10-Q

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 September 30, 2013

or

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

Commission File Number: 001-03140

Northern States Power Company

(Exact name of registrant as specified in its charter)

Wisconsin	39-0508315
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1414 West Hamilton Avenue
Eau Claire, Wisconsin	54701
(Address of principal executive offices)	(Zip Code)

(715) 737-2625

(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 Oct. 28, 2013
Common Stock, $100 par value	933,000 shares

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

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l    —	Financial Statements (Unaudited)	3
Item 2   —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 4   —	Controls and Procedures	24
PART II — OTHER INFORMATION
Item 1    —	Legal Proceedings	24
Item 1A —	Risk Factors	24
Item 4    —	Mine Safety Disclosures	24
Item 5    —	Other Information	24
Item 6    —	Exhibits	25
SIGNATURES		26

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 Wisconsin corporation (NSP-Wisconsin).  NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Southwestern Public Service Company, a New Mexico corporation (SPS); Public Service Company of Colorado, a Colorado corporation (PSCo); and NSP-Wisconsin.  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-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2013			2012			2013			2012
Operating revenues
Electric	$	216,545		$	214,426		$	592,730		$	575,532
Natural gas	14,266			11,742			89,178			68,064
Other	249			307			742			851
Total operating revenues	231,060			226,475			682,650			644,447
Operating expenses
Electric fuel and purchased power, non-affiliates	4,968			7,516			11,000			15,431
Purchased power, affiliates	106,554			103,572			305,539			301,551
Cost of natural gas sold and transported	7,483			5,656			52,770			39,658
Operating and maintenance expenses	42,521			41,726			127,189			122,718
Conservation program expenses	3,133			3,714			9,243			10,836
Depreciation and amortization	19,359			17,338			57,265			51,440
Taxes (other than income taxes)	6,273			6,218			19,008			18,816
Total operating expenses	190,291			185,740			582,014			560,450
Operating income	40,769			40,735			100,636			83,997
Other (expense) income, net	(61		)	(85		)	209			375
Allowance for funds used during construction — equity	1,029			(385		)	2,755			1,379
Interest charges and financing costs
Interest charges — includes other financing costs of $389, $375, $1,150 and $1,185, respectively	7,191			5,944			20,860			18,003
Allowance for funds used during construction — debt	(471		)	(995		)	(1,280		)	(1,220		)
Total interest charges and financing costs	6,720			4,949			19,580			16,783
Income before income taxes	35,017			35,316			84,020			68,968
Income taxes	13,004			13,116			31,778			26,148
Net income	$	22,013		$	22,200		$	52,242		$	42,820

See Notes to Consolidated Financial Statements

3

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
	2013		2012		2013		2012
Net income	$	22,013	$	22,200	$	52,242	$	42,820
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $12, $12, $38 and $37, respectively.	20		20		57		58
Other comprehensive income	20		20		57		58
Comprehensive income	$	22,033	$	22,220	$	52,299	$	42,878

See Notes to Consolidated Financial Statements

4

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Nine Months Ended Sept. 30
	2013			2012
Operating activities
Net income	$	52,242		$	42,820
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	58,126			52,291
Deferred income taxes	19,491			19,604
Amortization of investment tax credits	(500		)	(469		)
Allowance for equity funds used during construction	(2,755		)	(1,379		)
Net derivative (gains) losses	(658		)	95
Changes in operating assets and liabilities:
Accounts receivable	2,566			(11,303		)
Accrued unbilled revenues	11,076			9,496
Inventories	(3,382		)	3,924
Other current assets	9,486			6,142
Accounts payable	(3,755		)	(7,307		)
Net regulatory assets and liabilities	(6,260		)	6,150
Other current liabilities	9,635			9,701
Pension and other employee benefit obligations	(9,273		)	(11,002		)
Change in other noncurrent assets	260			(119		)
Change in other noncurrent liabilities	1,555			(500		)
Net cash provided by operating activities	137,854			118,144
Investing activities
Utility capital/construction expenditures	(134,641		)	(106,553		)
Allowance for equity funds used during construction	2,754			1,379
Other, net	(249		)	1,096
Net cash used in investing activities	(132,136		)	(104,078		)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(28,000		)	33,000
(Repayments of) proceeds from notes payable to affiliate	(80		)	50
Repayments of long-term debt	(109		)	(48		)
Capital contributions from parent	42,481			2,162
Dividends paid to parent	(22,943		)	(49,306		)
Net cash used in financing activities	(8,651		)	(14,142		)
Net change in cash and cash equivalents	(2,933		)	(76		)
Cash and cash equivalents at beginning of period	4,459			1,571
Cash and cash equivalents at end of period	$	1,526		$	1,495
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(18,366	)	$	(16,925	)
Cash received (paid) for income taxes, net	(2,127		)	1,971
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	10,347		$	8,866

See Notes to Consolidated Financial Statements

5

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	Sept. 30, 2013			Dec. 31, 2012
Assets
Current assets
Cash and cash equivalents	$	1,526		$	4,459
Accounts receivable, net	48,119			50,706
Accrued unbilled revenues	38,062			49,138
Inventories	22,999			19,685
Regulatory assets	17,011			12,048
Prepaid taxes	16,063			24,688
Deferred income taxes	10,466			—
Prepayments and other	2,889			4,394
Total current assets	157,135			165,118
Property, plant and equipment, net	1,378,647			1,298,236
Other assets
Regulatory assets	237,339			240,459
Other investments	3,483			3,232
Other	3,677			4,040
Total other assets	244,499			247,731
Total assets	$	1,780,281		$	1,711,085
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	103		$	1,246
Short-term debt	11,000			39,000
Notes payable to affiliates	470			550
Accounts payable	29,096			30,723
Accounts payable to affiliates	29,158			31,556
Dividends payable to parent	8,038			7,667
Regulatory liabilities	4,233			6,086
Taxes accrued	8,303			839
Environmental liabilities	23,817			23,427
Accrued interest	7,549			7,304
Other	9,627			10,955
Total current liabilities	131,394			159,353
Deferred credits and other liabilities
Deferred income taxes	294,026			261,800
Deferred investment tax credits	9,576			8,911
Regulatory liabilities	125,982			123,746
Environmental liabilities	81,862			84,655
Customer advances	16,861			15,631
Pension and employee benefit obligations	54,354			63,643
Other	9,141			8,923
Total deferred credits and other liabilities	591,802			567,309
Commitments and contingencies
Capitalization
Long-term debt	468,511			467,317
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Sept. 30, 2013 and Dec. 31, 2012, respectively	93,300			93,300
Additional paid in capital	232,349			189,867
Retained earnings	263,305			234,376
Accumulated other comprehensive loss	(380		)	(437		)
Total common stockholder’s equity	588,574			517,106
Total liabilities and equity	$	1,780,281		$	1,711,085

See Notes to Consolidated Financial Statements

6

NSP-WISCONSIN 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-Wisconsin and its subsidiaries as of Sept. 30, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2013 and 2012; and its cash flows for the nine months ended Sept. 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 Sept. 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-Wisconsin 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-Wisconsin 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-Wisconsin’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-Wisconsin 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 and NSP-Wisconsin. 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-Wisconsin 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-Wisconsin 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.

7

3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Accounts receivable, net (a)
Accounts receivable	$	52,596		$	55,039
Less allowance for bad debts	(4,477		)	(4,333		)
	$	48,119		$	50,706

^(a) Accounts receivable, net includes $14 and $586 due from affiliates as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(Thousands of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	6,406	$	6,172
Fuel	5,771		6,664
Natural gas	10,822		6,849
	$	22,999	$	19,685

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	1,869,563		$	1,795,239
Natural gas plant	231,778			224,625
Common and other property	112,514			111,319
Construction work in progress	101,436			62,629
Total property, plant and equipment	2,315,291			2,193,812
Less accumulated depreciation	(936,644		)	(895,576		)
	$	1,378,647		$	1,298,236

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in NSP-Wisconsin’s 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-Wisconsin 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 Sept. 30, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2013, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009.  In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011.  As of Sept. 30, 2013, no material adjustments had been proposed for these years.  There are currently no other 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)	Sept. 30, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.5		1.2
Total unrecognized tax benefit	$	1.7	$	1.3

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)	Sept. 30, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(0.9	)	$	(0.9	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 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 Sept. 30, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2013 or Dec. 31, 2012.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As NSP-Wisconsin had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 and in Note 5 to NSP-Wisconsin’s Quarterly Report on Form 10-Q for the quarter period ended March 31, 2013 and June 30, 2013, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)

Wisconsin 2014 Electric and Gas Rate Case—On May 31, 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent.

