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 June 30, 2015

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 Aug. 3, 2015
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	22
PART II — OTHER INFORMATION
Item 1    —	Legal Proceedings	23
Item 1A —	Risk Factors	23
Item 4    —	Mine Safety Disclosures	23
Item 5    —	Other Information	23
Item 6    —	Exhibits	23
SIGNATURES		24

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.  The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. 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 June 30						Six Months Ended June 30
	2015			2014			2015			2014
Operating revenues
Electric	$	199,621		$	198,277		$	409,905		$	409,374
Natural gas	16,889			29,539			80,185			103,330
Other	303			298			683			552
Total operating revenues	216,813			228,114			490,773			513,256
Operating expenses
Electric fuel and purchased power, non-affiliates	1,159			2,684			2,442			9,180
Purchased power, affiliates	104,413			104,532			216,245			216,458
Cost of natural gas sold and transported	8,120			19,194			50,558			70,336
Operating and maintenance expenses	45,661			48,433			87,834			92,664
Conservation program expenses	2,989			3,015			5,844			5,687
Depreciation and amortization	22,528			19,874			43,889			39,181
Taxes (other than income taxes)	6,874			6,652			14,106			13,449
Loss on Monticello life cycle management/extended power uprate project	—			—			5,237			—
Total operating expenses	191,744			204,384			426,155			446,955
Operating income	25,069			23,730			64,618			66,301
Other income, net	35			(70		)	284			54
Allowance for funds used during construction — equity	1,778			1,767			3,997			3,339
Interest charges and financing costs
Interest charges — includes other financing costs of $410, $377, $812 and $751, respectively	7,771			6,968			15,527			13,835
Allowance for funds used during construction — debt	(864		)	(850		)	(1,934		)	(1,608		)
Total interest charges and financing costs	6,907			6,118			13,593			12,227
Income before income taxes	19,975			19,309			55,306			57,467
Income taxes	7,463			7,287			20,527			21,210
Net income	$	12,512		$	12,022		$	34,779		$	36,257

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014
Net income	$	12,512	$	12,022	$	34,779	$	36,257
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $12 and $25 for each of the three and six months ended June 30, 2015 and 2014, respectively	19		19		38		37
Other comprehensive income	19		19		38		37
Comprehensive income	$	12,531	$	12,041	$	34,817	$	36,294

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30
	2015			2014
Operating activities
Net income	$	34,779		$	36,257
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	44,539			39,754
Deferred income taxes	20,219			16,877
Amortization of investment tax credits	(264		)	(337		)
Allowance for equity funds used during construction	(3,997		)	(3,339		)
Loss on Monticello life cycle management/extended power uprate project	5,237			—
Net derivative losses	586			108
Changes in operating assets and liabilities:
Accounts receivable	7,107			2,105
Accrued unbilled revenues	13,636			10,460
Inventories	7,696			2,672
Other current assets	6,876			3,680
Accounts payable	8,058			(3,981		)
Net regulatory assets and liabilities	(2,182		)	(23,547		)
Other current liabilities	3,222			(22		)
Pension and other employee benefit obligations	(4,403		)	(7,378		)
Change in other noncurrent assets	(8		)	101
Change in other noncurrent liabilities	412			872
Net cash provided by operating activities	141,513			74,282
Investing activities
Utility capital/construction expenditures	(150,443		)	(124,624		)
Allowance for equity funds used during construction	3,997			3,339
Other, net	(37		)	8
Net cash used in investing activities	(146,483		)	(121,277		)
Financing activities
Proceeds from short-term borrowings, net	(78,000		)	(57,000		)
Proceeds from notes payable to affiliate	—			30
Proceeds from issuance of long-term debt	98,375			98,926
Repayments of long-term debt	(25		)	(36		)
Capital contributions from parent	29,638			20,479
Dividends paid to parent	(28,272		)	(16,089		)
Net cash provided by financing activities	21,716			46,310
Net change in cash and cash equivalents	16,746			(685		)
Cash and cash equivalents at beginning of period	1,285			1,349
Cash and cash equivalents at end of period	$	18,031		$	664
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(13,001	)	$	(11,516	)
Cash received (paid) for income taxes, net	6,993			(359		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	13		$	16,844

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	June 30, 2015			Dec. 31, 2014
Assets
Current assets
Cash and cash equivalents	$	18,031		$	1,285
Accounts receivable, net	53,289			60,396
Accrued unbilled revenues	39,931			53,567
Inventories	16,989			24,685
Regulatory assets	12,919			20,036
Prepaid taxes	24,653			28,628
Deferred income taxes	14,671			8,201
Prepayments and other	3,966			6,918
Total current assets	184,449			203,716
Property, plant and equipment, net	1,752,403			1,674,281
Other assets
Regulatory assets	277,021			280,693
Other investments	3,855			3,818
Other	5,248			4,612
Total other assets	286,124			289,123
Total assets	$	2,222,976		$	2,167,120
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,210		$	1,235
Short-term debt	—			78,000
Notes payable to affiliates	500			500
Accounts payable	32,597			61,530
Accounts payable to affiliates	28,260			26,524
Dividends payable to parent	11,993			14,957
Regulatory liabilities	9,561			16,940
Environmental liabilities	23,429			29,116
Other	22,170			19,923
Total current liabilities	129,720			248,725
Deferred credits and other liabilities
Deferred income taxes	376,867			348,180
Deferred investment tax credits	8,824			9,089
Regulatory liabilities	138,054			132,674
Environmental liabilities	85,281			78,620
Customer advances	18,213			17,623
Pension and employee benefit obligations	46,864			51,313
Other	16,004			16,151
Total deferred credits and other liabilities	690,107			653,650
Commitments and contingencies
Capitalization
Long-term debt	666,313			567,056
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively	93,300			93,300
Additional paid in capital	351,914			322,276
Retained earnings	291,869			282,398
Accumulated other comprehensive loss	(247		)	(285		)
Total common stockholder’s equity	736,836			697,689
Total liabilities and equity	$	2,222,976		$	2,167,120

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 June 30, 2015 and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three months and six months ended June 30, 2015 and 2014; and its cash flows for the six months ended June 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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, 2014, filed with the SEC on Feb. 23, 2014. 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, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2015-02 on its consolidated financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, NSP-Wisconsin does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (Accounting Standards Update (ASU) No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, NSP-Wisconsin does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

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3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Accounts receivable, net (a)
Accounts receivable	$	57,894		$	66,217
Less allowance for bad debts	(4,605		)	(5,821		)
	$	53,289		$	60,396

(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	6,914	$	6,494
Fuel	6,753		6,654
Natural gas	3,322		11,537
	$	16,989	$	24,685

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	2,178,038		$	2,061,669
Natural gas plant	259,820			255,465
Common and other property	125,424			125,938
Construction work in progress	218,777			231,413
Total property, plant and equipment	2,782,059			2,674,485
Less accumulated depreciation	(1,029,656		)	(1,000,204		)
	$	1,752,403		$	1,674,281

^(a)  Accounts receivable, net includes an immaterial amount due from affiliates as of June 30, 2015 and Dec. 31, 2014, respectively.

4. Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, 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 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. As of June 30, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution is uncertain.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2015, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2010. As of June 30, 2015, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	June 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	2.4		2.9
Total unrecognized tax benefit	$	2.6	$	3.0

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

(Millions of Dollars)	June 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(0.7	)	$	(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 appeals process progresses and state audits resume. As the IRS appeals process moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014.

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, 2014 and in Note 5 to NSP-Wisconsin’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, 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 2016 Electric and Gas Rate Case — On May 29, 2015, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested an overall increase in annual electric rates of $27.4 million, or 3.9 percent, and an increase in natural gas rates of $5.9 million, or 5.0 percent.

The rate filing is based on a 2016 forecast test year, a return on equity (ROE) of 10.2 percent, an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility.

Key dates in the procedural schedule are as follows:

• Staff and Intervenor Direct Testimony — Oct. 1, 2015;

• Rebuttal Testimony — Oct. 19, 2015;

• Sur-Rebuttal Testimony — Oct. 27, 2015;

• Technical Hearing — Oct. 29, 2015;

• Initial Brief — Nov. 12, 2015;

• Reply Brief — Nov. 19, 2015; and

• A PSCW decision is anticipated in December 2015.

