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, 2014

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. 4, 2014
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	25
PART II — OTHER INFORMATION
Item 1    —	Legal Proceedings	25
Item 1A —	Risk Factors	25
Item 4    —	Mine Safety Disclosures	25
Item 5    —	Other Information	25
Item 6    —	Exhibits	26
SIGNATURES		27

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
	2014			2013			2014			2013
Operating revenues
Electric	$	198,277		$	185,374		$	409,374		$	376,185
Natural gas	29,539			24,555			103,330			74,912
Other	298			246			552			493
Total operating revenues	228,114			210,175			513,256			451,590
Operating expenses
Electric fuel and purchased power, non-affiliates	2,684			1,862			9,180			6,032
Purchased power, affiliates	104,532			100,043			216,458			198,985
Cost of natural gas sold and transported	19,194			14,302			70,336			45,287
Operating and maintenance expenses	48,433			42,992			92,664			84,668
Conservation program expenses	3,015			3,118			5,687			6,110
Depreciation and amortization	19,874			19,051			39,181			37,906
Taxes (other than income taxes)	6,652			6,341			13,449			12,735
Total operating expenses	204,384			187,709			446,955			391,723
Operating income	23,730			22,466			66,301			59,867
Other (expense) income, net	(70		)	155			54			270
Allowance for funds used during construction — equity	1,767			780			3,339			1,726
Interest charges and financing costs
Interest charges — includes other financing costs of $377, $380, $751 and $761, respectively	6,968			6,814			13,835			13,669
Allowance for funds used during construction — debt	(850		)	(400		)	(1,608		)	(809		)
Total interest charges and financing costs	6,118			6,414			12,227			12,860
Income before income taxes	19,309			16,987			57,467			49,003
Income taxes	7,287			6,443			21,210			18,774
Net income	$	12,022		$	10,544		$	36,257		$	30,229

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
	2014		2013		2014		2013
Net income	$	12,022	$	10,544	$	36,257	$	30,229
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $12, $14, $25 and $26, respectively	19		18		37		37
Other comprehensive income	19		18		37		37
Comprehensive income	$	12,041	$	10,562	$	36,294	$	30,266

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
	2014			2013
Operating activities
Net income	$	36,257		$	30,229
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	39,754			38,476
Deferred income taxes	16,877			15,407
Amortization of investment tax credits	(337		)	(332		)
Allowance for equity funds used during construction	(3,339		)	(1,726		)
Net derivative losses (gains)	108			(344		)
Changes in operating assets and liabilities:
Accounts receivable	2,105			1,134
Accrued unbilled revenues	10,460			9,928
Inventories	2,672			1,913
Other current assets	3,680			3,442
Accounts payable	(3,981		)	(5,435		)
Net regulatory assets and liabilities	(23,547		)	(806		)
Other current liabilities	(22		)	1,670
Pension and other employee benefit obligations	(7,378		)	(10,234		)
Change in other noncurrent assets	101			329
Change in other noncurrent liabilities	872			630
Net cash provided by operating activities	74,282			84,281
Investing activities
Utility capital/construction expenditures	(124,624		)	(81,603		)
Allowance for equity funds used during construction	3,339			1,726
Other, net	8			(230		)
Net cash used in investing activities	(121,277		)	(80,107		)
Financing activities
Repayments of short-term borrowings, net	(57,000		)	(37,000		)
Proceeds from (repayments of) notes payable to affiliate	30			(80		)
Proceeds from issuance of long-term debt	98,926			—
Repayments of long-term debt	(36		)	(92		)
Capital contributions from parent	20,479			45,093
Dividends paid to parent	(16,089		)	(15,186		)
Net cash provided by (used in) financing activities	46,310			(7,265		)
Net change in cash and cash equivalents	(685		)	(3,091		)
Cash and cash equivalents at beginning of period	1,349			4,459
Cash and cash equivalents at end of period	$	664		$	1,368
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(11,516	)	$	(12,122	)
Cash (paid) received for income taxes, net	(359		)	39
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	16,844		$	9,134