The rate filing is based on a 2014 forecast test year, a return on equity (ROE) of 10.4 percent, an equity ratio of 52.5 percent, and a forecasted average net investment rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility.

On Oct. 4, 2013, the PSCW Staff filed their direct testimony and recommended an electric rate increase of $23.8 million, or 3.8 percent, and a natural gas rate decrease of $1.1 million, or 0.9 percent. PSCW Staff’s recommendations were based on a 10.2 percent ROE and a 52.5 percent equity ratio. 

9

The most significant adjustments proposed by the PSCW Staff are shown in the table below:

(Millions of Dollars)	Electric Staff Testimony October 2013			Natural Gas Staff Testimony October 2013
Rate request	$	40.0		$	4.7
Electric fuel and purchased power	(5.1		)	—
Sales forecast	(4.8		)	—
Incentive compensation and merit pay	(3.0		)	(0.6		)
ROE	(1.6		)	(0.2		)
Conservation funding transfer	0.7			(0.7		)
Depreciation expense	(0.7		)	(1.3		)
Ashland site amortization expense	—			(2.3		)
Other, net	(1.7		)	(0.7		)
Recommended rate increase (decrease)	$	23.8		$	(1.1	)

The majority of the adjustment to electric fuel and purchased power is the result of the PSCW Staff’s proposal to discontinue using the New York Mercantile Exchange (NYMEX) futures prices as a basis for setting the fuel price forecast and instead using a discounted percentage of the NYMEX futures prices. PSCW Staff’s sales forecast adjustment is based on the assumption that the strong sales growth trend from 2010 through 2012, primarily in the large commercial/industrial sector, will continue through 2013 and 2014, while NSP-Wisconsin’s forecast shows moderating growth.

On Oct. 18, 2013, NSP-Wisconsin filed rebuttal testimony, revising the requested electric rate increase to $34.0 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments.

Next steps in the procedural schedule are as follows:

• Surrebuttal testimony - Oct. 28, 2013;

• Hearing - Oct. 30, 2013;

• Initial brief - Nov. 13, 2013; and

• Reply brief - Nov. 20, 2013.

A PSCW decision is anticipated in December 2013, with final rates going into effect in January 2014.

6. Commitments and Contingencies

Except as noted below and in Note 5, the circumstances set forth in Notes 10 and 11 to the consolidated financial statements in NSP-Wisconsin’s 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 and are incorporated herein by reference.  The following include commitments, contingencies and unresolved contingencies that are material to NSP-Wisconsin’s financial position.

Guarantees — NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program.  NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement.  The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee.  The guarantee contains no recourse provisions and requires no collateral.

The following table presents the guarantee issued and outstanding for NSP-Wisconsin:

(Millions of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.3		0.4

Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis.  The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site.  In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site.  The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site.  As a result of those settlement negotiations, the EPA agreed to segment the Ashland site into separate areas.  The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff.  The second area includes the Sediments.

In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources (WDNR), the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin.  This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area.  Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site.  The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million.  The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments.  As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees.  Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing.  In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation will be received and reported in November 2013. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a wet dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a wet dredge pilot study in 2011. The EPA’s ROD for the Ashland site includes estimates that the cost of the preferred remediation related to the Sediments is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site.  Trial for this matter has been rescheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At Sept. 30, 2013 and Dec. 31, 2012, NSP-Wisconsin had recorded a liability of $101.2 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $19.5 million and $20.1 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change.  NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site.  Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.  The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities.  External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process.  Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period.  The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

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In the last rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin.  The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a three percent carrying cost to the unamortized regulatory asset.  Implementation of this exception will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard (NSPS) Proposal and Emission Guideline for Existing Sources — In September 2013, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish carbon dioxide (CO₂) emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal 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 Wisconsin.  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.  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 hear arguments in December 2013. The Court will likely issue a decision by June 2014.

As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, NSP-Wisconsin expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions.  Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  NSP-Wisconsin purchased allowances in 2012 and plans to continue to purchase allowances in 2013 to comply with the CAIR.  At Sept. 30, 2013, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin did not have a material impact on the results of operations, financial position or cash flows.

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. 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. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

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Legal Contingencies

NSP-Wisconsin 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-Wisconsin’s financial statements.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

Environmental Litigation

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. Plaintiffs elected not to seek further review of this decision, which brings this litigation to a close.  No accrual was recorded for this matter.

7. Borrowings and Other Financing Instruments

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	150		$	150
Amount outstanding at period end	11			39
Average amount outstanding	4			61
Maximum amount outstanding	19			116
Weighted average interest rate, computed on a daily basis	0.22		%	0.39		%
Weighted average interest rate at period end	0.18			0.40

Letters of Credit— NSP-Wisconsin may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Sept. 30, 2013 and Dec. 31, 2012, there were no letters of credit outstanding.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin 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 aggregate 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 Sept. 30, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150.0	$	11.0	$	139.0

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper.

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

Other Short-Term Borrowings— The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.:

(Amounts in Millions, Except Interest Rates)	Sept. 30, 2013			Dec. 31, 2012
Notes payable to affiliates	$	0.5		$	0.6
Weighted average interest rate at period end	0.25		%	0.33		%

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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.

Derivative Instruments Fair Value Measurements

NSP-Wisconsin enters into derivative instruments, including forward contracts, futures, swaps and options, to manage risk in connection with changes in interest rates and utility commodity prices.

Interest Rate Derivatives — NSP-Wisconsin 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 Sept. 30, 2013, accumulated other comprehensive loss related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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There were immaterial pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings during the three months ended Sept. 30, 2013 and 2012, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the nine months ended Sept. 30, 2013 and 2012.

Commodity Derivatives — NSP-Wisconsin may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, including the sale of natural gas or the purchase of natural gas for resale.

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

(Amounts in Thousands)(a)(b)	Sept. 30, 2013	Dec. 31, 2012
Million British thermal units (MMBtu) of natural gas	853	53

^(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-Wisconsin continuously monitors the creditworthiness of the counterparties to its interest rate 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-Wisconsin’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 commodity derivatives presented in the consolidated balance sheets.

NSP-Wisconsin 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.

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

	Three Months Ended Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(400	)	$	(476	)
After-tax net realized losses on derivative transactions reclassified into earnings	20			20
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(380	)	$	(456	)

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(437	)	$	(514	)
After-tax net realized losses on derivative transactions reclassified into earnings	57			58
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(380	)	$	(456	)

During the three months ended Sept. 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities.  For the three months ended Sept. 30, 2012, changes in the fair value of natural gas commodity derivatives resulted in immaterial net gains recognized as regulatory assets and liabilities.  During the nine months ended Sept. 30, 2013 and 2012, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.4 million recognized as regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Natural gas commodity derivatives settlement losses of $2.9 million were recognized during the nine months ended Sept. 30, 2012, and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate.  Such losses for the three and nine months ended Sept. 30, 2013, and the three months ended Sept. 30, 2012, were immaterial.

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NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2013 and 2012.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2013 and Dec. 31, 2012:

	Sept. 30, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	346	$	—	$	346	$	—	$	346

	Dec. 31, 2012
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(c)
Current derivative liabilities
Natural gas commodity	$	—	$	11	$	—	$	11	$	—	$	11

^(a)  NSP-Wisconsin 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 Sept. 30, 2013 and 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.

^(b)  Included in other current assets balance of $2.9 million at Sept. 30, 2013 in the consolidated balance sheets.

^(c)  Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

Fair Value of Long-Term Debt

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

	Sept. 30, 2013				Dec. 31, 2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	468,614	$	531,932	$	468,563	$	576,353

The fair value of NSP-Wisconsin’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 Sept. 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 Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012			2013			2012
Interest income	$	23		$	18		$	419		$	650
Other nonoperating income	38			18			108			57
Insurance policy expense	(119		)	(121		)	(310		)	(332		)
Other nonoperating expense	(3		)	—			(8		)	—
Other (expense) income, net	$	(61	)	$	(85	)	$	209		$	375

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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-Wisconsin’s chief operating decision maker.  NSP-Wisconsin 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-Wisconsin has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

• NSP-Wisconsin’s regulated electric utility segment generates electricity which is transmitted and distributed in Wisconsin and Michigan.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities primarily in Wisconsin.

• NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas in portions of Wisconsin and Michigan.