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

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello life cycle management (LCM)/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW). Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

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In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used and useful for 2014.  As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaint/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.

In June 2014, the FERC issued an order adopting a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

The FERC set the ROE complaint against the MISO TOs for settlement and hearing procedures. The FERC directed parties to apply the new ROE methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. The settlement procedures were unsuccessful. In January 2015, the ROE complaint was set for full hearing procedures.

The complainants and intervenors filed testimony recommending an ROE between 8.67 percent and 9.54 percent. The FERC staff recommended an ROE of 8.68 percent. The MISO TOs recommended an ROE not less than 10.8 percent. A hearing is scheduled for August 2015, with an administrative law judge (ALJ) initial decision to be issued by November 2015 and a FERC order issued no earlier than 2016.

In November 2014, certain MISO TOs filed a request for FERC approval of a 50 basis point RTO membership ROE adder, with collection deferred until resolution of the ROE complaint. In January 2015, the FERC approved the ROE adder, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology.

In February 2015, an intervenor in the November 2013 ROE complaint filed a second complaint proposing to reduce the MISO region ROE to 8.67 percent, prior to any 50 basis point RTO adder. In June 2015, the FERC set the second ROE complaint for a hearing process, establishing a Feb. 12, 2015 refund effective date. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. The FERC decision would continue the ROE refund obligation initiated under the November 2013 complaint through May 2016. On July 20, 2015, the MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints involving the same issue with consecutive refund periods, arguing this ruling is contrary to the governing statute. FERC action on the rehearing request is pending.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of June 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5, 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, 2014 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.

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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 its exposure 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)	June 30, 2015		Dec. 31, 2014
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.1		0.2

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. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.

In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, 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, 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. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. Demolition activities occurred at the Ashland site in 2013. Soil, including excavation and treatment, as well as containment wall remedies were completed in early 2015. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and preliminary activities, including the installation of ground wells, have commenced at the site. Construction on the groundwater treatment plant is anticipated to commence in fall 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $57 million, of which approximately $35 million has already been spent. 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.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. It is NSP-Wisconsin’s view that the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy 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 November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent for the Wet Dredge pilot study with the EPA.

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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 took place in May 2015. A judicial decision is expected in the third quarter of 2015. A final settlement has been reached between NSP-Wisconsin, along with the EPA, and two of the PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”) resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. NSP-Wisconsin also has entered a second private party settlement agreement with LE Myers Co. Under the agreements, the Railroad PRPs contributed $10.5 million and LE Myers Co. contributed $5.4 million to the costs of the cleanup at the Ashland site. The agreements for the Railroad PRPs and LE Myers Co. were approved by the U.S. District Court for the Western District of Wisconsin in 2015 and payment has been received. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers. Two additional PRPs remain in the case.

At June 30, 2015 and Dec. 31, 2014, NSP-Wisconsin had recorded a liability of $108.5 million and $107.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $23.2 million and $28.9 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 NSP-Wisconsin rate recovery for all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. Under the established PSCW policy, once deferred MGP remediation costs are determined by the PSCW to be prudent, utilities are allowed to recover those deferred costs in natural gas rates, typically over a four- to six-year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

The PSCW reviewed the existing MGP cost recovery policy as it applied to the Ashland site in the context of NSP-Wisconsin’s 2013 general rate case. In December 2012, 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. In a 2014 rate case decision, the PSCW continued the cost recovery treatment with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area and allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. Cost recovery will continue at the level set in the 2014 rate case though 2015.  In May 2015, NSP-Wisconsin filed its 2016 rate case, in which it requested an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million. A decision is anticipated in late 2015.

Environmental Requirements

Water

Federal Clean Water Act (CWA) Waters of the United States Rule —In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule will go into effect beginning in August 2015. NSP-Wisconsin does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

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Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO₂₎ and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Wisconsin, using an emissions trading program.

In August 2012, the United States District 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 the EPA must continue administering the Clean Air Interstate Rule pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect.

In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015.

NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO₂. NSP-Wisconsin is complying with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, NSP-Wisconsin had met the EGU MATS rule by ending use of coal at Bay Front Unit 5. On June 29, 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. NSP-Wisconsin believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

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.

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 June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	150		$	150
Amount outstanding at period end	—			78
Average amount outstanding	74			46
Maximum amount outstanding	92			101
Weighted average interest rate, computed on a daily basis	0.43		%	0.27		%
Weighted average interest rate at period end	N/A			0.55

Letters of Credit— NSP-Wisconsin uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2015 and Dec. 31, 2014, 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 June 30, 2015, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150	$	—	$	150

^(a)  This credit facility expires in October 2019.

^(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 June 30, 2015 and Dec. 31, 2014.

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)	June 30, 2015			Dec. 31, 2014
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate at period end	0.56		%	0.51		%

Long-Term Borrowings

In June, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024.

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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 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 for trading purposes and 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 June 30, 2015, 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, including forecasted amounts for unsettled hedges, as applicable.

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, as well as for trading purposes. This could include the purchase or sale of natural gas to generate electric energy and natural gas for resale.

The following table details the gross notional amounts of commodity options at June 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands)(a)(b)	June 30, 2015	Dec. 31, 2014
Million British thermal units of natural gas	1,223	18

^(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.

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Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — There were immaterial pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings during the three months ended June 30, 2015 and 2014, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the six months ended June 30, 2015 and 2014.

During the three months and six months ended June 30, 2015, changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses recognized as regulatory assets and liabilities. For the three and six months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses and net gains of $0.7 million, respectively, 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 gains of $1.0 million and $0.5 million were recognized for the six months ended June 30, 2015 and 2014, respectively, 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. There were immaterial natural gas commodity derivatives settlement losses recognized during the three months ended June 30, 2015 and 2014, respectively.

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations—NSP-Wisconsin continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-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 unsettled 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.

Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis:

	June 30, 2015
	Fair Value						Fair Value Total		Counterparty Netting(a)			Total(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3
Current derivative assets
Natural gas commodity	$	—	$	3	$	—	$	3	$	(3	)	$	—
Total current derivative assets	$	—	$	3	$	—	$	3	$	(3	)	$	—
Current derivative liabilities
Natural gas commodity	$	—	$	48	$	—	$	48	$	(3	)	$	45
Total current derivative liabilities	$	—	$	48	$	—	$	48	$	(3	)	$	45

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(a)		Total(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3
Current derivative assets
Natural gas commodity	$	—	$	52	$	—	$	52	$	—	$	52

^(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 Dec. 31, 2014.  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 liabilities balance of $22.2 million at June 30, 2015 and prepayments and other assets balance of $6.9 million at Dec. 31, 2014, in the consolidated balance sheets.

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Fair Value of Long-Term Debt

As of June 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	667,523	$	730,460	$	568,291	$	670,665

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 June 30, 2015 and Dec. 31, 2014, 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 Income (Expense), Net

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

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2015			2014			2015			2014
Interest (expense) income	$	(9	)	$	12		$	288		$	216
Other nonoperating income	69			44			130			79
Insurance policy expense	(23		)	(124		)	(129		)	(236		)
Other nonoperating expense	(2		)	(2		)	(5		)	(5		)
Other income (expense), net	$	35		$	(70	)	$	284		$	54

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, transmits and distributes electricity primarily in portions of Wisconsin and Michigan. 

• NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas primarily 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 operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2015
Operating revenues (a)	$	199,621	$	16,889		$	303		$	—		$	216,813
Intersegment revenues	98		73			—			(171		)	—
Total revenues	$	199,719	$	16,962		$	303		$	(171	)	$	216,813
Net income (loss)	$	13,787	$	(1,074	)	$	(201	)	$	—		$	12,512

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2014
Operating revenues (a)	$	198,277	$	29,539		$	298	$	—		$	228,114
Intersegment revenues	123		849			—		(972		)	—
Total revenues	$	198,400	$	30,388		$	298	$	(972	)	$	228,114
Net income (loss)	$	11,799	$	(141	)	$	364	$	—		$	12,022

^(a)  Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014.

