fourth installment in 2013 into the nuclear decommissioning fund when received.  NSP-Minnesota proposed to contribute the second, third and fourth installments to the nuclear decommissioning fund to offset the increase in the decommissioning accrual that was included in the 2012 North Dakota electric rate case.  That filing is pending NDPSC action.

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7. Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool— Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries.  Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.  Money pool borrowings for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250
Amount outstanding at period end	20			—
Average amount outstanding	89			56
Maximum amount outstanding	211			236
Weighted average interest rate, computed on a daily basis	0.30		%	0.33		%
Weighted average interest rate at period end	0.28			N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	500		$	500
Amount outstanding at period end	25			221
Average amount outstanding	25			59
Maximum amount outstanding	149			302
Weighted average interest rate, computed on a daily basis	0.30		%	0.39		%
Weighted average interest rate at period end	0.29			0.39

Letters of Credit— NSP-Minnesota uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations.  At June 30, 2013 and Dec. 31, 2012, there were $11.1 million and $10.2 million of letters of credit outstanding, respectively, under the credit facility.  All letters of credit outstanding were issued under the credit facility at June 30, 2013 and Dec. 31, 2012.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an amount exceeding available capacity under this credit facility.  The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At June 30, 2013, NSP-Minnesota had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	500.0	$	36.1	$	463.9

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Minnesota had no direct advances on the credit facility outstanding at June 30, 2013 and Dec. 31, 2012.

Long-Term Borrowings

In May 2013, NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due May 15, 2023.

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8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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

Investments in debt securities— Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

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

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

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

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

Non-Derivative Instruments Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants.  Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants.  The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale.  NSP-Minnesota plans to reinvest matured securities until decommissioning begins.  The MPUC approved NSP-Minnesota’s proposed change in escrow fund investment strategy in September 2012.  The MPUC approved an asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

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

Unrealized gains for the nuclear decommissioning fund were $169.6 million and $135.8 million at June 30, 2013 and Dec. 31, 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $81.6 million and $46.4 million at June 30, 2013 and Dec. 31, 2012, respectively.

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements, in the nuclear decommissioning fund, at June 30, 2013 and Dec. 31, 2012:

	June 30, 2013
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	32,663	$	32,663	$	—	$	—	$	32,663
Commingled funds	415,197		—		414,899		—		414,899
International equity funds	66,452		—		65,606		—		65,606
Private equity investments	36,496		—		—		45,590		45,590
Real estate	30,357		—		—		38,140		38,140
Debt securities:
Government securities	56,017		—		49,702		—		49,702
U.S. corporate bonds	131,917		—		134,571		—		134,571
International corporate bonds	18,859		—		18,703		—		18,703
Municipal bonds	190,353		—		182,225		—		182,225
Equity securities:
Common stock	429,086		513,339		—		—		513,339
Total	$	1,407,397	$	546,002	$	865,706	$	83,730	$	1,495,438

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $25.8 million of miscellaneous investments.

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	Dec. 31, 2012
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	246,904	$	237,938	$	8,966	$	—	$	246,904
Commingled funds	396,681		—		417,583		—		417,583
International equity funds	66,452		—		69,481		—		69,481
Private equity investments	27,943		—		—		33,250		33,250
Real estate	32,561		—		—		39,074		39,074
Debt securities:
Government securities	21,092		—		21,521		—		21,521
U.S. corporate bonds	162,053		—		169,488		—		169,488
International corporate bonds	15,165		—		16,052		—		16,052
Municipal bonds	21,392		—		23,650		—		23,650
Asset-backed securities	2,066		—		—		2,067		2,067
Mortgage-backed securities	28,743		—		—		30,209		30,209
Equity securities:
Common stock	379,093		420,263		—		—		420,263
Total	$	1,400,145	$	658,201	$	726,741	$	104,600	$	1,489,542

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $24.6 million of miscellaneous investments.