• 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 investments in rental housing projects that qualify for low-income housing tax credits.

Asset and capital expenditure information is not provided for NSP-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin 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 operating and maintenance (O&M) expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2013
Operating revenues from external customers	$	216,545	$	14,266		$	249	$	—		$	231,060
Intersegment revenues	89		962			—		(1,051		)	—
Total revenues	$	216,634	$	15,228		$	249	$	(1,051	)	$	231,060
Net income (loss)	$	22,859	$	(1,726	)	$	880	$	—		$	22,013

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2012
Operating revenues from external customers	$	214,426	$	11,742		$	307	$	—		$	226,475
Intersegment revenues	82		321			—		(403		)	—
Total revenues	$	214,508	$	12,063		$	307	$	(403	)	$	226,475
Net income (loss)	$	21,743	$	(1,461	)	$	1,918	$	—		$	22,200

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2013
Operating revenues from external customers	$	592,730	$	89,178	$	742	$	—		$	682,650
Intersegment revenues	250		1,549		—		(1,799		)	—
Total revenues	$	592,980	$	90,727	$	742	$	(1,799	)	$	682,650
Net income	$	46,530	$	4,100	$	1,612	$	—		$	52,242

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2012
Operating revenues from external customers	$	575,532	$	68,064	$	851	$	—		$	644,447
Intersegment revenues	278		585		—		(863		)	—
Total revenues	$	575,810	$	68,649	$	851	$	(863	)	$	644,447
Net income	$	39,118	$	992	$	2,710	$	—		$	42,820

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,421		$	1,142		$	6		$	5
Interest cost	1,731			1,918			190			268
Expected return on plan assets	(2,499		)	(2,622		)	(11		)	(13		)
Amortization of transition obligation	—			—			—			42
Amortization of prior service cost (credit)	104			442			(88		)	(4		)
Amortization of net loss	1,981			1,460			241			123
Net benefit cost recognized for financial reporting	$	2,738		$	2,340		$	338		$	421

	Nine Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,262		$	3,426		$	18		$	15
Interest cost	5,193			5,753			570			806
Expected return on plan assets	(7,496		)	(7,867		)	(32		)	(38		)
Amortization of transition obligation	—			—			—			128
Amortization of prior service cost (credit)	312			1,328			(264		)	(11		)
Amortization of net loss	5,943			4,382			723			365
Net benefit cost recognized for financial reporting	$	8,214		$	7,022		$	1,015		$	1,265

In 2013, contributions of $192.2 million were made across four of Xcel Energy’s pension plans, of which $11.3 million was attributable to NSP-Wisconsin.  Xcel Energy does not expect additional pension contributions during 2013.

12. Other Comprehensive Income

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

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at July 1	$	(400	)
Losses reclassified from net accumulated other comprehensive loss	20
Net current period other comprehensive income	20
Accumulated other comprehensive loss at Sept. 30	$	(380	)

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(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	57
Net current period other comprehensive income	57
Accumulated other comprehensive loss at Sept. 30	$	(380	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2013				Nine Months Ended Sept. 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	32		(a)	$	95		(a)
Total, pre-tax	32				95
Tax benefit	(12		)		(38		)
Total amounts reclassified, net of tax	$	20			$	57

^(a)  Included in interest charges.

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

Discussion of financial condition and liquidity for NSP-Wisconsin 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-Wisconsin’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-Wisconsin’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

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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-Wisconsin 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-Wisconsin 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-Wisconsin 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 Nuclear Regulatory Commission (NRC); financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Wisconsin’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 Sept. 30, 2013.

Results of Operations

NSP-Wisconsin’s net income was $52.2 million for the nine months ended Sept. 30, 2013 compared with $42.8 million for the same period in 2012.  Higher earnings from electric and natural gas rates were partially offset by higher depreciation, O&M expenses and cooler summer weather.

Electric Revenues and Margin

Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power.  The electric fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings.  The following table details the electric revenues and margin:

	Nine Months Ended Sept. 30
(Millions of Dollars)	2013			2012
Electric revenues	$	593		$	576
Electric fuel and purchased power	(317		)	(317		)
Electric margin	$	276		$	259

The following tables summarize the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30:

Electric Revenues

(Millions of Dollars)	2013 vs. 2012
Retail rate increase (Wisconsin)	$	26
Interchange billings with Minnesota	11
Estimated impact of weather	3
Fuel and purchased power cost recovery	3
Firm wholesale	(23		)
Conservation and demand side management program revenues (offset by expenses)	(1		)
Other, net	(2		)
Total increase in electric revenues	$	17

20

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increase (Wisconsin)	$	26
Interchange billings with Minnesota	8
Estimated impact of weather	3
Firm wholesale	(15		)
Timing of fuel recovery	(5		)
Total increase in electric margin	$	17

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 the natural gas revenues and margin:

	Nine Months Ended Sept. 30
(Millions of Dollars)	2013			2012
Natural gas revenues	$	89		$	68
Cost of natural gas sold and transported	(53		)	(40		)
Natural gas margin	$	36		$	28

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the nine months ended Sept. 30:

Natural Gas Revenues

(Millions of Dollars)	2013 vs. 2012
Purchased natural gas adjustment clause recovery	$	13
Estimated impact of weather	4
Retail rate increase (Wisconsin)	2
Retail sales growth	1
Other, net	1
Total increase in natural gas revenues	$	21

Natural Gas Margin

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	4
Retail rate increase (Wisconsin)	2
Retail sales growth	1
Other, net	1
Total increase in natural gas margin	$	8

21

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $4.5 million, or 3.6 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2013 vs. 2012
Employee benefits	$	2
Other electric and gas distribution expenses	2
Bad debt expense	1
Interchange costs	(2		)
Other, net	1
Total increase in O&M expenses	$	4

Depreciation and Amortization — Depreciation and amortization increased $5.8 million, or 11.3 percent, for the nine months ended Sept. 30, 2013 compared with the same periods in 2012. The increases are primarily attributable to normal system expansion.

Allowance for funds used during construction, equity and debt (AFUDC)— AFUDC increased $1.4 million for the nine months ended Sept. 30, 2013, compared with the same periods in 2012. The increase is primarily due to the expansion of transmission facilities.

Income Taxes — Income tax expense increased $5.6 million for the first nine months of 2013 compared with the same period in 2012.  The increase in income tax expense was primarily due to higher pretax earnings in 2013. The ETR was 37.8 percent for the nine months ended Sept. 30, 2013 compared with 37.9 percent for the same period in 2012. 

Public Utility Regulation

2013 Electric Fuel Cost Recovery— NSP-Wisconsin’s electric fuel costs for the nine months ended Sept. 30, 2013 were higher than authorized in rates, and outside the two percent annual tolerance band established in the Wisconsin fuel cost recovery rules primarily due to extended outages at two baseload generation plants and higher than forecast prices in the MISO market. Under the fuel cost recovery rules, NSP-Wisconsin is at risk for the amount of under-recovery up to two percent of authorized annual fuel costs, up to $3.6 million. However, NSP-Wisconsin may defer the amount of under-recovery in excess of the two percent annual tolerance band for future rate recovery. Accordingly, NSP-Wisconsin recorded a deferral of approximately $3.5 million through September 2013. An application to recover the deferred amount cannot be made until 2013 annual actual fuel costs are known, and the amount of the deferral could increase or decrease based on actual fuel costs incurred for the remainder of the year. Rate recovery of the deferred amount is contingent on review and approval by the PSCW after opportunity for a hearing, and is subject to an earnings test based on NSP-Wisconsin’s most recently authorized ROE of 10.4 percent.

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-Wisconsin, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Wisconsin’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-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2012.

22

Midcontinent Independent Transmission System Operator, Inc.(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 (Seventh Circuit).  In June 2013, 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). U.S. Supreme Court review of the Seventh Circuit decision has been requested; the U.S. Supreme Court’s response is pending. 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 in July 2011 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 regional 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-Wisconsin 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 in May 2013. The FERC submitted its responsive brief on Sept. 25, 2013. Reply briefs from all parties are due on Nov. 15, 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-Wisconsin currently has under the MISO tariff to build certain transmission projects within its footprint.  Rather, the FERC required that the opportunity to build such projects would extend to competitive transmission developers.  Compliance with Order 1000 for NSP-Wisconsin 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 regional compliance filings for MISO, directing further changes to fully address the requirements of Order 1000.

Filings to address MISO interregional planning and cost allocation requirements with other regions were made in July 2013.

The filings are pending action by the FERC. 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 which will likely delay that filing until late third quarter of 2014.