(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2015
Operating revenues (a)	$	409,905		$	80,185	$	683		$	—		$	490,773
Intersegment revenues	207			298		—			(505		)	—
Total revenues	$	410,112		$	80,483	$	683		$	(505	)	$	490,773
Net income (loss)	$	29,301	(b)	$	5,707	$	(229	)	$	—		$	34,779

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2014
Operating revenues (a)	$	409,374	$	103,330	$	552	$	—		$	513,256
Intersegment revenues	215		3,766		—		(3,981		)	—
Total revenues	$	409,589	$	107,096	$	552	$	(3,981	)	$	513,256
Net income	$	26,865	$	7,568	$	1,824	$	—		$	36,257

^(a)  Operating revenues include $78 million and $63 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014, respectively.

^(b)  Includes a net of tax charge related to the Monticello LCM/EPU project.  See Note 5.

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,190		$	1,132		$	7		$	8
Interest cost	1,630			1,814			163			197
Expected return on plan assets	(2,371		)	(2,410		)	(7		)	(13		)
Amortization of prior service cost (credit)	28			28			(88		)	(87		)
Amortization of net loss	1,701			1,654			114			166
Net benefit cost recognized for financial reporting	$	2,178		$	2,218		$	189		$	271

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	Six Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,380		$	2,264		$	14		$	17
Interest cost	3,260			3,628			326			395
Expected return on plan assets	(4,742		)	(4,821		)	(15		)	(26		)
Amortization of prior service cost (credit)	56			56			(176		)	(175		)
Amortization of net loss	3,402			3,308			228			333
Net benefit cost recognized for financial reporting	$	4,356		$	4,435		$	377		$	544

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $4.9 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during 2015.

12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
Accumulated other comprehensive loss at April 1	$	(266	)	$	(343	)
Losses reclassified from net accumulated other comprehensive loss	19			19
Net current period other comprehensive income	19			19
Accumulated other comprehensive loss at June 30	$	(247	)	$	(324	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(285	)	$	(361	)
Losses reclassified from net accumulated other comprehensive loss	38			37
Net current period other comprehensive income	38			37
Accumulated other comprehensive loss at June 30	$	(247	)	$	(324	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	31		(a)	$	31		(a)
Total, pre-tax	31				31
Tax benefit	(12		)		(12		)
Total amounts reclassified, net of tax	$	19			$	19

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	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	63		(a)	$	62		(a)
Total, pre-tax	63				62
Tax benefit	(25		)		(25		)
Total amounts reclassified, net of tax	$	38			$	37

^(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.

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 slowdown 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; cyber security threats and data security breaches; 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; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force 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 and Exhibit 99.01 of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2014, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2015.

19

Results of Operations

NSP-Wisconsin’s net income was $34.8 million for the six months ended June 30, 2015 compared with $36.3 million for the same period in 2014. The impact of the Monticello LCM/EPU project loss, the unfavorable impact of weather and higher depreciation were partially offset by lower O&M expenses and higher electric margins, primarily due to electric rate increases. See Note 5 to the consolidated financial statements for further discussion of the Monticello LCM/EPU project loss.

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:

	Six Months Ended June 30
(Millions of Dollars)	2015			2014
Electric revenues	$	410		$	409
Electric fuel and purchased power	(219		)	(226		)
Electric margin	$	191		$	183

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

June 30:

Electric Revenues

(Millions of Dollars)	2015 vs. 2014
Fuel and purchased power cost recovery	$	3
Interchange agreement billings with NSP-Minnesota	3
Retail rate increases (Wisconsin and Michigan)	2
Estimated impact of weather	(7		)
Retail sales decline, excluding weather impact	(2		)
Other, net	2
Total increase in electric revenues	$	1

Electric Margin

(Millions of Dollars)	2015 vs. 2014
Fuel cost recovery	$	9
Interchange agreement billings with NSP-Minnesota	5
Retail rate increases (Wisconsin and Michigan)	2
Estimated impact of weather	(7		)
Retail sales decline, excluding weather impact	(2		)
Other, net	1
Total increase in electric margin	$	8

Natural Gas Revenues and Margin

Total natural gas expense 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:

	Six Months Ended June 30
(Millions of Dollars)	2015			2014
Natural gas revenues	$	80		$	103
Cost of natural gas sold and transported	(51		)	(70		)
Natural gas margin	$	29		$	33

20

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

Natural Gas Revenues

(Millions of Dollars)	2015 vs. 2014
Purchased natural gas adjustment clause recovery	$	(20	)
Estimated impact of weather	(4		)
Other, net	1
Total decrease in natural gas revenues	$	(23	)

Natural Gas Margin

(Millions of Dollars)	2015 vs. 2014
Estimated impact of weather	$	(4	)
Other, net	—
Total decrease in natural gas margin	$	(4	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased$4.8 million, or 5.2 percent, for the six months ended June 30, 2015. The decrease was primarily due to Interchange Agreement billings with NSP-Minnesota related to timing of transmission projects.

(Millions of Dollars)	2015 vs. 2014
Interchange agreement billings with NSP-Minnesota	$	(6	)
Electric and gas distribution expenses	1
Total increase in O&M expenses	$	(5	)

Depreciation and Amortization — Depreciation and amortization increased $4.7 million or 12.0 percent for the six months ended June 30, 2015. The increase was primarily attributed to normal system expansion.

Income Taxes — Income tax expense decreased $0.7 million for the six months ended June 30, 2015. The decrease in income tax expense was primarily due to lower pretax earnings in 2015. The ETR was 37.1 percent for the six months ended June 30, 2015 compared with 36.9 percent for the same period in 2014.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1. of NSP-Wisconsin's Annual Report on Form 10-K for the year ended Dec. 31, 2014, and Public Utility Regulation included in Item 2. of NSP-Wisconsin's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, appropriately represent, in all material respects. the current status of public utility regulation, and are incorporated herein by reference.

NSP System Resource Plans — In January 2015, NSP-Minnesota filed its 2016-2030 Resource Plan with the MPUC, proposing to achieve a 40 percent reduction in carbon emissions by 2030 from 2005 levels through the significant addition of renewables, continued commitment to specific critical infrastructure protection annual achievements and the continued operation of its existing cost-effective thermal generation. In March 2015, NSP-Minnesota supplemented the plan to reflect (1) the resource additions that resulted from its Competitive Acquisition Plan (CAP) to meet an identified resource need in the 2018-2020 timeframe, (2) significantly higher than expected response to its Community Solar Gardens program, and (3) additional early Sherco 1 and 2 retirement scenarios. The updated resource plan continues to position NSP-Minnesota to be responsive to future environmental requirements and market trends, builds on the significant investments already made in the NSP System and acknowledges the divergence in state energy policies within the NSP System. Key points of the resource plan include:

• Adding 600 MW of non-production tax credit wind by 2020 and an additional 1,200 MW by 2027, bringing total wind power on the NSP System to over 3,600 MW;

• Adding 187 MW of large-scale solar energy by year-end 2016 and an additional 1,700 MW of large-scale solar and 500 MW of customer-driven small-scale solar; bringing total solar power on the NSP System to approximately 2,400 MW;

• Operating the Monticello and Prairie Island nuclear plants through their current licenses; and

• Continuing to run Sherco Units 1 and 2 with gradually decreasing reliance through 2030.

21

NSP-Minnesota continues to execute on several aspects of the additional CAP resources approved by the MPUC in February 2015, including:

• Executed an agreement for 100 MW of distributed solar with Geronimo Energy LLC;

• Executed an agreement with Calpine Corporation for a 345 MW expansion at its Mankato Energy Center; and

• Initiated pre-construction tasks needed to construct a 215 MW Black Dog Unit 6 combustion turbine at the existing generation site.