The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2013 and 2012:

(Thousands of Dollars)	April 1, 2013		Purchases		Settlements			Gains Recognized as Regulatory Liabilities		Transfers Out of Level 3		June 30, 2013
Private equity investments	$	34,506	$	7,298	$	—		$	3,786	$	—	$	45,590
Real estate	40,406		2,032		(4,723		)	425		—		38,140
Total	$	74,912	$	9,330	$	(4,723	)	$	4,211	$	—	$	83,730

(Thousands of Dollars)	April 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			Transfers Out of Level 3		June 30, 2012
Private equity investments	$	20,068	$	3,235	$	—		$	—		$	—	$	23,303
Real estate	27,905		2,271		—			2,545			—		32,721
Asset-backed securities	16,547		—		(9,458		)	(21		)	—		7,068
Mortgage-backed securities	68,671		7,414		(9,690		)	(74		)	—		66,321
Total	$	133,191	$	12,920	$	(19,148	)	$	2,450		$	—	$	129,413

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(Thousands of Dollars)	Jan. 1, 2013		Purchases		Settlements			Gains Recognized as Regulatory Liabilities		Transfers Out of Level 3 (a)			June 30, 2013
Private equity investments	$	33,250	$	8,554	$	—		$	3,786	$	—		$	45,590
Real estate	39,074		6,818		(9,022		)	1,270		—			38,140
Asset-backed securities	2,067		—		—			—		(2,067		)	—
Mortgage-backed securities	30,209		—		—			—		(30,209		)	—
Total	$	104,600	$	15,372	$	(9,022	)	$	5,056	$	(32,276	)	$	83,730

^(a)  Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements.

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

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2013:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	—	$	2,793	$	11,211	$	35,698	$	49,702
U.S. corporate bonds	1,734		39,998		81,716		11,123		134,571
International corporate bonds	—		3,115		14,588		1,000		18,703
Municipal bonds	3,790		24,313		26,270		127,852		182,225
Debt securities	$	5,524	$	70,219	$	133,785	$	175,673	$	385,201

Derivative Instruments Fair Value Measurements

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

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

At June 30, 2013, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges.

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

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

At June 30, 2013, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2016.  NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2013 and 2012.

At June 30, 2013, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2013 and Dec. 31, 2012:

(Amounts in Thousands)(a)(b)	June 30, 2013	Dec. 31, 2012
Megawatt hours (MWh) of electricity	78,790	55,163
Million British thermal units (MMBtu) of natural gas	—	26
Gallons of vehicle fuel	320	375

^(a)  Amounts are not reflective of net positions in the underlying commodities.

^(b)  Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

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

NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.  Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.  At June 30, 2013, six of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $32.7 million or 32 percent of this credit exposure at June 30, 2013, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining four significant counterparties, comprising $9.6 million or 9 percent of this credit exposure at June 30, 2013, were not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included as a component of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:

	Three Months Ended June 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive (loss) income related to cash flow hedges at April 1	$	(21,195	)	$	611
After-tax net unrealized losses related to derivatives accounted for as hedges	(24		)	(16,970		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	195			(34		)
Accumulated other comprehensive loss related to cash flow hedges at June 30	$	(21,024	)	$	(16,393	)

	Six Months Ended June 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(21,393	)	$	(11,729	)
After-tax net unrealized losses related to derivatives accounted for as hedges	(19		)	(4,597		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	388			(67		)
Accumulated other comprehensive loss related to cash flow hedges at June 30	$	(21,024	)	$	(16,393	)

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended June 30, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—	$	346		(a)	$	—			$	—
Vehicle fuel and other commodity	(41		)	—		(9		)	(b)	—				—
Total	$	(41	)	$	—	$	337			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—			$	(498	)	(c)
Electric commodity	—			53,974		—				(13,764		)	(d)	—
Total	$	—		$	53,974	$	—			$	(13,764	)		$	(498	)

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	Six Months Ended June 30, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and(Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—	$	688		(a)	$	—			$	—
Vehicle fuel and other commodity	(27		)	—		(23		)	(b)	—				—
Total	$	(27	)	$	—	$	665			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—			$	2,278	(c)
Electric commodity	—			60,393		—				(28,993		)	(d)	—
Natural gas commodity	—			2		—				—				—
Total	$	—		$	60,395	$	—			$	(28,993	)		$	2,278

	Three Months Ended June 30, 2012
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and(Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(28,532	)	$	—	$	(27	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(118		)	—		(30		)	(b)	—				—
Total	$	(28,650	)	$	—	$	(57	)		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—			$	1,588	(c)
Electric commodity	—			38,174		—				(9,714		)	(d)	—
Natural gas commodity	—			96		—				—				—
Total	$	—		$	38,270	$	—			$	(9,714	)		$	1,588

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	Six Months Ended June 30, 2012
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and(Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(7,745	)	$	—		$	(54	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(15		)	—			(58		)	(b)	—				—
Total	$	(7,760	)	$	—		$	(112	)		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—			$	3,311	(c)
Electric commodity	—			39,756			—				(17,685		)	(d)	—
Natural gas commodity	—			(2,564		)	—				16,158			(e)	—
Total	$	—		$	37,192		$	—			$	(1,527	)		$	3,311

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to operating and maintenance (O&M) expenses.