NSP-System

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.  Wisconsin has not developed such legislation.  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 Xcel Energy has requested rehearing of this issue. The rehearing request is pending the FERC’s action. In a filing concurrent to MISO’s Order 1000 compliance filing, the FERC accepted changes to MISO’s transmission cost allocation procedures that will protect the ROFR for projects needed for system reliability.

23

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Wisconsin maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Sept. 30, 2013, based on an evaluation carried out under the supervision and with the participation of NSP-Wisconsin’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-Wisconsin’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Wisconsin’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-Wisconsin’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-Wisconsin.  NSP-Wisconsin 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-Wisconsin’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.

24

Item 6 — EXHIBITS

* Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
3.02	By-Laws of Northern States Power Co. (a Wisconsin corporation) as Amended and Restated on Sept. 26, 2013.
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-Wisconsin’s Quarterly Report on Form 10-Q for the quarter ended Sept. 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.

25

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 Wisconsin corporation)
Oct. 28, 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

26

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Mark E. Stoering, certify that:

1. I have reviewed this report on Form 10-Q of Northern States Power Company (a Wisconsin corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Oct. 28, 2013

/s/ MARK E. STOERING

Mark E. Stoering

President, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-Q of Northern States Power Company (a Wisconsin corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Oct. 28, 2013

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Northern States Power Company, a Wisconsin Corporation (NSP-Wisconsin) on Form 10-Q for the quarter ended Sept. 30, 2013, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of NSP-Wisconsin certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of NSP-Wisconsin as of the dates and for the periods expressed in the Form 10-Q.

Date: Oct. 28, 2013

/s/ MARK E. STOERING

Mark E. Stoering

President, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NSP-Wisconsin and will be retained by NSP-Wisconsin and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

NSP-Wisconsin Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of NSP-Wisconsin, Xcel Energy Inc. or any of its other subsidiaries. These statements are based on management’s beliefs as well as assumptions and information currently available to management.  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.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause NSP-Wisconsin’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Wisconsin has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-Wisconsin, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

• Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry or additional competition in the markets served by NSP-Wisconsin, Xcel Energy Inc. and its other subsidiaries;

• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of  compliance;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Risks associated with implementations of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in NSP-Wisconsin’s SEC filings, including “Risk Factors” in Item 1A of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2012, or in other publicly disseminated written documents.

NSP-Wisconsin undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

1

XML

Fair Value of Financial Assets and Liabilities

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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.

Derivative Instruments Fair Value Measurements

NSP-Wisconsin enters into derivative instruments, including forward contracts, futures, swaps and options, to manage risk in connection with changes in interest rates and utility commodity prices.

Interest Rate Derivatives — NSP-Wisconsin 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 Sept. 30, 2013, accumulated other comprehensive loss related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

There were immaterial pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings during the three months ended Sept. 30, 2013 and 2012, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the nine months ended Sept. 30, 2013 and 2012.

Commodity Derivatives — NSP-Wisconsin may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, including the sale of natural gas or the purchase of natural gas for resale.

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

(Amounts in Thousands)(a)(b)	Sept. 30, 2013	Dec. 31, 2012
Million British thermal units (MMBtu) of natural gas	853	53

^(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-Wisconsin continuously monitors the creditworthiness of the counterparties to its interest rate 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-Wisconsin’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 commodity derivatives presented in the consolidated balance sheets.

NSP-Wisconsin 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.

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

	Three Months Ended Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(400	)	$	(476	)
After-tax net realized losses on derivative transactions reclassified into earnings	20			20
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(380	)	$	(456	)

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(437	)	$	(514	)
After-tax net realized losses on derivative transactions reclassified into earnings	57			58
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(380	)	$	(456	)

During the three months ended Sept. 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities.  For the three months ended Sept. 30, 2012, changes in the fair value of natural gas commodity derivatives resulted in immaterial net gains recognized as regulatory assets and liabilities.  During the nine months ended Sept. 30, 2013 and 2012, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.4 million recognized as regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Natural gas commodity derivatives settlement losses of $2.9 million were recognized during the nine months ended Sept. 30, 2012, and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate.  Such losses for the three and nine months ended Sept. 30, 2013, and the three months ended Sept. 30, 2012, were immaterial.

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2013 and 2012.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2013 and Dec. 31, 2012:

	Sept. 30, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	346	$	—	$	346	$	—	$	346

	Dec. 31, 2012
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(c)
Current derivative liabilities
Natural gas commodity	$	—	$	11	$	—	$	11	$	—	$	11

^(a)  NSP-Wisconsin 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 Sept. 30, 2013 and 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.

^(b)  Included in other current assets balance of $2.9 million at Sept. 30, 2013 in the consolidated balance sheets.

^(c)  Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

Fair Value of Long-Term Debt

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

	Sept. 30, 2013				Dec. 31, 2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	468,614	$	531,932	$	468,563	$	576,353

The fair value of NSP-Wisconsin’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 Sept. 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.

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Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012	Sep. 30, 2013		Sep. 30, 2012
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period				$ (437)
Accumulated other comprehensive loss at end of period	(380)			(380)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	7,191		5,944	20,860		18,003
Total, pre-tax	(35,017)		(35,316)	(84,020)		(68,968)
Tax benefit	13,004		13,116	31,778		26,148
Gains and Losses on Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(400)			(437)
Losses reclassified from net accumulated other comprehensive loss	20			57
Net current period other comprehensive income (loss)	20			57
Accumulated other comprehensive loss at end of period	(380)			(380)
Gains and Losses on Cash Flow Hedges [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	32			95
Tax benefit	(12)			(38)
Total, net of tax	20			57
Gains and Losses on Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	$ 32	[1]		$ 95	[1]

[1] Included in interest charges.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Comprehensive income:
Net income	$ 22,013	$ 22,200	$ 52,242	$ 42,820
Derivative instruments:
Reclassification of losses to net income, net of tax of $12, $12, $38 and $37, respectively.	20	20	57	58
Other comprehensive income	20	20	57	58
Comprehensive income	$ 22,033	$ 22,220	$ 52,299	$ 42,878

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Wisconsin 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 and NSP-Wisconsin. 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.

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Rate Matters Rate Matters (Tables)

9 Months Ended

Sep. 30, 2013

Public Utilities, General Disclosure [Abstract]

PSCW Staff signficant adjustments to the NSP-Wisconsin 2014 Electric and Gas Rate Case [Table Text Block]

The most significant adjustments proposed by the PSCW Staff are shown in the table below:

(Millions of Dollars)	Electric Staff Testimony October 2013			Natural Gas Staff Testimony October 2013
Rate request	$	40.0		$	4.7
Electric fuel and purchased power	(5.1		)	—
Sales forecast	(4.8		)	—
Incentive compensation and merit pay	(3.0		)	(0.6		)
ROE	(1.6		)	(0.2		)
Conservation funding transfer	0.7			(0.7		)
Depreciation expense	(0.7		)	(1.3		)
Ashland site amortization expense	—			(2.3		)
Other, net	(1.7		)	(0.7		)
Recommended rate increase (decrease)	$	23.8		$	(1.1	)

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Other (Expense) Income, Net

9 Months Ended

Sep. 30, 2013

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

Other (Expense) Income, Net

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012			2013			2012
Interest income	$	23		$	18		$	419		$	650
Other nonoperating income	38			18			108			57
Insurance policy expense	(119		)	(121		)	(310		)	(332		)
Other nonoperating expense	(3		)	—			(8		)	—
Other (expense) income, net	$	(61	)	$	(85	)	$	209		$	375

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other current liabilities	$ 9,627		$ 10,955
Prepayments and other	2,889		4,394
Fair Value Measured on a Recurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas commodity	346	[1]
Current derivative liabilities [Abstract]
Natural gas commodity			11	[2]
Fair Value Measured on a Recurring Basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas commodity	0
Current derivative liabilities [Abstract]
Natural gas commodity			0
Fair Value Measured on a Recurring Basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas commodity	346
Current derivative liabilities [Abstract]
Natural gas commodity			11
Fair Value Measured on a Recurring Basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas commodity	0
Current derivative liabilities [Abstract]
Natural gas commodity			0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other current liabilities			11,000
Prepayments and other	2,900
Natural gas commodity	346
Current derivative liabilities [Abstract]
Natural gas commodity			11
Fair Value Measured on a Recurring Basis [Member] | Counterparty Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas commodity	0
Current derivative liabilities [Abstract]
Natural gas commodity			$ 0	[3]

[1] Included in other current assets balance of $2.9 million at Sept. 30, 2013 in the consolidated balance sheets.