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, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	664		$	1,349
Accounts receivable, net	51,684			57,674
Accounts receivable from affiliates	5,480			1,595
Accrued unbilled revenues	41,174			51,634
Inventories	18,803			21,475
Regulatory assets	24,835			14,866
Prepaid taxes	24,278			27,518
Deferred income taxes	10,975			14,953
Prepayments and other	4,356			5,056
Total current assets	182,249			196,120
Property, plant and equipment, net	1,521,829			1,442,779
Other assets
Regulatory assets	252,169			233,193
Other investments	3,643			3,650
Other	4,164			3,651
Total other assets	259,976			240,494
Total assets	$	1,964,054		$	1,879,393
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,207		$	107
Short-term debt	11,000			68,000
Notes payable to affiliates	500			470
Accounts payable	34,353			52,086
Accounts payable to affiliates	28,360			24,986
Dividends payable to parent	16,243			8,032
Regulatory liabilities	4,047			9,717
Taxes accrued	5,539			5,638
Environmental liabilities	34,380			28,785
Accrued interest	7,593			7,507
Other	8,341			9,376
Total current liabilities	151,563			214,704
Deferred credits and other liabilities
Deferred income taxes	320,334			305,139
Deferred investment tax credits	9,361			9,698
Regulatory liabilities	134,492			126,424
Environmental liabilities	80,109			79,703
Customer advances	16,678			16,008
Pension and employee benefit obligations	38,330			45,708
Other	9,362			9,237
Total deferred credits and other liabilities	608,666			591,917
Commitments and contingencies
Capitalization
Long-term debt	567,070			468,490
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively	93,300			93,300
Additional paid in capital	269,322			248,844
Retained earnings	274,457			262,499
Accumulated other comprehensive loss	(324		)	(361		)
Total common stockholder’s equity	636,755			604,282
Total liabilities and equity	$	1,964,054		$	1,879,393

See Notes to Consolidated Financial Statements

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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, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2014 and 2013; and its cash flows for the six months ended June 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2014 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, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2013. 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, 2013, filed with the SEC on Feb. 24, 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, 2013, 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 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. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	56,469		$	62,585
Less allowance for bad debts	(4,785		)	(4,911		)
	$	51,684		$	57,674

(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	6,882	$	6,437
Fuel	7,071		5,915
Natural gas	4,850		9,123
	$	18,803	$	21,475

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(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	1,984,497		$	1,913,354
Natural gas plant	239,659			236,047
Common and other property	114,063			112,886
Construction work in progress	154,992			127,954
Total property, plant and equipment	2,493,211			2,390,241
Less accumulated depreciation	(971,382		)	(947,462		)
	$	1,521,829		$	1,442,779

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but 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, 2014, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the first quarter of 2014, the state of Wisconsin completed an examination of tax years 2009 through 2011. No material adjustments were proposed for those tax years. As of June 30, 2014, 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, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.7		1.4
Total unrecognized tax benefit	$	1.8	$	1.5

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

(Millions of Dollars)	June 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(0.4	)	$	(0.4	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

8

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, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2014 or Dec. 31, 2013.

5. Rate Matters

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

NSP-Wisconsin 2015 Electric Rate Case — In May 2014, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $20.6 million, or 3.2 percent, effective Jan. 1, 2015. The request is for the limited purpose of updating 2015 electric rates to reflect anticipated increases in the production and transmission fixed charges and the fuel and purchased power components of the interchange agreement with NSP-Minnesota. No changes are being requested to the capital structure or the 10.2 percent return on equity (ROE) authorized by the PSCW in the 2014 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100 percent of the earnings above the authorized ROE would be refunded to customers.