^(c)  Amounts are recorded to electric operating revenues.  Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

^(d)  Amounts are recorded to electric fuel and purchased power.  These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

^(e)  Amounts are recorded to cost of natural gas sold and transported.  These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2013 and 2012.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features— Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale (NPNS) contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings.  If the credit ratings of NSP-Minnesota were downgraded below investment grade, derivative instruments reflected in a $20.4 million gross liability position on the consolidated balance sheet at June 30, 2013 would have required NSP-Minnesota to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.0 million at June 30, 2013.  At June 30, 2013 there was no collateral posted on these specific contracts.  At Dec. 31, 2012, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses.  These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired.  NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2013 and Dec. 31, 2012.

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Recurring Fair Value Measurements— The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2013:

	June 30, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	34	$	—	$	34	$	—		$	34
Other derivative instruments:
Commodity trading	—		17,929		2,349		20,278		(5,371		)	14,907
Electric commodity	—		—		50,105		50,105		(2,823		)	47,282
Total current derivative assets	$	—	$	17,963	$	52,454	$	70,417	$	(8,194	)	62,223
Purchased power agreements (a)												23,419
Current derivative instruments												$	85,642
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	14	$	—	$	14	$	(14	)	$	—
Other derivative instruments:
Commodity trading	—		28,867		55		28,922		(3,410		)	25,512
Total noncurrent derivative assets	$	—	$	28,881	$	55	$	28,936	$	(3,424	)	25,512
Purchased power agreements (a)												22,038
Noncurrent derivative instruments												$	47,550
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	10,011	$	2,468	$	12,479	$	(8,775	)	$	3,704
Electric commodity	—		—		2,823		2,823		(2,823		)	—
Total current derivative liabilities	$	—	$	10,011	$	5,291	$	15,302	$	(11,598	)	3,704
Purchased power agreements (a)												14,116
Current derivative instruments												$	17,820
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	10,741	$	—	$	10,741	$	(3,424	)	$	7,317
Total noncurrent derivative liabilities	$	—	$	10,741	$	—	$	10,741	$	(3,424	)	7,317
Purchased power agreements (a)												153,282
Noncurrent derivative instruments												$	160,599

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2013. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012:

	Dec. 31, 2012
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	52	$	—	$	52	$	—		$	52
Other derivative instruments:	��
Commodity trading	—		19,871		692		20,563		(3,374		)	17,189
Electric commodity	—		—		16,724		16,724		(843		)	15,881
Total current derivative assets	$	—	$	19,923	$	17,416	$	37,339	$	(4,217	)	33,122
Purchased power agreements (a)												23,110
Current derivative instruments												$	56,232
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	47	$	—	$	47	$	(47	)	$	—
Other derivative instruments:
Commodity trading	—		37,513		76		37,589		(2,616		)	34,973
Total noncurrent derivative assets	$	—	$	37,560	$	76	$	37,636	$	(2,663	)	34,973
Purchased power agreements (a)												31,507
Noncurrent derivative instruments												$	66,480
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	12,664	$	—	$	12,664	$	(6,400	)	$	6,264
Electric commodity	—		—		843		843		(843		)	—
Natural gas commodity	—		2		—		2		—			2
Total current derivative liabilities	$	—	$	12,666	$	843	$	13,509	$	(7,243	)	6,266
Purchased power agreements (a)												13,851
Current derivative instruments												$	20,117
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	17,966	$	—	$	17,966	$	(2,664	)	$	15,302
Total noncurrent derivative liabilities	$	—	$	17,966	$	—	$	17,966	$	(2,664	)	15,302
Purchased power agreements (a)												159,169
Noncurrent derivative instruments												$	174,471

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2012.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following tables present the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30
(Thousands of Dollars)	2013			2012
Balance at April 1	$	7,642		$	5,324
Purchases	51,386			37,296
Settlements	(8,503		)	(12,675		)
Net transactions recorded during the period:
Losses recognized in earnings (a)	(217		)	—
(Losses) gains recognized as regulatory assets and liabilities	(3,090		)	3,844
Balance at June 30	$	47,218		$	33,789

	Six Months Ended June 30
(Thousands of Dollars)	2013			2012
Balance at Jan. 1	$	16,649		$	12,417
Purchases	51,386			37,297
Settlements	(20,952		)	(21,560		)
Net transactions recorded during the period:
Losses recognized in earnings (a)	(279		)	(9		)
Gains recognized as regulatory liabilities	414			5,644
Balance at June 30	$	47,218		$	33,789

^(a)  These amounts relate to commodity derivatives held at the end of the period.