[2] Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

[3] NSP-Wisconsin 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 Sept. 30, 2013 and 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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Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (USD $)	9 Months Ended
	Sep. 30, 2013 Site	Dec. 31, 2012
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites, current	$ 23,817,000	$ 23,427,000
Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Number of properties included in superfund site which NSP-Wisconsin does not own	2
Liability for estimated cost of remediating sites	101,200,000	103,700,000
Liability for estimated cost of remediating sites, current	19,500,000	20,100,000
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years)	4 years
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years)	6 years
Ashland MGP Site - Phase I Project Area
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites	40,000,000
Number of acres of land conveyed to the State of Wisconsin and tribal trustees (in acres)	1,390
Approved amortization period for recovery of remediation costs in natural gas rates (in years)	10 years
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths)	3.00%
Ashland MGP Site - Sediments
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Estimated cost of remediating site, low end of range	63,000,000
Estimated cost of remediating site, high end of range	$ 77,000,000
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths)	50.00%
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths)	30.00%

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Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

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

(Amounts in Thousands)(a)(b)	Sept. 30, 2013	Dec. 31, 2012
Million British thermal units (MMBtu) of natural gas	853	53

^(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.

Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss

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

	Three Months Ended Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(400	)	$	(476	)
After-tax net realized losses on derivative transactions reclassified into earnings	20			20
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(380	)	$	(456	)

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(437	)	$	(514	)
After-tax net realized losses on derivative transactions reclassified into earnings	57			58
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(380	)	$	(456	)

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2013 and Dec. 31, 2012:

	Sept. 30, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	346	$	—	$	346	$	—	$	346

	Dec. 31, 2012
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(c)
Current derivative liabilities
Natural gas commodity	$	—	$	11	$	—	$	11	$	—	$	11

^(a)  NSP-Wisconsin 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 Sept. 30, 2013 and 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.

^(b)  Included in other current assets balance of $2.9 million at Sept. 30, 2013 in the consolidated balance sheets.

^(c)  Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

Carrying Amount and Fair Value of Long-term Debt

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

	Sept. 30, 2013				Dec. 31, 2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	468,614	$	531,932	$	468,563	$	576,353

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Borrowings and Other Financing Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Debt Instruments [Abstract]

Committed Credit Facility Available

At Sept. 30, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150.0	$	11.0	$	139.0

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper.

Commercial Paper

Debt Instruments [Abstract]

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	150		$	150
Amount outstanding at period end	11			39
Average amount outstanding	4			61
Maximum amount outstanding	19			116
Weighted average interest rate, computed on a daily basis	0.22		%	0.39		%
Weighted average interest rate at period end	0.18			0.40

Intercompany Borrowing Arrangement

Debt Instruments [Abstract]

Short-Term Borrowings

Other Short-Term Borrowings— The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.:

(Amounts in Millions, Except Interest Rates)	Sept. 30, 2013			Dec. 31, 2012
Notes payable to affiliates	$	0.5		$	0.6
Weighted average interest rate at period end	0.25		%	0.33		%

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (Other Derivative Instruments [Member], Natural Gas Commodity Contract [Member])	Sep. 30, 2013 MMBTU		Dec. 31, 2012 MMBTU
Other Derivative Instruments [Member] | Natural Gas Commodity Contract [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	853,000	[1],[2]	53,000	[1],[2]

[1] Amounts are not reflective of net positions in the underlying commodities.

[2] Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

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Selected Balance Sheet Data, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 2,315,291	$ 2,193,812
Less accumulated depreciation	(936,644)	(895,576)
Property, plant and equipment, net	1,378,647	1,298,236
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,869,563	1,795,239
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	231,778	224,625
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	112,514	111,319
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 101,436	$ 62,629

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Commitments and Contingencies, Legal Contingencies (Details) (USD $)	Sep. 30, 2013	May 31, 2011 Counterparty
Legal Contingencies [Abstract]
Accrual for legal contingency	$ 0
Comer vs. Xcel Energy Inc. et al. [Member]
Legal Contingencies [Abstract]
Accrual for legal contingency	$ 0
Minimum number of utility, oil, chemical and coal companies against which a lawsuit was filed in U.S. District Court in Mississippi		85

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 468,614	$ 468,563
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 531,932	$ 576,353

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2013

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

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

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at July 1	$	(400	)
Losses reclassified from net accumulated other comprehensive loss	20
Net current period other comprehensive income	20
Accumulated other comprehensive loss at Sept. 30	$	(380	)

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	57
Net current period other comprehensive income	57
Accumulated other comprehensive loss at Sept. 30	$	(380	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2013				Nine Months Ended Sept. 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	32		(a)	$	95		(a)
Total, pre-tax	32				95
Tax benefit	(12		)		(38		)
Total amounts reclassified, net of tax	$	20			$	57

^(a)  Included in interest charges.

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Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
Credit Facility [Abstract]
Credit facility	$ 150,000,000	[1]
Drawn	11,000,000	[2]
Available	139,000,000
Credit facility bank borrowings outstanding	$ 0		$ 0

[1] Credit facility expires in July 2017.

[2] Includes outstanding commercial paper.

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Guarantee Issued and Outstanding

The following table presents the guarantee issued and outstanding for NSP-Wisconsin:

(Millions of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.3		0.4

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Operating activities
Net income	$ 52,242	$ 42,820
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	58,126	52,291
Deferred income taxes	19,491	19,604
Amortization of investment tax credits	(500)	(469)
Allowance for equity funds used during construction	(2,755)	(1,379)
Net derivative (gains) losses	(658)	95
Changes in operating assets and liabilities:
Accounts receivable	2,566	(11,303)
Accrued unbilled revenues	11,076	9,496
Inventories	(3,382)	3,924
Other current assets	9,486	6,142
Accounts payable	(3,755)	(7,307)
Net regulatory assets and liabilities	(6,260)	6,150
Other current liabilities	9,635	9,701
Pension and other employee benefit obligations	(9,273)	(11,002)
Change in other noncurrent assets	260	(119)
Change in other noncurrent liabilities	1,555	(500)
Net cash provided by operating activities	137,854	118,144
Investing activities
Utility capital/construction expenditures	(134,641)	(106,553)
Allowance for equity funds used during construction	2,754	1,379
Other, net	(249)	1,096
Net cash used in investing activities	(132,136)	(104,078)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(28,000)	33,000
(Repayments of) proceeds from notes payable to affiliate	(80)	50
Repayments of long-term debt	(109)	(48)
Capital contributions from parent	42,481	2,162
Dividends paid to parent	(22,943)	(49,306)
Net cash used in financing activities	(8,651)	(14,142)
Net change in cash and cash equivalents	(2,933)	(76)
Cash and cash equivalents at beginning of period	4,459	1,571
Cash and cash equivalents at end of period	1,526	1,495
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(18,366)	(16,925)
Cash received (paid) for income taxes, net	(2,127)	1,971
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 10,347	$ 8,866

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Capitalization
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, par value (in dollars per share)	$ 100	$ 100
Common stock, shares outstanding (in shares)	933,000	933,000

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Accounting Pronouncements

9 Months Ended

Sep. 30, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

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-Wisconsin 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-Wisconsin 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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Management's Opinion

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Management's Opinion

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-Wisconsin and its subsidiaries as of Sept. 30, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2013 and 2012; and its cash flows for the nine months ended Sept. 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 Sept. 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-Wisconsin 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-Wisconsin 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-Wisconsin’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

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Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Short-term Debt [Line Items]
Amount outstanding at period end	$ 11,000,000	$ 39,000,000
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	150,000,000	150,000,000
Amount outstanding at period end	11,000,000	39,000,000
Average amount outstanding	4,000,000	61,000,000
Maximum amount outstanding	$ 19,000,000	$ 116,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.22%	0.39%
Weighted average interest rate at period end (in hundredths)	0.18%	0.40%

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Other (Expense) Income, Net (Tables)

9 Months Ended

Sep. 30, 2013

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012			2013			2012
Interest income	$	23		$	18		$	419		$	650
Other nonoperating income	38			18			108			57
Insurance policy expense	(119		)	(121		)	(310		)	(332		)
Other nonoperating expense	(3		)	—			(8		)	—
Other (expense) income, net	$	(61	)	$	(85	)	$	209		$	375