The major cost components of the requested increase are summarized below:

(Millions of Dollars)	Request
Production and transmission fixed charges	$	28.1
Fuel and purchased power	13.9
Sub-Total	$	42.0
NSP-Minnesota transmission depreciation reserve	$	(16.2	)
Monticello extended power uprate deferral	(5.2		)
Total	$	20.6

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

• Direct Testimony (PSCW staff and intervenors) — Oct. 3, 2014;

• Rebuttal Testimony — Oct. 17, 2014;

• Surrebuttal Testimony — Oct. 24, 2014; and

• Evidentiary Hearing — Oct. 28, 2014;

A final PSCW decision is anticipated by the end of the year with final rates implemented in January 2015.

Recently Concluded Regulatory Proceedings — Michigan Public Service Commission (MPSC)

Michigan 2014 Natural Gas Rate Case — In December 2013, NSP-Wisconsin filed a request with the MPSC to increase rates for natural gas distribution service by $527,000, or 8.8 percent and implement a gas meter pressure correction factor. The filing was based on a 2014 forecast test year, a ROE of 10.4 percent, an equity ratio of 52.54 percent and a forecasted average rate base of approximately $4.7 million. The MPSC staff was the only other party to the proceeding.

In May 2014, the MPSC issued an order approving the settlement agreement reached by NSP-Wisconsin and the MPSC staff, authorizing an increase of $500,000 or 8.4 percent, based on a 10.2 percent ROE and accepting the proposed gas meter pressure correction factor. Under the terms of the settlement agreement, the rate increase will be phased in over two years, with phase one rates effective July 1, 2014 and phase two rates effective July 1, 2015.

9

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

MISO ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to 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 January 2014, Xcel Energy filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO transmission owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO transmission owners’ motion to dismiss. The complaint is pending FERC action.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth. The FERC set the issue of the appropriate long-term growth rate for further hearing procedures. The FERC could order settlement judge procedures, and if necessary a hearing, to apply the new methodology to MISO transmission owners. The new FERC ROE methodology is expected to reduce transmission revenue, net of expense, between $5 million and $7 million annually for NSP-Minnesota and NSP-Wisconsin.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 10 and 11 to the consolidated financial statements in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 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 their 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, 2014		Dec. 31, 2013
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.2		0.3

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.

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In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site. As a result of 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. The settlement reflects a cost estimate for the cleanup of the Phase I Project Area of $40 million. Demolition activities occurred at the Ashland site in 2013. The final design for the soil, including excavation and treatment, as well as containment wall remedies was submitted to the EPA in April 2014 and work commenced in May 2014. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and those activities are expected to commence in 2015. Based on these updated designs, the updated cost estimate for the cleanup of the Phase I Project Area is approximately $52 million, of which $12 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. As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations 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. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates 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. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. 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. Implementation of the pilot is anticipated in late summer or early fall of 2014.

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 is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At June 30, 2014 and Dec. 31, 2013, NSP-Wisconsin had recorded a liability of $113.3 million and $104.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $33.4 million and $25.2 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

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

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In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; (2) approval to amortize these estimated costs over a ten-year period; and (3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area. The PSCW determined the timing of the cleanup of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the cleanup in 2014 rates. However, the PSCW 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. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

Environmental Requirements

Water and waste

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule was signed by the EPA in May 2014. The timing of compliance with the requirements will vary from plant-to-plant since the new rules do not have a final compliance deadline. Since some of the compliance requirements depend on site-specific determinations by state regulators, the exact cost is somewhat uncertain. NSP-Wisconsin estimates the most likely cost for compliance is approximately $4 million and anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.

Air

EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. NSP-Wisconsin is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Wisconsin’s power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which NSP-Wisconsin operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

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GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards are not based on and would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at NSP-Wisconsin’s power plants.

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address 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. The CSAPR would set more stringent requirements than the proposed Clean Air Transport Rule. The rule would also create an emissions trading program.

In August 2012, the 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 (CAIR) 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 will now need to be considered on remand. In June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit has not yet ruled on the motion to lift the stay. Because it is not yet known how the litigation over the remaining issues will be resolved or how the D.C. Circuit will rule on the motion to lift the stay, it is not yet known what requirements may be imposed in the future, or their timing.