NSP-Minnesota recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for the three and six months ended June 30, 2013 and 2012.

Fair Value of Long-Term Debt

As of June 30, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2013				Dec. 31, 2012
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,888,337	$	4,217,525	$	3,488,640	$	4,181,580

The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of June 30, 2013 and Dec. 31, 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  

9. Other (Expense) Income, Net

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

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2013			2012			2013			2012
Interest income (expense)	$	254		$	(83	)	$	3,652		$	3,756
Other nonoperating (expense) income	(156		)	168			121			472
Insurance policy expense	(1,101		)	(967		)	(2,623		)	(2,705		)
Other (expense) income, net	$	(1,003	)	$	(882	)	$	1,150		$	1,523

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10. Segment Information

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

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

• NSP-Minnesota’s regulated electric utility segment generates electricity which is transmitted and distributed in Minnesota, North Dakota and South Dakota.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.

• NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota.

• Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

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

To report income from continuing operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues	$	971,231	$	107,451	$	6,163		$	—		$	1,084,845
Intersegment revenues	164		254		—			(418		)	—
Total revenues	$	971,395	$	107,705	$	6,163		$	(418	)	$	1,084,845
Net income (loss)	$	78,195	$	2,595	$	(3,089	)	$	—		$	77,701

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2012
Operating revenues	$	908,050	$	59,069		$	5,417	$	—		$	972,536
Intersegment revenues	144		139			—		(283		)	—
Total revenues	$	908,194	$	59,208		$	5,417	$	(283	)	$	972,536
Net income (loss)	$	64,921	$	(2,811	)	$	2,202	$	—		$	64,312

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues	$	1,922,545	$	342,737	$	12,798	$	—		$	2,278,080
Intersegment revenues	299		399		—		(698		)	—
Total revenues	$	1,922,844	$	343,136	$	12,798	$	(698	)	$	2,278,080
Net income	$	148,193	$	23,733	$	7,740	$	—		$	179,666

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2012
Operating revenues	$	1,782,434	$	255,583	$	11,292	$	—		$	2,049,309
Intersegment revenues	267		380		—		(647		)	—
Total revenues	$	1,782,701	$	255,963	$	11,292	$	(647	)	$	2,049,309
Net income	$	124,202	$	11,486	$	5,610	$	—		$	141,298

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	8,291		$	7,336		$	30		$	24
Interest cost	10,933			12,301			1,225			1,814
Expected return on plan assets	(15,788		)	(16,836		)	(104		)	(109		)
Amortization of transition obligation	—			—			8			336
Amortization of prior service cost (credit)	514			2,955			(759		)	(30		)
Amortization of net loss	13,247			10,196			1,318			853
Net periodic benefit cost	17,197			15,952			1,718			2,888
Costs not recognized due to the effects of regulation	(6,772		)	(9,083		)	—			—
Net benefit cost recognized for financial reporting	$	10,425		$	6,869		$	1,718		$	2,888

	Six Months Ended June 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	16,583		$	14,706		$	60		$	48
Interest cost	21,867			24,610			2,450			3,565
Expected return on plan assets	(31,576		)	(33,658		)	(208		)	(219		)
Amortization of transition obligation	—			—			16			673
Amortization of prior service cost (credit)	1,028			5,910			(1,518		)	(59		)
Amortization of net loss	26,494			20,065			2,636			1,602
Net periodic benefit cost	34,396			31,633			3,436			5,610
Costs not recognized due to the effects of regulation	(13,544		)	(17,141		)	—			—
Net benefit cost recognized for financial reporting	$	20,852		$	14,492		$	3,436		$	5,610

In January 2013, contributions of $191.5 million were made across four of Xcel Energy’s pension plans, of which $72.1 million was attributable to NSP-Minnesota.  Xcel Energy does not expect additional pension contributions during 2013.