Since the filing of the resource plan, NSP-Minnesota has completed several stakeholder workshops that provided information on the Plan and March supplement as well as other key topics of interest to stakeholders. This effort is intended to both focus and reduce formal information requests regarding the resource plan. In July, the Department of Commerce filed comments on the Plan recommending that one of the Sherco units be retired in 2025, or alternatively, as early as 2020. A coalition of environmental intervenors filed comments recommending that Sherco Unit 1 close in 2021 and Unit 2 close in 2024. The current schedule calls for NSP-Minnesota to file reply comments on Sept. 2, 2015.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line — In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a Certificate of Public Convenience and Necessity (CPCN) for a new 345 Kilovolt transmission line that would extend from La Crosse, Wis. to Madison, Wis.  NSP-Wisconsin’s half of the line will be shared with three partners, Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Association-Wisconsin.  In 2011, MISO determined the line to be a Multi-Value Project (MVP) project, and as such, eligible for cost sharing under MISO’s MVP tariff. 

In April 2015, the PSCW issued its order approving a CPCN and route for the project. In June 2015, the PSCW denied two requests for rehearing. Two groups have appealed the CPCN Order to county court. Court action is pending and the CPCN remains in full effect unless one of the parties seeks and receives a stay from the court and posts a bond to cover damages the utilities may incur due to delay. The 180-mile project will cost approximately $580 million. NSP-Wisconsin’s portion of the investment is estimated to be approximately $207 million. NSP-Wisconsin and ATC anticipate beginning construction on the line in mid-2016, with completion by late 2018.

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, asset transactions and mergers, 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, 2014. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any of the ROE complaint proceedings until 2016. See Note 5 to the consolidated financial statements for discussion of the MISO ROE complaints.

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 June 30, 2015, 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.

22

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

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.

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, 2014, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03140)).
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 June 30, 2015 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 Consolidated Financial Statements, and (vi) document and entity information.

23

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)
Aug. 3, 2015	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

24

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, 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: Aug. 3, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

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: Aug. 3, 2015

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

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 June 30, 2015, 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: Aug. 3, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

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, 2014, 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

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 78,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

XML

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015		Jun. 30, 2014
Segment Reporting Information [Line Items]
Operating revenues	$ 216,813		$ 228,114		$ 490,773		$ 513,256
Net income (loss)	12,512		12,022		34,779		36,257
Affiliate electric revenue	33,000		0		78,000		63,000
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	199,719		198,400		410,112		409,589
Net income (loss)	13,787		11,799		29,301	[1]	26,865
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	16,962		30,388		80,483		107,096
Net income (loss)	(1,074)		(141)		5,707		7,568
All Other
Segment Reporting Information [Line Items]
Operating revenues	303		298		683		552
Net income (loss)	(201)		364		(229)		1,824
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	216,813	[2]	228,114	[2]	490,773	[3]	513,256	[3]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	199,621	[2]	198,277	[2]	409,905	[3]	409,374	[3]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	16,889		29,539		80,185		103,330
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	303		298		683		552
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(171)		(972)		(505)		(3,981)
Net income (loss)	0		0		0		0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	98		123		207		215
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	73		849		298		3,766
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0		$ 0		$ 0		$ 0

[1] Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5.

[2] Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014

[3] Operating revenues include $78 million and $63 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014, respectively.

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 667,523	$ 568,291
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 730,460	$ 670,665

XML

Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 2,782,059	$ 2,674,485
Less accumulated depreciation	(1,029,656)	(1,000,204)
Property, plant and equipment, net	1,752,403	1,674,281
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,178,038	2,061,669
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	259,820	255,465
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	125,424	125,938
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 218,777	$ 231,413

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Borrowings and Other Financing Instruments (Tables)

6 Months Ended

Jun. 30, 2015

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At June 30, 2015, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150	$	—	$	150

^(a)  This credit facility expires in October 2019.

^(b)  Includes outstanding commercial paper.

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for NSP-Wisconsin was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	150		$	150
Amount outstanding at period end	—			78
Average amount outstanding	74			46
Maximum amount outstanding	92			101
Weighted average interest rate, computed on a daily basis	0.43		%	0.27		%
Weighted average interest rate at period end	N/A			0.55

Notes Payable To Affiliates

Borrowings and Other Financing 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)	June 30, 2015			Dec. 31, 2014
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate at period end	0.56		%	0.51		%

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Other Comprehensive Income (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period				$ (285)
Accumulated other comprehensive loss at end of period		$ (247)		(247)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(19,975)	$ (19,309)	(55,306)	$ (57,467)
Tax benefit		7,463	7,287	20,527	21,210
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(266)	(343)	(285)	(361)
Losses reclassified from net accumulated other comprehensive loss		19	19	38	37
Net current period other comprehensive income		19	19	38	37
Accumulated other comprehensive loss at end of period		(247)	(324)	(247)	(324)
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		31	31	63	62
Tax benefit		(12)	(12)	(25)	(25)
Total, net of tax		19	19	38	37
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	$ 31	$ 31	$ 63	$ 62

[1] Included in interest charges.

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - Jun. 30, 2015 - NSP-Wisconsin - Bonds [Member] - Series Due June 15, 2024 [Member] - USD ($) $ in Millions	Total
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 100
Debt Instrument, Interest Rate, Stated Percentage	3.30%

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Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Thousands	1 Months Ended		6 Months Ended
	May. 31, 2015 USD ($)	Apr. 30, 2012 MW	Jun. 30, 2015 USD ($) Site Parties	Dec. 31, 2014 USD ($)	Apr. 30, 2014 Issue
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites, current			$ 23,429	$ 29,116
Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Number of properties included in superfund site which NSP-Wisconsin does not own | Site			2
Liability for estimated cost of remediating MGP sites			$ 108,500	107,600
Liability for estimated cost of remediating sites, current			$ 23,200	$ 28,900
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 MGP sites			$ 57,000
Estimated amount spent on Phase I Project Area cleanup			$ 35,000
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%
Approved increase (decrease) in amortization expense granted by a regulatory body			$ 1,100
Ashland MGP Site - Sediments
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Estimated cost of remediating site, low end of range			63,000
Estimated cost of remediating site, high end of range			$ 77,000
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%
NSP-Wisconsin | Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Number of PRPs that have reached a settlement in principle | Parties			2
Additional PRPs that remain in the case | Parties			2
Railroad PRPs [Member] | Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Site Contingency, Recovery from Third Party of Environmental Remediation Cost			$ 10,500
LE Myers Co. [Member] | Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Site Contingency, Recovery from Third Party of Environmental Remediation Cost			$ 5,400
Minimum
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Annual recovery for MGP clean-up costs requested in NSP-Wisconsin 2016 rate case	$ 4,700
Maximum
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Annual recovery for MGP clean-up costs requested in NSP-Wisconsin 2016 rate case	$ 7,600
Electric Generating Unit Mercury and Air Toxics Standards Rule [Member]
Site Contingency [Line Items]
Generating capacity (in MW) | MW		25
Number of years before affected facilities must demonstrate compliance, low end of range		3 years
Number of years before affected facilities must demonstrate compliance, high end of range		4 years
Cross-State Air Pollution Rule [Member]
Site Contingency [Line Items]
Number of issues on which the D.C. Circuit overturned the CSAPR | Issue					2

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Other (Expense) Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Other Income and Expenses [Abstract]
Interest (expense) income	$ (9)	$ 12	$ 288	$ 216
Other nonoperating income	69	44	130	79
Insurance policy expense	(23)	(124)	(129)	(236)
Other nonoperating expense	(2)	(2)	(5)	(5)
Other income (expense), net	$ 35	$ (70)	$ 284	$ 54

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Management's Opinion

6 Months Ended

Jun. 30, 2015

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 June 30, 2015 and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three months and six months ended June 30, 2015 and 2014; and its cash flows for the six months ended June 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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, 2014, filed with the SEC on Feb. 23, 2014. 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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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MMBTU in Thousands, $ in Millions		Jun. 30, 2015 USD ($) MMBTU	Dec. 31, 2014 MMBTU
Interest Rate Swap
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)
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Options [Abstract]
Derivative, Nonmonetary Notional amount	[1],[2]	1,223	18

[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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Benefit Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,190		$	1,132		$	7		$	8
Interest cost	1,630			1,814			163			197
Expected return on plan assets	(2,371		)	(2,410		)	(7		)	(13		)
Amortization of prior service cost (credit)	28			28			(88		)	(87		)
Amortization of net loss	1,701			1,654			114			166
Net benefit cost recognized for financial reporting	$	2,178		$	2,218		$	189		$	271