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Selected Balance Sheet Data, Accounts Receivable (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
Accounts Receivable, Net
Accounts receivable	$ 52,596,000		$ 55,039,000
Less allowance for bad debts	(4,477,000)		(4,333,000)
Accounts receivable, net	48,119,000	[1]	50,706,000	[1]
Accounts receivable from affiliates, net	$ 14		$ 586

[1] Accounts receivable, net includes $14 and $586 due from affiliates as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

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Commitments and Contingencies, Guarantees and Indemnifications (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Guarantor Obligations [Line Items]
Assets Held As Collateral	$ 0
Payment or Performance Guarantee | Customer Loans for Farm Rewiring Program
Guarantees [Abstract]
Guarantees issued and outstanding	1,000,000	1,000,000
Current exposure under these guarantees	$ 300,000	$ 400,000

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Other (Expense) Income, Net (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Income and Expenses [Abstract]
Interest income	$ 23	$ 18	$ 419	$ 650
Other nonoperating income	38	18	108	57
Insurance policy expense	(119)	(121)	(310)	(332)
Other nonoperating expense	(3)	0	(8)	0
Other (expense) income, net	$ (61)	$ (85)	$ 209	$ 375

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (Interest Rate Swap [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	$ (0.1)
Amount of accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings	$ (0.1)	$ (0.1)

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Interest charges and financing costs
Other financing costs	$ 389	$ 375	$ 1,150	$ 1,185

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Rate Matters (Notes)

9 Months Ended

Sep. 30, 2013

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 and in Note 5 to NSP-Wisconsin’s Quarterly Report on Form 10-Q for the quarter period ended March 31, 2013 and June 30, 2013, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)

Wisconsin 2014 Electric and Gas Rate Case—On May 31, 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent.

The rate filing is based on a 2014 forecast test year, a return on equity (ROE) of 10.4 percent, an equity ratio of 52.5 percent, and a forecasted average net investment rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility.

On Oct. 4, 2013, the PSCW Staff filed their direct testimony and recommended an electric rate increase of $23.8 million, or 3.8 percent, and a natural gas rate decrease of $1.1 million, or 0.9 percent. PSCW Staff’s recommendations were based on a 10.2 percent ROE and a 52.5 percent equity ratio. 

The most significant adjustments proposed by the PSCW Staff are shown in the table below:

(Millions of Dollars)	Electric Staff Testimony October 2013			Natural Gas Staff Testimony October 2013
Rate request	$	40.0		$	4.7
Electric fuel and purchased power	(5.1		)	—
Sales forecast	(4.8		)	—
Incentive compensation and merit pay	(3.0		)	(0.6		)
ROE	(1.6		)	(0.2		)
Conservation funding transfer	0.7			(0.7		)
Depreciation expense	(0.7		)	(1.3		)
Ashland site amortization expense	—			(2.3		)
Other, net	(1.7		)	(0.7		)
Recommended rate increase (decrease)	$	23.8		$	(1.1	)

The majority of the adjustment to electric fuel and purchased power is the result of the PSCW Staff’s proposal to discontinue using the New York Mercantile Exchange (NYMEX) futures prices as a basis for setting the fuel price forecast and instead using a discounted percentage of the NYMEX futures prices. PSCW Staff’s sales forecast adjustment is based on the assumption that the strong sales growth trend from 2010 through 2012, primarily in the large commercial/industrial sector, will continue through 2013 and 2014, while NSP-Wisconsin’s forecast shows moderating growth.

On Oct. 18, 2013, NSP-Wisconsin filed rebuttal testimony, revising the requested electric rate increase to $34.0 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments.

Next steps in the procedural schedule are as follows:

• Surrebuttal testimony - Oct. 28, 2013;

• Hearing - Oct. 30, 2013;

• Initial brief - Nov. 13, 2013; and

• Reply brief - Nov. 20, 2013.

A PSCW decision is anticipated in December 2013, with final rates going into effect in January 2014.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative instruments:
Reclassification of losses to net income, net of tax	$ 12	$ 12	$ 38	$ 37

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating revenues
Electric	$ 216,545	$ 214,426	$ 592,730	$ 575,532
Natural gas	14,266	11,742	89,178	68,064
Other	249	307	742	851
Total operating revenues	231,060	226,475	682,650	644,447
Operating expenses
Electric fuel and purchased power, non-affiliates	4,968	7,516	11,000	15,431
Purchased power, affiliates	106,554	103,572	305,539	301,551
Cost of natural gas sold and transported	7,483	5,656	52,770	39,658
Operating and maintenance expenses	42,521	41,726	127,189	122,718
Conservation program expenses	3,133	3,714	9,243	10,836
Depreciation and amortization	19,359	17,338	57,265	51,440
Taxes (other than income taxes)	6,273	6,218	19,008	18,816
Total operating expenses	190,291	185,740	582,014	560,450
Operating income	40,769	40,735	100,636	83,997
Other (expense) income, net	(61)	(85)	209	375
Allowance for funds used during construction — equity	1,029	(385)	2,755	1,379
Interest charges and financing costs
Interest charges — includes other financing costs of $389, $375, $1,150 and $1,185, respectively	7,191	5,944	20,860	18,003
Allowance for funds used during construction — debt	(471)	(995)	(1,280)	(1,220)
Total interest charges and financing costs	6,720	4,949	19,580	16,783
Income before income taxes	35,017	35,316	84,020	68,968
Income taxes	13,004	13,116	31,778	26,148
Net income	$ 22,013	$ 22,200	$ 52,242	$ 42,820

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Segment Reporting Information [Line Items]
Operating revenues	$ 231,060	$ 226,475	$ 682,650	$ 644,447
Net income (loss)	22,013	22,200	52,242	42,820
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	216,634	214,508	592,980	575,810
Net income (loss)	22,859	21,743	46,530	39,118
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	15,228	12,063	90,727	68,649
Net income (loss)	(1,726)	(1,461)	4,100	992
All Other
Segment Reporting Information [Line Items]
Operating revenues	249	307	742	851
Net income (loss)	880	1,918	1,612	2,710
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	231,060	226,475	682,650	644,447
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	216,545	214,426	592,730	575,532
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	14,266	11,742	89,178	68,064
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	249	307	742	851
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(1,051)	(403)	(1,799)	(863)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	89	82	250	278
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	962	321	1,549	585
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0	$ 0	$ 0	$ 0

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Results from Continuing Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2013
Operating revenues from external customers	$	216,545	$	14,266		$	249	$	—		$	231,060
Intersegment revenues	89		962			—		(1,051		)	—
Total revenues	$	216,634	$	15,228		$	249	$	(1,051	)	$	231,060
Net income (loss)	$	22,859	$	(1,726	)	$	880	$	—		$	22,013

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2012
Operating revenues from external customers	$	214,426	$	11,742		$	307	$	—		$	226,475
Intersegment revenues	82		321			—		(403		)	—
Total revenues	$	214,508	$	12,063		$	307	$	(403	)	$	226,475
Net income (loss)	$	21,743	$	(1,461	)	$	1,918	$	—		$	22,200

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2013
Operating revenues from external customers	$	592,730	$	89,178	$	742	$	—		$	682,650
Intersegment revenues	250		1,549		—		(1,799		)	—
Total revenues	$	592,980	$	90,727	$	742	$	(1,799	)	$	682,650
Net income	$	46,530	$	4,100	$	1,612	$	—		$	52,242

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2012
Operating revenues from external customers	$	575,532	$	68,064	$	851	$	—		$	644,447
Intersegment revenues	278		585		—		(863		)	—
Total revenues	$	575,810	$	68,649	$	851	$	(863	)	$	644,447
Net income	$	39,118	$	992	$	2,710	$	—		$	42,820

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.5		1.2
Total unrecognized tax benefit	$	1.7	$	1.3

Tax Benefits Associated with NOL and Tax Credit Carryforwards

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)	Sept. 30, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(0.9	)	$	(0.9	)

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Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangement and Other Short-Term Borrowings (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Short-term Debt [Line Items]
Notes payable to affiliates	$ 470	$ 550
Intercompany Borrowing Arrangement
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 600
Weighted average interest rate at period end (in hundredths)	0.25%	0.33%

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Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (Federal Clean Water Act)	Jun. 30, 2013 Regulation
Federal Clean Water Act
Environmental Requirements [Abstract]
Number of potential regulatory options under the proposed Effluent Limitations Guidelines rule	4