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12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2013 were as follows:

	Three Months Ended June 30, 2013
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(21,195	)	$	(131	)	$	(1,683	)	$	(23,009	)
Other comprehensive loss before reclassifications	(24		)	—			—			(24		)
Losses reclassified from net accumulated other comprehensive loss	195			—			21			216
Net current period other comprehensive income	171			—			21			192
Accumulated other comprehensive loss at June 30	$	(21,024	)	$	(131	)	$	(1,662	)	$	(22,817	)

	Six Months Ended June 30, 2013
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(21,393	)	$	(99	)	$	(1,707	)	$	(23,199	)
Other comprehensive loss before reclassifications	(19		)	(32		)	—			(51		)
Losses reclassified from net accumulated other comprehensive loss	388			—			45			433
Net current period other comprehensive income (loss)	369			(32		)	45			382
Accumulated other comprehensive loss at June 30	$	(21,024	)	$	(131	)	$	(1,662	)	$	(22,817	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2013				Six Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		(a)	$	688		(a)
Vehicle fuel derivatives	(9		)	(b)	(23		)	(b)
Total, pre-tax	337				665
Tax benefit	(142		)		(277		)
Total, net of tax	195				388
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	85			(c)	170			(c)
Prior service cost	(47		)	(c)	(94		)	(c)
Transition obligation	—			(c)	1			(c)
Total, pre-tax	38				77
Tax benefit	(17		)		(32		)
Total, net of tax	21				45
Total amounts reclassified, net of tax	$	216			$	433

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

^(c)  Included in the computation of net periodic pension and post retirement benefit costs.  See Note 11 for details regarding these benefit plans.

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2012, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2013.

Results of Operations

NSP-Minnesota’s net income was approximately $179.7 million for the six months ended June 30, 2013, compared with approximately $141.3 million for the same period in 2012.  Earnings were positively impacted by the Minnesota and North Dakota interim electric rates, subject to refund, an electric rate increase in South Dakota and lower interest charges. Further, natural gas margins increased due to cooler weather. These factors were partially offset by higher O&M expenses and depreciation.

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Electric Revenues and Margin

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

	Six Months Ended June 30
(Millions of Dollars)	2013			2012
Electric revenues	$	1,923		$	1,782
Electric fuel and purchased power	(805		)	(727		)
Electric margin	$	1,118		$	1,055

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

Electric Revenues

(Millions of Dollars)	2013 vs. 2012
Retail rate increases (Minnesota interim, South Dakota and North Dakota interim) (a)	$	84
Fuel and purchased power cost recovery	57
Transmission revenue	23
Estimated impact of weather	12
Retail sales decrease (excluding weather impact)	(9		)
Conservation revenue (offset by expenses)	(8		)
Non-fuel riders	(5		)
Conservation incentive	(5		)
Other, net	(8		)
Total increase in electric revenues	$	141

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increases (Minnesota interim, South Dakota and North Dakota interim) (a)	$	84
Transmission revenue, net of costs	15
Estimated impact of weather	12
Retail sales decrease (excluding weather impact)	(9		)
Conservation revenue (offset by expenses)	(8		)
Non-fuel riders	(5		)
Conservation incentive	(5		)
Other, net	(21		)
Total increase in electric margin	$	63

^(a)  NSP-Minnesota recognized a reserve for revenue subject to refund of approximately $47 million, for the six months ended June 30, 2013. See Note 5 to the consolidated financial statements for additional discussion.

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Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases.  However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.  The following table details natural gas revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2013			2012
Natural gas revenues	$	343		$	256
Cost of natural gas sold and transported	(224		)	(160		)
Natural gas margin	$	119		$	96

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

Natural Gas Revenues

(Millions of Dollars)	2013 vs. 2012
Purchased natural gas adjustment clause recovery	$	64
Estimated impact of weather	15
Conservation revenue (offset by expenses)	4
Retail sales increase (excluding weather impact)	3
Other, net	1
Total increase in natural gas revenues	$	87

Natural Gas Margin

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	15
Conservation revenue (offset by expenses)	4
Retail sales increase (excluding weather impact)	3
Other, net	1
Total increase in natural gas margin	$	23

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased $27.1 million, or 5.1 percent, for the six months ended June 30, 2013 compared with the same period in 2012.  The following table summarizes the changes in O&M expenses for the six months ended June 30:

(Millions of Dollars)	2013 vs. 2012
Nuclear plant operations and amortization	$	18
Storm damage restoration	4
Interchange agreement billing with NSP-Wisconsin	4
Information technology costs	4
Transmission costs	3
Plant generation costs	(5		)
Other, net	(1		)
Total increase in O&M expenses	$	27

• Costs related to nuclear plant operations and amortization increased mainly due to operational initiatives;

• Storm damage restoration was due to power outages experienced during the second quarter of 2013;

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Conservation Program Expenses — Conservation program expenses decreased $4.1 million, or 8.2 percent, for the six months ended June 30, 2013 compared with the same period in 2012.  The decreased expense is primarily attributable to the timing of recovery of electric conservation program expenses partially offset by higher gas and electric rates used to recover program expenses. Conservation program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization— Depreciation and amortization expense increased $13.9 million, or 7.0 percent, for the six months ended June 30, 2013 compared with the same period in 2012.  The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased $4.0 million, or 3.9 percent, for the six months ended June 30, 2013 compared with the same period in 2012.  The increase is due to higher property taxes primarily in Minnesota.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $6.2 million for the six months ended June 30, 2013 compared with the same period in 2012.  The increase is primarily due to the expansion of transmission facilities related to CapX2020.