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

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. At June 30, 2014, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin did not have a material impact on the results of operations, financial position or cash flows.

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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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, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	150		$	150
Amount outstanding at period end	11			68
Average amount outstanding	72			20
Maximum amount outstanding	101			71
Weighted average interest rate, computed on a daily basis	0.25		%	0.31		%
Weighted average interest rate at period end	0.24			0.27

Letters of Credit— NSP-Wisconsin may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2014 and Dec. 31, 2013, 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, 2014, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

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

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the credit facility outstanding at June 30, 2014 and Dec. 31, 2013.

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, 2014			Dec. 31, 2013
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate at period end	0.43		%	0.24		%

Long-Term Borrowings

In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

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.

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

Specific valuation methods include the following:

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

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

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

Derivative Instruments Fair Value Measurements

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

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

At June 30, 2014, 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.

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, 2014 and Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	June 30, 2014	Dec. 31, 2013
Million British thermal units of natural gas	448	987

^(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.

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, 2014 and 2013, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the six months ended June 30, 2014 and 2013.

During the three months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses recognized as regulatory assets and liabilities.  For the three months ended June 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities.  During the six months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in net gains of $0.7 million, recognized as regulatory assets and liabilities. During the six months ended June 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Natural gas commodity derivatives settlement gains of $0.5 million were recognized for the six months ended June 30, 2014, 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, 2014, and three and six months ended June 30, 2013.

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NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2014 and 2013. 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 table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2014 and Dec. 31, 2013:

	June 30, 2014
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	321	$	—	$	321	$	—	$	321

	Dec. 31, 2013
	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	$	—	$	580	$	—	$	580	$	—	$	580

^(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 June 30, 2014 and Dec. 31, 2013.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  Included in prepayments and other assets balance of $4.4 million and $5.1 million at June 30, 2014 and Dec. 31, 2013, respectively, in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	568,277	$	652,505	$	468,597	$	518,269

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, 2014 and Dec. 31, 2013, 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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9. Other (Expense) Income, Net

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

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	12		$	197		$	216		$	396
Other nonoperating income	44			29			79			70
Insurance policy expense	(124		)	(69		)	(236		)	(191		)
Other nonoperating expense	(2		)	(2		)	(5		)	(5		)
Other (expense) income, net	$	(70	)	$	155		$	54		$	270

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 operating and maintenance (O&M) expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended 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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues (a)	$	185,374	$	24,555	$	246	$	—		$	210,175
Intersegment revenues	83		278		—		(361		)	—
Total revenues	$	185,457	$	24,833	$	246	$	(361	)	$	210,175
Net income	$	10,068	$	201	$	275	$	—		$	10,544

^(a)  Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013.

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(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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues (a)	$	376,185	$	74,912	$	493	$	—		$	451,590
Intersegment revenues	161		586		—		(747		)	—
Total revenues	$	376,346	$	75,498	$	493	$	(747	)	$	451,590
Net income	$	23,671	$	5,825	$	733	$	—		$	30,229

^(a)  Operating revenues include $63 million and $65 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,132		$	1,420		$	8		$	6
Interest cost	1,814			1,731			197			190
Expected return on plan assets	(2,410		)	(2,498		)	(13		)	(10		)
Amortization of prior service cost (credit)	28			104			(87		)	(88		)
Amortization of net loss	1,654			1,981			166			241
Net benefit cost recognized for financial reporting	$	2,218		$	2,738		$	271		$	339

	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,264		$	2,841		$	17		$	12
Interest cost	3,628			3,462			395			380
Expected return on plan assets	(4,821		)	(4,997		)	(26		)	(21		)
Amortization of prior service cost (credit)	56			208			(175		)	(176		)
Amortization of net loss	3,308			3,962			333			482
Net benefit cost recognized for financial reporting	$	4,435		$	5,476		$	544		$	677

In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $8.0 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during 2014.