	Six Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,380		$	2,264		$	14		$	17
Interest cost	3,260			3,628			326			395
Expected return on plan assets	(4,742		)	(4,821		)	(15		)	(26		)
Amortization of prior service cost (credit)	56			56			(176		)	(175		)
Amortization of net loss	3,402			3,308			228			333
Net benefit cost recognized for financial reporting	$	4,356		$	4,435		$	377		$	544

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2015

Segment Reporting [Abstract]

Results by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2015
Operating revenues (a)	$	199,621	$	16,889		$	303		$	—		$	216,813
Intersegment revenues	98		73			—			(171		)	—
Total revenues	$	199,719	$	16,962		$	303		$	(171	)	$	216,813
Net income (loss)	$	13,787	$	(1,074	)	$	(201	)	$	—		$	12,512

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2014
Operating revenues (a)	$	198,277	$	29,539		$	298	$	—		$	228,114
Intersegment revenues	123		849			—		(972		)	—
Total revenues	$	198,400	$	30,388		$	298	$	(972	)	$	228,114
Net income (loss)	$	11,799	$	(141	)	$	364	$	—		$	12,022

^(a)  Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014.

(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2015
Operating revenues (a)	$	409,905		$	80,185	$	683		$	—		$	490,773
Intersegment revenues	207			298		—			(505		)	—
Total revenues	$	410,112		$	80,483	$	683		$	(505	)	$	490,773
Net income (loss)	$	29,301	(b)	$	5,707	$	(229	)	$	—		$	34,779

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2014
Operating revenues (a)	$	409,374	$	103,330	$	552	$	—		$	513,256
Intersegment revenues	215		3,766		—		(3,981		)	—
Total revenues	$	409,589	$	107,096	$	552	$	(3,981	)	$	513,256
Net income	$	26,865	$	7,568	$	1,824	$	—		$	36,257

^(a)  Operating revenues include $78 million and $63 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014, respectively.

^(b)  Includes a net of tax charge related to the Monticello LCM/EPU project.  See Note 5.

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	$ 0	$ 0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss			100,000	100,000
Other Derivative Instruments | Natural Gas Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities				700,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)			$ (1,000,000)	$ (500,000)

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Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2015

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 six months ended June 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
Accumulated other comprehensive loss at April 1	$	(266	)	$	(343	)
Losses reclassified from net accumulated other comprehensive loss	19			19
Net current period other comprehensive income	19			19
Accumulated other comprehensive loss at June 30	$	(247	)	$	(324	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(285	)	$	(361	)
Losses reclassified from net accumulated other comprehensive loss	38			37
Net current period other comprehensive income	38			37
Accumulated other comprehensive loss at June 30	$	(247	)	$	(324	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	31		(a)	$	31		(a)
Total, pre-tax	31				31
Tax benefit	(12		)		(12		)
Total amounts reclassified, net of tax	$	19			$	19

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	63		(a)	$	62		(a)
Total, pre-tax	63				62
Tax benefit	(25		)		(25		)
Total amounts reclassified, net of tax	$	38			$	37

^(a)  Included in interest charges.

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Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accounts Receivable, Net
Accounts receivable	$ 57,894	$ 66,217
Less allowance for bad debts	(4,605)	(5,821)
Accounts receivable, net	$ 53,289	$ 60,396

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Jun. 30, 2015	Dec. 31, 2014
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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Selected Balance Sheet Data, Inventory (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 16,989	$ 24,685
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	6,914	6,494
Fuel
Public Utilities, Inventory [Line Items]
Inventories	6,753	6,654
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 3,322	$ 11,537

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Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility		Jun. 30, 2015 USD ($)
Line of Credit Facility [Line Items]
Credit Facility	[1]	$ 150,000,000
Drawn	[2]	0
Available		150,000,000
Direct advances on the credit facility outstanding		$ 0

[1] This credit facility expires in October 2019.

[2] Includes outstanding commercial paper.

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating revenues
Electric	$ 199,621	$ 198,277	$ 409,905	$ 409,374
Natural gas	16,889	29,539	80,185	103,330
Other	303	298	683	552
Total operating revenues	216,813	228,114	490,773	513,256
Operating expenses
Electric fuel and purchased power, non-affiliates	1,159	2,684	2,442	9,180
Purchased power, affiliates	104,413	104,532	216,245	216,458
Cost of natural gas sold and transported	8,120	19,194	50,558	70,336
Operating and maintenance expenses	45,661	48,433	87,834	92,664
Conservation program expenses	2,989	3,015	5,844	5,687
Depreciation and amortization	22,528	19,874	43,889	39,181
Taxes (other than income taxes)	6,874	6,652	14,106	13,449
Loss on Monticello life cycle management/extended power uprate project	0	0	5,237	0
Total operating expenses	191,744	204,384	426,155	446,955
Operating income	25,069	23,730	64,618	66,301
Other income, net	35	(70)	284	54
Allowance for funds used during construction — equity	1,778	1,767	3,997	3,339
Interest charges and financing costs
Interest charges — includes other financing costs of $410, $377, $812 and $751, respectively	7,771	6,968	15,527	13,835
Allowance for funds used during construction — debt	(864)	(850)	(1,934)	(1,608)
Total interest charges and financing costs	6,907	6,118	13,593	12,227
Income before income taxes	19,975	19,309	55,306	57,467
Income taxes	7,463	7,287	20,527	21,210
Net income	$ 12,512	$ 12,022	$ 34,779	$ 36,257

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Prepayments and other		$ 3,966	$ 6,918
Other Liabilities, Current		22,170	19,923
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Fair Value Measured on a Recurring Basis | Fair Value Total
Derivatives, Fair Value [Line Items]
Prepayments and other			6,900
Other Liabilities, Current		22,200
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[2]	(3)
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Other Current Assets | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	52	[1]
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[1]	45
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		45
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3	52
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		48
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		48
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3	52
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		48
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		48
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[2]	(3)	$ 0
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]	(3)
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]	$ (3)

[1] Included in other current liabilities balance of $22.2 million at June 30, 2015 and prepayments and other assets balance of $6.9 million at Dec. 31, 2014, in the consolidated balance sheets.

[2] 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 Dec. 31, 2014. 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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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Operating activities
Net income	$ 34,779	$ 36,257
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	44,539	39,754
Deferred income taxes	20,219	16,877
Amortization of investment tax credits	(264)	(337)
Allowance for equity funds used during construction	(3,997)	(3,339)
Loss on Monticello life cycle management/extended power uprate project	5,237	0
Net derivative losses	586	108
Changes in operating assets and liabilities:
Accounts receivable	7,107	2,105
Accrued unbilled revenues	13,636	10,460
Inventories	7,696	2,672
Other current assets	6,876	3,680
Accounts payable	8,058	(3,981)
Net regulatory assets and liabilities	(2,182)	(23,547)
Other current liabilities	3,222	(22)
Pension and other employee benefit obligations	(4,403)	(7,378)
Change in other noncurrent assets	(8)	101
Change in other noncurrent liabilities	412	872
Net cash provided by operating activities	141,513	74,282
Investing activities
Utility capital/construction expenditures	(150,443)	(124,624)
Allowance for equity funds used during construction	3,997	3,339
Other, net	(37)	8
Net cash used in investing activities	(146,483)	(121,277)
Financing activities
Proceeds from short-term borrowings, net	(78,000)	(57,000)
Proceeds from notes payable to affiliate	0	30
Proceeds from Issuance of Long-term Debt	98,375	98,926
Repayments of long-term debt	(25)	(36)
Capital contributions from parent	29,638	20,479
Dividends paid to parent	(28,272)	(16,089)
Net cash provided by financing activities	21,716	46,310
Net change in cash and cash equivalents	16,746	(685)
Cash and cash equivalents at beginning of period	1,285	1,349
Cash and cash equivalents at end of period	18,031	664
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(13,001)	(11,516)
Cash received (paid) for income taxes, net	6,993	(359)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 13	$ 16,844