Interest Charges — Interest charges decreased $12.8 million, or 12.3 percent, for the six months ended June 30, 2013 compared with the same period in 2012. The decrease is due to lower interest rates, primarily related to refinancings, partially offset by higher long-term debt levels to fund investments in utility operations.

Income Taxes — Income tax expense increased $25.4 million for the six months ended June 30, 2013 compared with the same period in 2012.  The increase in income tax expense was primarily due to higher pretax earnings in 2013 and a discrete tax benefit of approximately $15.0 million for a carryback in 2012.  These were partially offset by recognition of research and experimentation credits in 2013 due to the passage of the American Taxpayer Relief Act of 2012 in 2013 and a tax benefit for a carryback claim related to 2013. The ETR was 30.8 percent for the six months ended June 30, 2013 compared with 27.8 percent for the same period in 2012.  The lower ETR for 2012 was primarily due to the carryback adjustment, partially offset by a tax benefit for a carryback claim related to 2013 and research and experimentation credits in 2013.

Public Utility Regulation

Minnesota Resource Plan — In March 2013, the MPUC approved NSP-Minnesota’s 2011-2025 Resource Plan.  The MPUC ordered that a competitive acquisition process be conducted with the goal of adding approximately 500 MW of generation to the NSP System between 2017 and 2019.  In February 2013, NSP-Minnesota also issued a Request for Proposal (RFP) for up to 200 MW of wind generation, to the extent that cost effective opportunities can be identified. Proposals for both RFPs may be for purchase power agreements (PPA), self-build or contracts with a build-ownership transfer option.  Bid proposals in response to the two RFPs were received in April 2013.

The competitive acquisition schedule is expected to be as follows:

• Continued evaluation of generation bids through contested case process managed by ALJ – August-October 2013

• ALJ will report to the MPUC which project should be selected – December 2013

• MPUC to make a final ruling – February-March 2014

On July 16, 2013, NSP-Minnesota filed a petition with the MPUC seeking approval of three 200 MW wind generation projects. NSP-Minnesota requested approval by October 2013. Potential projects are as follows:

• Odell is a 200 MW wind farm located near Mountain Lake, Minn. This is a 20-year PPA with Geronimo Energy. The project is expected to be operational in late 2015.

• Courtenay is a 200 MW wind farm located near Jamestown, N.D. This is a 20-year PPA with Geronimo Energy. The project is expected to operational by September 2015.

• Pleasant Valley is a 200 MW wind farm to be located near Austin, Minn. It will be developed and constructed by RES Americas, who will transfer ownership to NSP-Minnesota upon construction completion. Pleasant Valley is expected to operational by October 2015.

• In addition, NSP-Minnesota has been in discussions with RES Americas regarding an additional 150 MW build-ownership project. This may be brought to the MPUC and the NDPSC in separate petitions, depending on transmission costs which will be determined by MISO.

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CapX2020Transmission Expansion — In 2009, the MPUC approved separate Certificate of Need (CON) applications to construct one 230 kilovolt (kV) electric transmission line and three 345 kV electric transmission lines as part of the CapX2020 project.  The estimated cost of the four transmission projects is $1.9 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total cost.  The remainder of the costs will be borne by other utilities in the upper Midwest.  These cost estimates will be updated as the projects progress.

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 kV transmission line

In May 2012, the MPUC issued a route permit for the Minnesota portion of the project and the PSCW approved a certificate of public convenience and necessity (CPCN) for the Wisconsin portion of the project.  Federal approval of the project was granted in January 2013.  Two parties filed an appeal with the Minnesota Court of Appeals against the MPUC’s route permit decision, and the Court of Appeals issued an order on June 10, 2013, upholding the MPUC’s determination. One party has requested Minnesota Supreme Court review of the MPUC’s route permit decision, citing similar arguments to those presented unsuccessfully to the Court of Appeals. On July 3, 2013, the FERC denied a complaint filed by two citizen groups in March 2013 against the project. Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2015.