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12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1	$	(343	)	$	(418	)
Losses reclassified from net accumulated other comprehensive loss	19			18
Net current period other comprehensive income	19			18
Accumulated other comprehensive loss at June 30	$	(324	)	$	(400	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(361	)	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	37			37
Net current period other comprehensive income	37			37
Accumulated other comprehensive loss at June 30	$	(324	)	$	(400	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	31		(a)	$	32		(a)
Total, pre-tax	31				32
Tax benefit	(12		)		(14		)
Total amounts reclassified, net of tax	$	19			$	18

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	62		(a)	$	63		(a)
Total, pre-tax	62				63
Tax benefit	(25		)		(26		)
Total amounts reclassified, net of tax	$	37			$	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).

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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 slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Wisconsin has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Wisconsin and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the Nuclear Regulatory Commission (NRC); financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2013, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2014.

Results of Operations

NSP-Wisconsin’s net income was $36.3 million for the six months ended June 30, 2014 compared with $30.2 million for the same period in 2013. Higher electric and natural gas margins, due to an electric rate increase effective in January 2014, and weather-normalized sales growth (which is adjusted against a 30-year average of actual historical weather conditions) were partially offset by higher O&M expenses.

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)	2014			2013
Electric revenues	$	409		$	376
Electric fuel and purchased power	(226		)	(205		)
Electric margin	$	183		$	171

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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)	2014 vs. 2013
Retail rate increase (Wisconsin)	$	12
Interchange agreement billings with NSP-Minnesota	8
Estimated impact of weather	5
Fuel and purchased power cost recovery	5
Retail sales growth (excluding weather impact)	3
Total increase in electric revenues	$	33

Electric Margin

(Millions of Dollars)	2014 vs. 2013
Retail rate increase (Wisconsin)	$	12
Estimated impact of weather	5
Retail sales growth (excluding weather impact)	3
Interchange agreement billings with NSP-Minnesota	(9		)
Other, net	1
Total increase in electric margin	$	12

Natural Gas Revenues and Margin

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

	Six Months Ended June 30
(Millions of Dollars)	2014			2013
Natural gas revenues	$	103		$	75
Cost of natural gas sold and transported	(70		)	(45		)
Natural gas margin	$	33		$	30

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)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	25
Estimated impact of weather	2
Other, net	1
Total increase in natural gas revenues	$	28

Natural Gas Margin

(Millions of Dollars)	2014 vs. 2013
Estimated impact of weather	$	2
Other, net	1
Total increase in natural gas margin	$	3

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Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $8.0 million, or 9.4 percent, for the six months ended June 30, 2014. The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2014 vs. 2013
Interchange agreement billings with NSP-Minnesota	$	5
Electric and gas distribution expenses	1
Other, net	2
Total increase in O&M expenses	$	8

Allowance for funds used during construction, Equity and Debt (AFUDC) — AFUDC increased $2.4 million for the six months ended June 30, 2014. The increase was primarily due to the expansion of transmission facilities.

Income Taxes — Income tax expense increased $2.4 million for the six months ended June 30, 2014. The increase in income tax expense was primarily due to higher pretax earnings in 2014. This was partially offset by increased permanent plant-related adjustments in 2014. The ETR was 36.9 percent for the six months ended June 30, 2014 compared with 38.3 percent for the same period in 2013. The lower ETR for 2014 was primarily due to increased permanent plant-related adjustments.

Public Utility Regulation

NSP System Resource Plans — In March 2013, the Minnesota Public Utilities Commission (MPUC) approved NSP-Minnesota’s Resource Plan and ordered a competitive acquisition process with the goal of adding approximately 500 megawatt (MW) of generation to the NSP System by 2019.

In May 2014, the MPUC issued its order directing NSP-Minnesota to negotiate a 100 MW solar PPA with Geronimo Energy, a natural gas, combined-cycle PPA with Calpine, a natural gas, combustion turbine PPA with Invenergy and to file these agreements later this fall. The MPUC also directed NSP-Minnesota to present its final pricing terms for its 215 MW natural gas combustion turbine, self-build option at the Black Dog site. The MPUC is expected to rule on the four options later this year.