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Income Taxes (Details) (USD $)			3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012 Internal Revenue Service (IRS)	Sep. 30, 2013 Internal Revenue Service (IRS)	Mar. 31, 2013 State Jurisdiction (Wisconsin)	Sep. 30, 2013 State Jurisdiction (Wisconsin)
Tax Audits [Abstract]
Year(s) no longer subject to audit as statute of limitations has expired				2008
Earliest year subject to examination				2009		2009
Year(s) under examination			2010 and 2011		2009 through 2011
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions	$ 200,000	$ 100,000
Unrecognized tax benefit — Temporary tax positions	1,500,000	1,200,000
Total unrecognized tax benefit	1,700,000	1,300,000
NOL and tax credit carryforwards	(900,000)	(900,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	(1,000,000)
Amounts accrued for penalties related to unrecognized tax benefits	$ 0	$ 0

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Rate Matters (Details) (Public Service Commission of Wisconsin (PSCW) [Member], USD $) In Millions, unless otherwise specified	1 Months Ended			0 Months Ended
	May 31, 2013 Electric and Gas Rate Case 2014, Electric Rates [Member]	May 31, 2013 Electric and Gas Rate Case 2014, Gas Rates [Member]	May 31, 2013 Electric and Gas Rate Case 2014 [Member]	Oct. 18, 2013 Subsequent Event [Member] Electric and Gas Rate Case 2014, Electric Rates [Member]	Oct. 04, 2013 Subsequent Event [Member] Electric and Gas Rate Case 2014, Electric Rates [Member]	Oct. 18, 2013 Subsequent Event [Member] Electric and Gas Rate Case 2014, Gas Rates [Member]	Oct. 04, 2013 Subsequent Event [Member] Electric and Gas Rate Case 2014, Gas Rates [Member]	Oct. 18, 2013 Subsequent Event [Member] Electric and Gas Rate Case 2014 [Member]	Oct. 04, 2013 Subsequent Event [Member] Electric and Gas Rate Case 2014 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 34.0		$ 0
Public Utilities, Requested Rate Increase (Decrease), Amount	40.0	4.7
Public Utilities, Requested Rate Increase (Decrease), Percentage	6.50%	3.80%
Public Utilities, Requested Return on Equity, Percentage			10.40%					10.40%
Public Utilities, Requested Equity Capital Structure, Percentage			52.50%
Forecasted Average Net Investment Rate Base, Electric Utility			895.3
Forecasted Average Net Investment Rate Base, Natural Gas Utility			89.8
Public Utilities, Return on equity recommended by third parties									10.20%
Public Utilities, Debt capital structure recommended by third parties									52.50%
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to electric fuel and purchased power					(5.1)		0
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to the sales forecast					(4.8)		0
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to incentive compensation					(3.0)		(0.6)
Public Utilities, Adjustment recommended by third parties related to return on equity					(1.6)		(0.2)
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to conservation programs					0.7		(0.7)
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to depreciation expense					(0.7)		(1.3)
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to amortization expenses					0		(2.3)
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs					(1.7)		(0.7)
Public Utilities, Rate increase (decrease) recommended by third parties					$ 23.8		$ (1.1)
Public Utilities, Rate increase (decrease) recommended by third parties, percentage					3.80%		(0.90%)

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Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in NSP-Wisconsin’s 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-Wisconsin 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 Sept. 30, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2013, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009.  In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011.  As of Sept. 30, 2013, no material adjustments had been proposed for these years.  There are currently no other state income tax audits in progress.

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

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

(Millions of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.5		1.2
Total unrecognized tax benefit	$	1.7	$	1.3

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)	Sept. 30, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(0.9	)	$	(0.9	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 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 Sept. 30, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2013 or Dec. 31, 2012.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As NSP-Wisconsin had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

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Benefit Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,421		$	1,142		$	6		$	5
Interest cost	1,731			1,918			190			268
Expected return on plan assets	(2,499		)	(2,622		)	(11		)	(13		)
Amortization of transition obligation	—			—			—			42
Amortization of prior service cost (credit)	104			442			(88		)	(4		)
Amortization of net loss	1,981			1,460			241			123
Net benefit cost recognized for financial reporting	$	2,738		$	2,340		$	338		$	421

	Nine Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,262		$	3,426		$	18		$	15
Interest cost	5,193			5,753			570			806
Expected return on plan assets	(7,496		)	(7,867		)	(32		)	(38		)
Amortization of transition obligation	—			—			—			128
Amortization of prior service cost (credit)	312			1,328			(264		)	(11		)
Amortization of net loss	5,943			4,382			723			365
Net benefit cost recognized for financial reporting	$	8,214		$	7,022		$	1,015		$	1,265

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Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Letters of Credit [Abstract]
Terms of letters of credit (in years)	1 year
Letters of credit outstanding under credit facilities	$ 0	$ 0

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Borrowings and Other Financing Instruments

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	150		$	150
Amount outstanding at period end	11			39
Average amount outstanding	4			61
Maximum amount outstanding	19			116
Weighted average interest rate, computed on a daily basis	0.22		%	0.39		%
Weighted average interest rate at period end	0.18			0.40

Letters of Credit— NSP-Wisconsin may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Sept. 30, 2013 and Dec. 31, 2012, there were no letters of credit outstanding.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin 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 aggregate 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 Sept. 30, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150.0	$	11.0	$	139.0

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper.

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

Other Short-Term Borrowings— The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.:

(Amounts in Millions, Except Interest Rates)	Sept. 30, 2013			Dec. 31, 2012
Notes payable to affiliates	$	0.5		$	0.6
Weighted average interest rate at period end	0.25		%	0.33		%

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Selected Balance Sheet Data

9 Months Ended

Sep. 30, 2013

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Accounts receivable, net (a)
Accounts receivable	$	52,596		$	55,039
Less allowance for bad debts	(4,477		)	(4,333		)
	$	48,119		$	50,706

^(a) Accounts receivable, net includes $14 and $586 due from affiliates as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(Thousands of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	6,406	$	6,172
Fuel	5,771		6,664
Natural gas	10,822		6,849
	$	22,999	$	19,685

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	1,869,563		$	1,795,239
Natural gas plant	231,778			224,625
Common and other property	112,514			111,319
Construction work in progress	101,436			62,629
Total property, plant and equipment	2,315,291			2,193,812
Less accumulated depreciation	(936,644		)	(895,576		)
	$	1,378,647		$	1,298,236

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 1,526		$ 4,459
Accounts receivable, net	48,119	[1]	50,706	[1]
Accrued unbilled revenues	38,062		49,138
Inventories	22,999		19,685
Regulatory assets	17,011		12,048
Prepaid taxes	16,063		24,688
Deferred income taxes	10,466		0
Prepayments and other	2,889		4,394
Total current assets	157,135		165,118
Property, plant and equipment, net	1,378,647		1,298,236
Other assets
Regulatory assets	237,339		240,459
Other investments	3,483		3,232
Other	3,677		4,040
Total other assets	244,499		247,731
Total assets	1,780,281		1,711,085
Current liabilities
Current portion of long-term debt	103		1,246
Short-term debt	11,000		39,000
Notes payable to affiliates	470		550
Accounts payable	29,096		30,723
Accounts payable to affiliates	29,158		31,556
Dividends payable to parent	8,038		7,667
Regulatory liabilities	4,233		6,086
Taxes accrued	8,303		839
Environmental liabilities	23,817		23,427
Accrued interest	7,549		7,304
Other	9,627		10,955
Total current liabilities	131,394		159,353
Deferred credits and other liabilities
Deferred income taxes	294,026		261,800
Deferred investment tax credits	9,576		8,911
Regulatory liabilities	125,982		123,746
Environmental liabilities	81,862		84,655
Customer advances	16,861		15,631
Pension and employee benefit obligations	54,354		63,643
Other	9,141		8,923
Total deferred credits and other liabilities	591,802		567,309
Commitments and contingencies
Capitalization
Long-term debt	468,511		467,317
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Sept. 30, 2013 and Dec. 31, 2012, respectively	93,300		93,300
Additional paid in capital	232,349		189,867
Retained earnings	263,305		234,376
Accumulated other comprehensive loss	(380)		(437)
Total common stockholder’s equity	588,574		517,106
Total liabilities and equity	$ 1,780,281		$ 1,711,085

[1] Accounts receivable, net includes $14 and $586 due from affiliates as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