Minnesota Solar Legislation —In May 2013, Minnesota’s Governor signed into law legislation requiring that 1.5 percent, of which at least 10 percent must be rooftop, of a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. The legislation also authorized two new solar programs, a community solar garden program that must have a minimum of five subscribers and a new solar energy program that authorizes the spending of five million dollars over five years to implement a solar energy production incentive payment for solar energy systems equal to or less than 20 kilowatts. Both programs require approval by the MPUC. Xcel Energy is currently assessing the impact of this legislation.

Minnesota Multi-Year Plan —In June 2013, the MPUC issued guidelines to allow utilities within its jurisdiction to file multi-year rate plans. Under a multi-year rate plan, utilities would be required to show clearly identified capital projects and non-capital costs for which it sought recovery over a period no longer than three years. NSP-Minnesota would file fixed rates over the period, with one ROE applying throughout the plan. A multi-year plan request would be filed within the context of a general rate case.

Annual Automatic Adjustment (AAA) of Charges — As part of the 2012 AAA dockets in June 2013, the DOC included a fuel clause incentive proposal that would normalize Fuel Clause Adjustment (FCA) recovery using monthly patterns derived from averages of the prior three year period, setting and fixing this level during a rate case with no adjustment between rate cases. While this may set a limitation of monthly FCA costs, it would be largely based on costs NSP-Minnesota does not control, such as the price of fuel and not recognize new events or changed circumstances which would dilute the impact of those events and circumstances until three or more years had passed. NSP-Minnesota’s reply comments are expected to be filed in August 2013.

Minneapolis, Minn. Franchise Agreement —On June 28, 2013, two measures were authorized by the Minneapolis City Council. The first measure allowed for public hearings to be held regarding the establishment of a municipal electric and natural gas utility. These hearings were held on Aug. 1, 2013. The Minneapolis City Council has until Aug. 16, 2013 to vote on placing a measure on the November 2013 ballot to further pursue forming a municipal utility. The second measure authorized a $250,000 study that will explore the various paths the City of Minneapolis could take to achieve its energy goals, including examination of potential utility partnerships, changes to how the City of Minneapolis uses energy utility franchise fees and the potential for municipalization of one or both energy utilities. Any potential municipalization of the public utilities would require a vote of the Minneapolis City Council to authorize the city to establish a municipal utility, and a subsequent special election to obtain voter ratification of the council action.

Should Minneapolis attempt to condemn Xcel Energy facilities, Xcel Energy would seek to obtain full compensation for the property and business taken by Minneapolis and for all damages resulting to Xcel Energy and its system. Xcel Energy would also seek appropriate compensation for stranded costs with the FERC.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant.  See Note 14 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 for further discussion regarding the nuclear generating plants.

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

In March 2012, the NRC issued three orders and a request for additional information to all licensees.  The orders included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant.  The request for additional information included requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards and to assess the emergency preparedness staffing and communications capabilities at each plant.  Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance to meet the orders is expected to begin in the second quarter of 2015 with all units expected to be fully compliant by December 2016.

In June 2013, the NRC issued a revised order with regard to reliable hardened containment vents that superseded the March 2012 order. The revised order added severe accident conditions under which the existing hardened vent which comes off of the wet portion of the containment needs to operate and requires a second hardened vent off of the dry portion of the containment. The revised order requires that any necessary changes to the existing vent are to be completed by the second quarter of 2017 refueling outage at the Monticello plant and a new vent to be added by the second quarter of 2019 refueling outage. Portions of the work that fall under the requests for additional information are expected to be completed by 2018.

NSP-Minnesota expects that complying with these requirements will cost approximately $40 to $60 million at the Monticello and Prairie Island plants. NSP-Minnesota believes the costs associated with compliance for both the March 2012 and June 2013 orders would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

Nuclear Plant Power Uprates

Monticello Nuclear Plant EPU — In 2008, NSP-Minnesota filed for both state and federal approvals of an EPU of approximately 71 MW for NSP-Minnesota’s Monticello nuclear generating plant. The MPUC approved the CON for the EPU in 2008. The NRC staff has placed the license amendment filing on hold to address concerns raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance. In September 2012, NSP-Minnesota made a supplemental filing to the NRC to address the containment accident pressure concern. NSP-Minnesota completed implementation of the equipment changes needed to support the Monticello 20-year life extension and EPU projects during the plant’s 2013 refueling outage, which concluded when the plant commenced operations on July 19, 2013. However, the plant will not be permitted to operate at the higher uprate capacity levels without NRC approval. NSP-Minnesota expects to receive approval of the EPU license by the NRC in the second half of 2013. The method and timing of rate recovery of the costs associated with the Monticello life extension and EPU construction projects is included as part of the 2013 electric rate case. Ultimately, the project costs will be subject to a prudence review by the MPUC as part of the 2014 electric rate case, currently planned to be filed in the fall 2013.