In early 2013, NSP-Minnesota also issued a request for proposal (RFP) for wind generation and subsequently sought commission approval of the following four wind projects:

• A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota;

• A 150 MW ownership project for the Border Winds wind farm in North Dakota;

• A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and

• A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota.

In October 2013, the MPUC approved the four wind projects. In 2014, the North Dakota Public Service Commission approved the prudence of the Border Winds project as part of the rate case settlement and determined it will address the Pleasant Valley project at a later date. In June and July of 2014, NSP-Minnesota finalized agreements with Renewable Energy Systems Americas, Inc. for the Pleasant Valley and Border Winds projects and anticipates both projects going into service in 2015.

In April 2014, NSP-Minnesota issued a RFP for up to 100 MWs of solar generation resources. Proposals were received in June 2014. NSP-Minnesota is evaluating such bids and plans to submit recommendations regarding selected bids with the MPUC in October 2014.

NSP-WisconsinCapX2020 Certificate of Public Convenience and Necessity (CPCN) — The PSCW issued a CPCN for the Wisconsin portion of the Hampton, Minn. to La Crosse, Wis. project in May 2012. The Wisconsin route is approximately 50 miles of new transmission line with an estimated cost of $211 million. Construction on the Wisconsin terminus of the line, the Briggs Road Substation, began in mid-2013 and construction on the Wisconsin portion of the line began in June 2014. The line is expected to go into service in 2015.

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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 CPCN for a new 345 kilovolt transmission line that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, known as the Badger Coulee line, would run between 159 and 182 miles. Updated information was provided to the PSCW in April 2014 showing an estimated project cost, including allowance for funds used during construction, of between $540 and $580 million, depending upon the route ultimately approved by the PSCW. NSP-Wisconsin’s share of the investment is estimated to be between $190 and $207 million. The cost estimates are based on a projected 2018 in-service year. In December 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.

On April 30, 2014, the PSCW determined the CPCN application was complete. The next step is an extensive regulatory review by the PSCW, the Wisconsin Department of Natural Resources and the Department of Agriculture. By statute, the PSCW has 360 days from the determination of completeness to issue a decision on the project. If approved, 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, accounting practices and certain other activities of NSP-Wisconsin, including enforcement of North American Electric Reliability Corporation (NERC) 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, 2013. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000)— In 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities to develop tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area.

The removal of a federal ROFR would eliminate rights that NSP-Wisconsin has under the MISO tariffs to build certain transmission projects within its footprint. In Order 1000, FERC instead required that the opportunity to build such projects would extend to competitive transmission developers. MISO made their initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation. Various parties appealed Order 1000 final rules to the D.C. Circuit. The date for a Court decision in the appeal is uncertain.

The FERC ruled on the initial regional compliance filings for MISO, directing further compliance changes. The FERC ruling prohibits ROFR provisions in the MISO tariff and Transmission Owners Agreement (TOA), except for consideration of state statutes. The MISO Transmission Owners filed an appeal of this decision. Initial filings to address interregional planning and cost allocation requirements with other regions were made by MISO and are pending action by the FERC.

Minnesota, North Dakota and South Dakota legislation preserves ROFR rights. Wisconsin has not developed such legislation. The FERC’s initial order on MISO’s compliance filing required MISO to remove proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project. Xcel Energy requested rehearing of this issue. The FERC has also accepted changes to MISO’s transmission cost allocation procedures that will protect the ROFR for projects needed for system reliability. MISO has proposed that the Order 1000 compliance tariffs be effective for projects approved in December 2014.