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Rate Matters Rate Matters (Details) $ in Thousands		1 Months Ended						3 Months Ended			6 Months Ended		12 Months Ended
	May. 29, 2015 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015	Jan. 31, 2015	Nov. 30, 2014	Jun. 30, 2014	Nov. 30, 2013	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($) MW	Jun. 30, 2014 USD ($)	Dec. 31, 2014 USD ($)
Public Utilities, General Disclosures [Line Items]
Loss on Monticello life cycle management/extended power uprate project								$ 0		$ 0	$ 5,237	$ 0
FERC Proceeding, MISO ROE Complaint [Member] | Federal Energy Regulatory Commission (FERC)
Public Utilities, General Disclosures [Line Items]
Public Utilities, number of steps required for newly adopted ROE discounted cash flow methodology						2
NSP-Minnesota | Nuclear Project Prudency Investigation
Public Utilities, General Disclosures [Line Items]
Nuclear project expenditures, Amount											665,000
Total capitalized nuclear project costs											748,000
Initial estimated nuclear project expenditures											$ 320,000
NSP-Minnesota | Nuclear Project Prudency Investigation | Minnesota Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Amount of recoverable investment, with return		$ 415,000
Amount of recoverable investment, without a return		$ 333,000
Public Utilities, Percentage of investment considered used and useful		50.00%
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity charged to customers through transmission formula rates							12.38%
Public Utilities, maximum equity capital structure percentage allowed per the complaint							50.00%
Public Utilities, ROE applicable to transmission formula rates in the MISO region, lower bound, percentage				8.67%
Public Utilities, ROE applicable to transmission formula rates in the MISO region, upper bound, percentage				9.54%
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties			8.67%				9.15%
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties			50
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | Federal Energy Regulatory Commission (FERC)
Public Utilities, General Disclosures [Line Items]
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties					50
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | FERC Staff [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties				8.68%
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | MISO TOs [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE applicable to transmission formula rates in the MISO region, lower bound, percentage				10.80%
Xcel Energy Inc. | Nuclear Project Prudency Investigation
Public Utilities, General Disclosures [Line Items]
Loss on Monticello life cycle management/extended power uprate project									$ 129,000
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Electric Rates 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 27,400
Public Utilities, Requested Rate Increase (Decrease), Percentage	3.90%
Public Utilities, Requested Rate Base, Amount	$ 1,200,000
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 5,900
Public Utilities, Requested Rate Increase (Decrease), Percentage	5.00%
Public Utilities, Requested Rate Base, Amount	$ 111,200
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Return on Equity, Percentage	10.20%
Public Utilities, Requested Equity Capital Structure, Percentage	52.50%
NSP-Wisconsin | Nuclear Project Prudency Investigation
Public Utilities, General Disclosures [Line Items]
Loss on Monticello life cycle management/extended power uprate project									$ 5,000
Minimum | NSP-Minnesota | Nuclear Project Prudency Investigation
Public Utilities, General Disclosures [Line Items]
Facility generating capacity (in MW) | MW											600
Minimum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Increase (decrease) in transmission revenue, net of expense, due to the new ROE methodology													$ (7,000)
Maximum | NSP-Minnesota | Nuclear Project Prudency Investigation
Public Utilities, General Disclosures [Line Items]
Facility generating capacity (in MW) | MW											671
Maximum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Increase (decrease) in transmission revenue, net of expense, due to the new ROE methodology													$ (9,000)

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Selected Balance Sheet Data (Tables)

6 Months Ended

Jun. 30, 2015

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

^[1]

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Accounts receivable, net (a)
Accounts receivable	$	57,894		$	66,217
Less allowance for bad debts	(4,605		)	(5,821		)
	$	53,289		$	60,396

Inventories

(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	6,914	$	6,494
Fuel	6,753		6,654
Natural gas	3,322		11,537
	$	16,989	$	24,685

Property, Plant and Equipment, Net

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	2,178,038		$	2,061,669
Natural gas plant	259,820			255,465
Common and other property	125,424			125,938
Construction work in progress	218,777			231,413
Total property, plant and equipment	2,782,059			2,674,485
Less accumulated depreciation	(1,029,656		)	(1,000,204		)
	$	1,752,403		$	1,674,281

[1] Accounts receivable, net includes an immaterial amount due from affiliates as of June 30, 2015 and Dec. 31, 2014, respectively.

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Commitments and Contingencies, Guarantees and Indemnifications (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Guarantor Obligations [Line Items]
Assets Held As Collateral	$ 0	$ 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	$ 100,000	$ 200,000

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Guarantees Issued and Outstanding

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

(Millions of Dollars)	June 30, 2015		Dec. 31, 2014
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.1		0.2

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 18,031	$ 1,285
Accounts receivable, net	53,289	60,396
Accrued unbilled revenues	39,931	53,567
Inventories	16,989	24,685
Regulatory assets	12,919	20,036
Prepaid taxes	24,653	28,628
Deferred income taxes	14,671	8,201
Prepayments and other	3,966	6,918
Total current assets	184,449	203,716
Property, plant and equipment, net	1,752,403	1,674,281
Other assets
Regulatory assets	277,021	280,693
Other investments	3,855	3,818
Other	5,248	4,612
Total other assets	286,124	289,123
Total assets	2,222,976	2,167,120
Current liabilities
Current portion of long-term debt	1,210	1,235
Short-term debt	0	78,000
Notes payable to affiliates	500	500
Accounts payable	32,597	61,530
Accounts payable to affiliates	28,260	26,524
Dividends payable to parent	11,993	14,957
Regulatory liabilities	9,561	16,940
Environmental liabilities	23,429	29,116
Other	22,170	19,923
Total current liabilities	129,720	248,725
Deferred credits and other liabilities
Deferred income taxes	376,867	348,180
Deferred investment tax credits	8,824	9,089
Regulatory liabilities	138,054	132,674
Environmental liabilities	85,281	78,620
Customer advances	18,213	17,623
Pension and employee benefit obligations	46,864	51,313
Other	16,004	16,151
Total deferred credits and other liabilities	$ 690,107	$ 653,650
Commitments and contingencies
Capitalization
Long-term debt	$ 666,313	$ 567,056
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively	93,300	93,300
Additional paid in capital	351,914	322,276
Retained earnings	291,869	282,398
Accumulated other comprehensive loss	(247)	(285)
Total common stockholder’s equity	736,836	697,689
Total liabilities and equity	$ 2,222,976	$ 2,167,120

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Interest charges and financing costs
Other financing costs	$ 410	$ 377	$ 812	$ 751

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Fair Value of Financial Assets and Liabilities

6 Months Ended

Jun. 30, 2015

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 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 for trading purposes and 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 June 30, 2015, 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, including forecasted amounts for unsettled hedges, as applicable.

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, as well as for trading purposes. This could include the purchase or sale of natural gas to generate electric energy and natural gas for resale.

The following table details the gross notional amounts of commodity options at June 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands)(a)(b)	June 30, 2015	Dec. 31, 2014
Million British thermal units of natural gas	1,223	18

^(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.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — There were immaterial pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings during the three months ended June 30, 2015 and 2014, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the six months ended June 30, 2015 and 2014.

During the three months and six months ended June 30, 2015, changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses recognized as regulatory assets and liabilities. For the three and six months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses and net gains of $0.7 million, respectively, 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 gains of $1.0 million and $0.5 million were recognized for the six months ended June 30, 2015 and 2014, respectively, 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. There were immaterial natural gas commodity derivatives settlement losses recognized during the three months ended June 30, 2015 and 2014, respectively.

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations—NSP-Wisconsin continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-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 unsettled 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.

Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis:

	June 30, 2015
	Fair Value						Fair Value Total		Counterparty Netting(a)			Total(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3
Current derivative assets
Natural gas commodity	$	—	$	3	$	—	$	3	$	(3	)	$	—
Total current derivative assets	$	—	$	3	$	—	$	3	$	(3	)	$	—
Current derivative liabilities
Natural gas commodity	$	—	$	48	$	—	$	48	$	(3	)	$	45
Total current derivative liabilities	$	—	$	48	$	—	$	48	$	(3	)	$	45

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(a)		Total(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3
Current derivative assets
Natural gas commodity	$	—	$	52	$	—	$	52	$	—	$	52

^(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 Dec. 31, 2014.  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 liabilities balance of $22.2 million at June 30, 2015 and prepayments and other assets balance of $6.9 million at Dec. 31, 2014, in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of June 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	667,523	$	730,460	$	568,291	$	670,665

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 June 30, 2015 and Dec. 31, 2014, 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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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 03, 2015
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	Jun. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
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

XML

Other (Expense) Income, Net

6 Months Ended

Jun. 30, 2015

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

Other Income (Expense), Net

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

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2015			2014			2015			2014
Interest (expense) income	$	(9	)	$	12		$	288		$	216
Other nonoperating income	69			44			130			79
Insurance policy expense	(23		)	(124		)	(129		)	(236		)
Other nonoperating expense	(2		)	(2		)	(5		)	(5		)
Other income (expense), net	$	35		$	(70	)	$	284		$	54

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Comprehensive income:
Net income	$ 12,512	$ 12,022	$ 34,779	$ 36,257
Derivative instruments:
Reclassification of losses to net income, net of tax of $12 and $25 for each of the three and six months ended June 30, 2015 and 2014, respectively	19	19	38	37
Other comprehensive income	19	19	38	37
Comprehensive income	$ 12,531	$ 12,041	$ 34,817	$ 36,294

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Selected Balance Sheet Data

6 Months Ended

Jun. 30, 2015

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Accounts receivable, net (a)
Accounts receivable	$	57,894		$	66,217
Less allowance for bad debts	(4,605		)	(5,821		)
	$	53,289		$	60,396

(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	6,914	$	6,494
Fuel	6,753		6,654
Natural gas	3,322		11,537
	$	16,989	$	24,685

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	2,178,038		$	2,061,669
Natural gas plant	259,820			255,465
Common and other property	125,424			125,938
Construction work in progress	218,777			231,413
Total property, plant and equipment	2,782,059			2,674,485
Less accumulated depreciation	(1,029,656		)	(1,000,204		)
	$	1,752,403		$	1,674,281

^(a)  Accounts receivable, net includes an immaterial amount due from affiliates as of June 30, 2015 and Dec. 31, 2014, respectively.

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Accounting Pronouncements

6 Months Ended

Jun. 30, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2015-02 on its consolidated financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, NSP-Wisconsin does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (Accounting Standards Update (ASU) No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, NSP-Wisconsin does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	June 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	2.4		2.9
Total unrecognized tax benefit	$	2.6	$	3.0

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)	June 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(0.7	)	$	(0.9	)

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Segment Information

6 Months Ended

Jun. 30, 2015

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, transmits and distributes electricity primarily in portions of Wisconsin and Michigan. 

• NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas primarily 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 operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2015
Operating revenues (a)	$	199,621	$	16,889		$	303		$	—		$	216,813
Intersegment revenues	98		73			—			(171		)	—
Total revenues	$	199,719	$	16,962		$	303		$	(171	)	$	216,813
Net income (loss)	$	13,787	$	(1,074	)	$	(201	)	$	—		$	12,512

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2014
Operating revenues (a)	$	198,277	$	29,539		$	298	$	—		$	228,114
Intersegment revenues	123		849			—		(972		)	—
Total revenues	$	198,400	$	30,388		$	298	$	(972	)	$	228,114
Net income (loss)	$	11,799	$	(141	)	$	364	$	—		$	12,022

^(a)  Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014.

(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2015
Operating revenues (a)	$	409,905		$	80,185	$	683		$	—		$	490,773
Intersegment revenues	207			298		—			(505		)	—
Total revenues	$	410,112		$	80,483	$	683		$	(505	)	$	490,773
Net income (loss)	$	29,301	(b)	$	5,707	$	(229	)	$	—		$	34,779

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2014
Operating revenues (a)	$	409,374	$	103,330	$	552	$	—		$	513,256
Intersegment revenues	215		3,766		—		(3,981		)	—
Total revenues	$	409,589	$	107,096	$	552	$	(3,981	)	$	513,256
Net income	$	26,865	$	7,568	$	1,824	$	—		$	36,257

^(a)  Operating revenues include $78 million and $63 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014, respectively.

^(b)  Includes a net of tax charge related to the Monticello LCM/EPU project.  See Note 5.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except to the extent noted below and in Note 5, 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, 2014 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 its exposure 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)	June 30, 2015		Dec. 31, 2014
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.1		0.2

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. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.

In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, 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, 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. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. Demolition activities occurred at the Ashland site in 2013. Soil, including excavation and treatment, as well as containment wall remedies were completed in early 2015. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and preliminary activities, including the installation of ground wells, have commenced at the site. Construction on the groundwater treatment plant is anticipated to commence in fall 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $57 million, of which approximately $35 million has already been spent. 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.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. It is NSP-Wisconsin’s view that the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy 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 November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent for the Wet Dredge pilot study with the EPA.

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 took place in May 2015. A judicial decision is expected in the third quarter of 2015. A final settlement has been reached between NSP-Wisconsin, along with the EPA, and two of the PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”) resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. NSP-Wisconsin also has entered a second private party settlement agreement with LE Myers Co. Under the agreements, the Railroad PRPs contributed $10.5 million and LE Myers Co. contributed $5.4 million to the costs of the cleanup at the Ashland site. The agreements for the Railroad PRPs and LE Myers Co. were approved by the U.S. District Court for the Western District of Wisconsin in 2015 and payment has been received. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers. Two additional PRPs remain in the case.

At June 30, 2015 and Dec. 31, 2014, NSP-Wisconsin had recorded a liability of $108.5 million and $107.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $23.2 million and $28.9 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 NSP-Wisconsin rate recovery for all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. Under the established PSCW policy, once deferred MGP remediation costs are determined by the PSCW to be prudent, utilities are allowed to recover those deferred costs in natural gas rates, typically over a four- to six-year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

The PSCW reviewed the existing MGP cost recovery policy as it applied to the Ashland site in the context of NSP-Wisconsin’s 2013 general rate case. In December 2012, 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. In a 2014 rate case decision, the PSCW continued the cost recovery treatment with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area and allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. Cost recovery will continue at the level set in the 2014 rate case though 2015.  In May 2015, NSP-Wisconsin filed its 2016 rate case, in which it requested an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million. A decision is anticipated in late 2015.

Environmental Requirements

Water

Federal Clean Water Act (CWA) Waters of the United States Rule —In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule will go into effect beginning in August 2015. NSP-Wisconsin does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO₂₎ and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Wisconsin, using an emissions trading program.

In August 2012, the United States District 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 the EPA must continue administering the Clean Air Interstate Rule pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect.

In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015.

NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO₂. NSP-Wisconsin is complying with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, NSP-Wisconsin had met the EGU MATS rule by ending use of coal at Bay Front Unit 5. On June 29, 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. NSP-Wisconsin believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

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.

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Income Taxes

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, 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 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. As of June 30, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution is uncertain.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2015, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2010. As of June 30, 2015, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	June 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	2.4		2.9
Total unrecognized tax benefit	$	2.6	$	3.0

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

(Millions of Dollars)	June 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(0.7	)	$	(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 appeals process progresses and state audits resume. As the IRS appeals process moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014.

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Rate Matters Rate Matters (Notes)

6 Months Ended

Jun. 30, 2015

Public Utilities, General Disclosures [Abstract]

Public Utilities Disclosure [Text Block]

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, 2014 and in Note 5 to NSP-Wisconsin’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, 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 2016 Electric and Gas Rate Case — On May 29, 2015, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested an overall increase in annual electric rates of $27.4 million, or 3.9 percent, and an increase in natural gas rates of $5.9 million, or 5.0 percent.

The rate filing is based on a 2016 forecast test year, a return on equity (ROE) of 10.2 percent, an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility.

Key dates in the procedural schedule are as follows:

• Staff and Intervenor Direct Testimony — Oct. 1, 2015;

• Rebuttal Testimony — Oct. 19, 2015;

• Sur-Rebuttal Testimony — Oct. 27, 2015;

• Technical Hearing — Oct. 29, 2015;

• Initial Brief — Nov. 12, 2015;

• Reply Brief — Nov. 19, 2015; and

• A PSCW decision is anticipated in December 2015.