The EPU project was completed concurrently with life cycle management (LCM) work at Monticello to support the 20-year extension of the operating license for the plant.  A preliminary cost estimate provided to the MPUC in 2008 as part of the EPU CON filing was $320 million, including both LCM and EPU work.  The total construction budget estimate for the LCM/EPU project of $587 million (determined in late 2011) was included in the 2013 Minnesota electric rate case filing and revised during the case to $640 million.  Final costs of the project after completion of the 2013 outage are now projected to be approximately $650 million, depending on the results of ongoing vendor cost negotiations.  The primary reasons for the increased cost estimates of Monticello’s LCM/EPU project include (a) outside events have affected the NRC’s schedule and requirements, adding time and cost to the project; (b) our original estimate was based on preliminary engineering and a conceptual framework before any detailed work activities were scoped; and (c) we discovered additional work was necessary once our planned work entered the construction phase during the 2011 and 2013 outages.

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Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards.  State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters.  See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2012.  In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature.  If a project qualifies as a multi-value project (MVP), the costs would be fully allocated to all loads in the MISO region.  MVP eligibility is generally obtained for higher voltage (345 kV and higher) projects considered part of a portfolio of projects expected to serve multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving.  Certain parties appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit.  On June 7, 2013, the Court of Appeals for the Seventh Circuit upheld the FERC MVP tariff orders allocating MVP project costs regionally, but remanded the FERC decision to not apply the regional charge to transmission service transactions crossing into the PJM Interconnection, LLC Regional Transmission Organization (RTO). The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery.  Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities.  The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation could be significant in future periods.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — The FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively.  In Order 1000, the FERC required utilities to develop tariffs that provide for joint transmission planning and cost allocation for all FERC-jurisdictional utilities within a region.  In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation.  A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area. Various parties have appealed Order 1000 final rules to the D.C. Circuit Court of Appeals. NSP-Minnesota is participating in the appeals in coordination with other MISO transmission owners and utilities who oppose certain aspects of the rules, including the ROFR prohibition. Initial briefs by parties challenging the final rules were filed May 28, 2013. The FERC is expected to submit its responsive brief in September 2013. Oral arguments have not yet been scheduled. The Court is unlikely to rule before 2014.

The removal of a federal ROFR will eliminate rights that NSP-Minnesota currently has under the MISO tariff to build transmission within its footprint.  Rather, the FERC required that opportunity to build such projects would extend to competitive transmission developers.  Compliance with Order 1000 for NSP-Minnesota will occur through changes to the MISO tariff. MISO made its initial compliance filings to incorporate new provisions into its tariff regarding regional planning and cost allocation. The FERC has ruled on the compliance filing for MISO, directing further changes to fully address the requirements of Order 1000. In addition, MISO has received an extension of the deadline for filing its interregional planning and cost allocation agreement with the Midcontinent Area Power Pool (MAPP) which will likely delay that filing until late third quarter of 2013. Filings to address MISO interregional planning and cost allocation requirements with other regions were made on July 10, 2013.

In 2012, Minnesota enacted legislation that preserves ROFR rights for Minnesota utilities at the state level.  This legislation is similar to legislation previously passed in North Dakota and South Dakota.  The FERC’s initial order on MISO’s compliance filing to address the regional requirements of Order 1000 required MISO to remove proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project and NSP-Minnesota has requested rehearing of this issue. The rehearing request is pending the FERC’s action.

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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 SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of June 30, 2013, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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

Additional Information

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

Item 1A — RISK FACTORS

NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2012, which is incorporated herein by reference.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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Item 6 — EXHIBITS

*Indicates incorporation by reference

3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern Power Corp. as Amended on Aug. 1, 2000 and June 3, 2008 (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
4.01*	Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60% First Mortgage Bonds, Series due May 15, 2023. (Exhibit 4.01 to NSP-Minnesota’s Form 8-K dated May 20, 2013 (file no. 001-31387))
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	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.
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

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

		Northern States Power Company (a Minnesota corporation)
Aug. 5, 2013	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

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