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Benefit Plans and Other Postretirement Benefits (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost	$ 1,421,000	$ 1,142,000	$ 4,262,000	$ 3,426,000
Interest cost	1,731,000	1,918,000	5,193,000	5,753,000
Expected return on plan assets	(2,499,000)	(2,622,000)	(7,496,000)	(7,867,000)
Amortization of transition obligation	0	0	0	0
Amortization of prior service cost (credit)	104,000	442,000	312,000	1,328,000
Amortization of net loss	1,981,000	1,460,000	5,943,000	4,382,000
Net benefit cost recognized for financial reporting	2,738,000	2,340,000	8,214,000	7,022,000
Total contributions to Xcel Energy's pension plans during the period			11,300,000
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost	6,000	5,000	18,000	15,000
Interest cost	190,000	268,000	570,000	806,000
Expected return on plan assets	(11,000)	(13,000)	(32,000)	(38,000)
Amortization of transition obligation	0	42,000	0	128,000
Amortization of prior service cost (credit)	(88,000)	(4,000)	(264,000)	(11,000)
Amortization of net loss	241,000	123,000	723,000	365,000
Net benefit cost recognized for financial reporting	338,000	421,000	1,015,000	1,265,000
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 192,200,000
Number of Xcel Energy's pension plans to which contributions were made	4		4

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Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at beginning of period	$ (400,000)	$ (476,000)	$ (437,000)	$ (514,000)
After-tax net realized losses on derivative transactions reclassified into earnings	20,000	20,000	57,000	58,000
Accumulated other comprehensive loss related to cash flow hedges at end of period	(380,000)	(456,000)	(380,000)	(456,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)				2,900,000
Derivative instruments designated as fair value hedges	0	0	0	0
Natural Gas Commodity Contract [Member] | Cash Flow Hedging Other [Member]
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	$ (200,000)		$ (400,000)	$ (400,000)

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Selected Balance Sheet Data, Inventory (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Public Utilities, Inventory [Line Items]
Inventories	$ 22,999	$ 19,685
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	6,406	6,172
Fuel
Public Utilities, Inventory [Line Items]
Inventories	5,771	6,664
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 10,822	$ 6,849

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Segment Information

Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Wisconsin’s chief operating decision maker.  NSP-Wisconsin 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-Wisconsin has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

• NSP-Wisconsin’s regulated electric utility segment generates electricity which is transmitted and distributed in Wisconsin and Michigan.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities primarily in Wisconsin.

• NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas in portions of Wisconsin and Michigan.

• 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 investments in rental housing projects that qualify for low-income housing tax credits.

Asset and capital expenditure information is not provided for NSP-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin 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 operating and maintenance (O&M) expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2013
Operating revenues from external customers	$	216,545	$	14,266		$	249	$	—		$	231,060
Intersegment revenues	89		962			—		(1,051		)	—
Total revenues	$	216,634	$	15,228		$	249	$	(1,051	)	$	231,060
Net income (loss)	$	22,859	$	(1,726	)	$	880	$	—		$	22,013

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2012
Operating revenues from external customers	$	214,426	$	11,742		$	307	$	—		$	226,475
Intersegment revenues	82		321			—		(403		)	—
Total revenues	$	214,508	$	12,063		$	307	$	(403	)	$	226,475
Net income (loss)	$	21,743	$	(1,461	)	$	1,918	$	—		$	22,200

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2013
Operating revenues from external customers	$	592,730	$	89,178	$	742	$	—		$	682,650
Intersegment revenues	250		1,549		—		(1,799		)	—
Total revenues	$	592,980	$	90,727	$	742	$	(1,799	)	$	682,650
Net income	$	46,530	$	4,100	$	1,612	$	—		$	52,242

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2012
Operating revenues from external customers	$	575,532	$	68,064	$	851	$	—		$	644,447
Intersegment revenues	278		585		—		(863		)	—
Total revenues	$	575,810	$	68,649	$	851	$	(863	)	$	644,447
Net income	$	39,118	$	992	$	2,710	$	—		$	42,820

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except as noted below and in Note 5, the circumstances set forth in Notes 10 and 11 to the consolidated financial statements in NSP-Wisconsin’s 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 and are incorporated herein by reference.  The following include commitments, contingencies and unresolved contingencies that are material to NSP-Wisconsin’s financial position.

Guarantees — NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program.  NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement.  The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee.  The guarantee contains no recourse provisions and requires no collateral.

The following table presents the guarantee issued and outstanding for NSP-Wisconsin:

(Millions of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.3		0.4

Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis.  The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site.  In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site.  The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site.  As a result of those settlement negotiations, the EPA agreed to segment the Ashland site into separate areas.  The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff.  The second area includes the Sediments.

In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources (WDNR), the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin.  This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area.  Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site.  The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million.  The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments.  As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees.  Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing.  In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation will be received and reported in November 2013. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a wet dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a wet dredge pilot study in 2011. The EPA’s ROD for the Ashland site includes estimates that the cost of the preferred remediation related to the Sediments is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site.  Trial for this matter has been rescheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At Sept. 30, 2013 and Dec. 31, 2012, NSP-Wisconsin had recorded a liability of $101.2 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $19.5 million and $20.1 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change.  NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site.  Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.  The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities.  External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process.  Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period.  The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

In the last rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin.  The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a three percent carrying cost to the unamortized regulatory asset.  Implementation of this exception will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard (NSPS) Proposal and Emission Guideline for Existing Sources — In September 2013, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish carbon dioxide (CO₂) emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal 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 Wisconsin.  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.  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 hear arguments in December 2013. The Court will likely issue a decision by June 2014.

As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, NSP-Wisconsin expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions.  Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  NSP-Wisconsin purchased allowances in 2012 and plans to continue to purchase allowances in 2013 to comply with the CAIR.  At Sept. 30, 2013, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin did not have a material impact on the results of operations, financial position or cash flows.

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. 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. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

Legal Contingencies

NSP-Wisconsin 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-Wisconsin’s financial statements.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

Environmental Litigation

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. Plaintiffs elected not to seek further review of this decision, which brings this litigation to a close.  No accrual was recorded for this matter.

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Selected Balance Sheet Data (Tables)

9 Months Ended

Sep. 30, 2013

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Accounts receivable, net (a)
Accounts receivable	$	52,596		$	55,039
Less allowance for bad debts	(4,477		)	(4,333		)
	$	48,119		$	50,706

^(a) Accounts receivable, net includes $14 and $586 due from affiliates as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

Inventories

(Thousands of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	6,406	$	6,172
Fuel	5,771		6,664
Natural gas	10,822		6,849
	$	22,999	$	19,685

Property, Plant and Equipment, Net

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	1,869,563		$	1,795,239
Natural gas plant	231,778			224,625
Common and other property	112,514			111,319
Construction work in progress	101,436			62,629
Total property, plant and equipment	2,315,291			2,193,812
Less accumulated depreciation	(936,644		)	(895,576		)
	$	1,378,647		$	1,298,236

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Benefit Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,421		$	1,142		$	6		$	5
Interest cost	1,731			1,918			190			268
Expected return on plan assets	(2,499		)	(2,622		)	(11		)	(13		)
Amortization of transition obligation	—			—			—			42
Amortization of prior service cost (credit)	104			442			(88		)	(4		)
Amortization of net loss	1,981			1,460			241			123
Net benefit cost recognized for financial reporting	$	2,738		$	2,340		$	338		$	421

	Nine Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,262		$	3,426		$	18		$	15
Interest cost	5,193			5,753			570			806
Expected return on plan assets	(7,496		)	(7,867		)	(32		)	(38		)
Amortization of transition obligation	—			—			—			128
Amortization of prior service cost (credit)	312			1,328			(264		)	(11		)
Amortization of net loss	5,943			4,382			723			365
Net benefit cost recognized for financial reporting	$	8,214		$	7,022		$	1,015		$	1,265

In 2013, contributions of $192.2 million were made across four of Xcel Energy’s pension plans, of which $11.3 million was attributable to NSP-Wisconsin.  Xcel Energy does not expect additional pension contributions during 2013.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 28, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO /WI/
Entity Central Index Key	0000072909
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		933,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2013

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

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

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at July 1	$	(400	)
Losses reclassified from net accumulated other comprehensive loss	20
Net current period other comprehensive income	20
Accumulated other comprehensive loss at Sept. 30	$	(380	)

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	57
Net current period other comprehensive income	57
Accumulated other comprehensive loss at Sept. 30	$	(380	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2013				Nine Months Ended Sept. 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	32		(a)	$	95		(a)
Total, pre-tax	32				95
Tax benefit	(12		)		(38		)
Total amounts reclassified, net of tax	$	20			$	57

^(a)  Included in interest charges.