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

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello life cycle management (LCM)/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW). Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used and useful for 2014.  As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaint/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.

In June 2014, the FERC issued an order adopting a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

The FERC set the ROE complaint against the MISO TOs for settlement and hearing procedures. The FERC directed parties to apply the new ROE methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. The settlement procedures were unsuccessful. In January 2015, the ROE complaint was set for full hearing procedures.

The complainants and intervenors filed testimony recommending an ROE between 8.67 percent and 9.54 percent. The FERC staff recommended an ROE of 8.68 percent. The MISO TOs recommended an ROE not less than 10.8 percent. A hearing is scheduled for August 2015, with an administrative law judge (ALJ) initial decision to be issued by November 2015 and a FERC order issued no earlier than 2016.

In November 2014, certain MISO TOs filed a request for FERC approval of a 50 basis point RTO membership ROE adder, with collection deferred until resolution of the ROE complaint. In January 2015, the FERC approved the ROE adder, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology.

In February 2015, an intervenor in the November 2013 ROE complaint filed a second complaint proposing to reduce the MISO region ROE to 8.67 percent, prior to any 50 basis point RTO adder. In June 2015, the FERC set the second ROE complaint for a hearing process, establishing a Feb. 12, 2015 refund effective date. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. The FERC decision would continue the ROE refund obligation initiated under the November 2013 complaint through May 2016. On July 20, 2015, the MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints involving the same issue with consecutive refund periods, arguing this ruling is contrary to the governing statute. FERC action on the rehearing request is pending.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of June 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System.

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Borrowings and Other Financing Instruments

6 Months Ended

Jun. 30, 2015

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 June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	150		$	150
Amount outstanding at period end	—			78
Average amount outstanding	74			46
Maximum amount outstanding	92			101
Weighted average interest rate, computed on a daily basis	0.43		%	0.27		%
Weighted average interest rate at period end	N/A			0.55

Letters of Credit— NSP-Wisconsin uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2015 and Dec. 31, 2014, 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 June 30, 2015, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150	$	—	$	150

^(a)  This credit facility expires in October 2019.

^(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 June 30, 2015 and Dec. 31, 2014.

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)	June 30, 2015			Dec. 31, 2014
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate at period end	0.56		%	0.51		%

Long-Term Borrowings

In June, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024.

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Income Taxes (Details) - USD ($)	3 Months Ended	6 Months Ended
	Sep. 30, 2012	Jun. 30, 2015	Dec. 31, 2014
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions		$ 200,000	$ 100,000
Unrecognized tax benefit — Temporary tax positions		2,400,000	2,900,000
Total unrecognized tax benefit		2,600,000	3,000,000
NOL and tax credit carryforwards		(700,000)	(900,000)
Amounts accrued for penalties related to unrecognized tax benefits		$ 0	$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Earliest year subject to examination		2009
Year(s) under examination	2010 and 2011
Year of carryback claim under examination	2009
Potential Tax Adjustments		$ 12,000,000
State Jurisdiction (Wisconsin)
Tax Audits [Abstract]
Earliest year subject to examination		2010

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Other Comprehensive Income

6 Months Ended

Jun. 30, 2015

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
Accumulated other comprehensive loss at April 1	$	(266	)	$	(343	)
Losses reclassified from net accumulated other comprehensive loss	19			19
Net current period other comprehensive income	19			19
Accumulated other comprehensive loss at June 30	$	(247	)	$	(324	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(285	)	$	(361	)
Losses reclassified from net accumulated other comprehensive loss	38			37
Net current period other comprehensive income	38			37
Accumulated other comprehensive loss at June 30	$	(247	)	$	(324	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	31		(a)	$	31		(a)
Total, pre-tax	31				31
Tax benefit	(12		)		(12		)
Total amounts reclassified, net of tax	$	19			$	19

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	63		(a)	$	62		(a)
Total, pre-tax	63				62
Tax benefit	(25		)		(25		)
Total amounts reclassified, net of tax	$	38			$	37

^(a)  Included in interest charges.

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Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

The following table details the gross notional amounts of commodity options at June 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands)(a)(b)	June 30, 2015	Dec. 31, 2014
Million British thermal units of natural gas	1,223	18

^(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.

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

Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis:

	June 30, 2015
	Fair Value						Fair Value Total		Counterparty Netting(a)			Total(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3
Current derivative assets
Natural gas commodity	$	—	$	3	$	—	$	3	$	(3	)	$	—
Total current derivative assets	$	—	$	3	$	—	$	3	$	(3	)	$	—
Current derivative liabilities
Natural gas commodity	$	—	$	48	$	—	$	48	$	(3	)	$	45
Total current derivative liabilities	$	—	$	48	$	—	$	48	$	(3	)	$	45

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(a)		Total(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3
Current derivative assets
Natural gas commodity	$	—	$	52	$	—	$	52	$	—	$	52

^(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 Dec. 31, 2014.  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 liabilities balance of $22.2 million at June 30, 2015 and prepayments and other assets balance of $6.9 million at Dec. 31, 2014, in the consolidated balance sheets.

Carrying Amount and Fair Value of Long-term Debt

As of June 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	667,523	$	730,460	$	568,291	$	670,665

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2015 USD ($) Plan	Jun. 30, 2015 USD ($)	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2014 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 1,190	$ 1,132	$ 2,380	$ 2,264
Interest cost		1,630	1,814	3,260	3,628
Expected return on plan assets		(2,371)	(2,410)	(4,742)	(4,821)
Amortization of prior service cost (credit)		28	28	56	56
Amortization of net loss		1,701	1,654	3,402	3,308
Net benefit cost recognized for financial reporting		2,178	2,218	4,356	4,435
Total contributions to the pension plans during the period	$ 4,900
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		7	8	14	17
Interest cost		163	197	326	395
Expected return on plan assets		(7)	(13)	(15)	(26)
Amortization of prior service cost (credit)		(88)	(87)	(176)	(175)
Amortization of net loss		114	166	228	333
Net benefit cost recognized for financial reporting		$ 189	$ 271	$ 377	$ 544
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to the pension plans during the period	$ 90,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4

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Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangement and Other Short-Term Borrowings (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Notes Payable To Affiliates
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Weighted average interest rate at period end (percentage)	0.56%	0.51%

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative instruments:
Reclassification of losses to net income, net of tax	$ 12	$ 12	$ 25	$ 25

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2015

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, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Other (Expense) Income, Net (Tables)

6 Months Ended

Jun. 30, 2015

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

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

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2015			2014			2015			2014
Interest (expense) income	$	(9	)	$	12		$	288		$	216
Other nonoperating income	69			44			130			79
Insurance policy expense	(23		)	(124		)	(129		)	(236		)
Other nonoperating expense	(2		)	(2		)	(5		)	(5		)
Other income (expense), net	$	35		$	(70	)	$	284		$	54

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Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 78,000
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	150,000	150,000
Amount outstanding at period end	0	78,000
Average amount outstanding	74,000	46,000
Maximum amount outstanding	$ 92,000	$ 101,000
Weighted average interest rate, computed on a daily basis (percentage)	0.43%	0.27%
Weighted average interest rate at period end (percentage)		0.55%

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Benefit Plans and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2015

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 June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,190		$	1,132		$	7		$	8
Interest cost	1,630			1,814			163			197
Expected return on plan assets	(2,371		)	(2,410		)	(7		)	(13		)
Amortization of prior service cost (credit)	28			28			(88		)	(87		)
Amortization of net loss	1,701			1,654			114			166
Net benefit cost recognized for financial reporting	$	2,178		$	2,218		$	189		$	271

	Six Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,380		$	2,264		$	14		$	17
Interest cost	3,260			3,628			326			395
Expected return on plan assets	(4,742		)	(4,821		)	(15		)	(26		)
Amortization of prior service cost (credit)	56			56			(176		)	(175		)
Amortization of net loss	3,402			3,308			228			333
Net benefit cost recognized for financial reporting	$	4,356		$	4,435		$	377		$	544

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $4.9 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during 2015.