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MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature. If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region. MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to serve multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving. Certain parties appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit). In June 2013, the Seventh Circuit upheld the FERC MVP tariff orders allocating MVP project costs regionally, but remanded the FERC decision to not apply the regional charge to transmission service transactions crossing into the PJM Interconnection, LLC (PJM) RTO. U.S. Supreme Court review of the Seventh Circuit decision was requested. In March 2014, the U.S. Supreme Court denied the appeal. Appeals of the regional allocation issue have thus been exhausted. The FERC has not yet taken action on the remand of the PJM allocation issue. The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery. Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities. The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation could be significant in future periods.

NERC Critical Infrastructure Protection (CIP) Requirements — The FERC has approved version 5 of NERC’s CIP standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. NSP-Wisconsin is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In July 2014, the FERC issued a notice of proposed rulemaking (NOPR) generally proposing to adopt NERC’s proposed CIP standard related to physical security for bulk electric system facilities. However, the FERC proposed a modification to the standard that would allow certain governmental authorities, including FERC, to revise an entity’s list of critical facilities. The new standard would likely be effective in 2015. NSP-Wisconsin is currently in the process of evaluating and identifying the critical facilities impacted to better determine the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

Southwest Power Pool, Inc. (SPP) and MISO Complaints Regarding RTO Joint Operating Agreement (JOA)—SPP and MISO have a longstanding dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagree over MISO’s authority to transmit power over SPP transmission facilities between the traditional MISO region in the Midwest and the Entergy system. Several cases have been filed with the FERC by MISO and SPP. In March 2014, FERC issued an order setting all of the cases for settlement judge proceedings, or hearings if settlement fails. The Xcel Energy utilities have intervened in the various dockets, arguing that non-firm use by MISO should not be subject to SPP transmission charges. If SPP is successful in charging MISO for use of the SPP system, the NSP System would experience higher costs from MISO, which could be material, but SPS would collect revenues from SPP. The outcome of the JOA disputes, and the potential impact on Xcel Energy, are uncertain at this time. In June 2014, the FERC accepted a proposed tariff change by MISO to recover transmission charges imposed by SPP retroactive to Jan. 29, 2014, and set the issues for settlement judge and hearing procedures.

FERC Order 745 Vacated, Demand Response Compensation in Organized Wholesale Energy Markets (Order 745) — In 2011, the FERC issued a final rule requiring that demand resources participating in organized wholesale markets (such as MISO) be paid the locational marginal price for avoided energy consumption. Numerous parties objected to the rule. On appeal, the D.C. Circuit Court of Appeals vacated and remanded FERC’s order. The Court found that the order was an impermissible intrusion by the FERC into retail electric matters reserved to the states. The FERC has requested rehearing en banc (review by the entire appeals court panel)and that request remains pending. After issuance of the Court’s decision, FirstEnergy Service Company (FirstEnergy) filed a complaint requesting FERC to require PJM to remove all portions of the PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s wholesale markets. This complaint also remains pending. Neither the Court’s vacatur of Order 745 nor FirstEnergy’s complaint against PJM have material implications for NSP-Minnesota and NSP-Wisconsin at this time. However, these actions create uncertainty regarding future participation of demand resources in the MISO wholesale organized market.

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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, 2014, based on an evaluation carried out under the supervision and with the participation of NSP-Wisconsin’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Wisconsin’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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, 2013, which is incorporated herein by reference.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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Item 6 — EXHIBITS

* Indicates incorporation by reference

3.01*	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)).
4.01*	Supplemental Indenture dated as of June 1, 2014 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.30 percent First Mortgage Bonds, Series due June 15, 2024. (Exhibit 4.01 to NSP-Wisconsin’s Form 8-K dated June 23, 2014 (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, 2014 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.

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SIGNATURES

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

		Northern States Power Company (a Wisconsin corporation)
Aug. 4, 2014	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

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EX-31.01

Exhibit 31.01

CERTIFICATION

I, Mark E. Stoering, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Aug. 4, 2014

/s/ MARK E. STOERING

Mark E. Stoering

President, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Aug. 4, 2014

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Northern States Power Company, a Wisconsin Corporation (NSP-Wisconsin) on Form 10-Q for the quarter ended June 30, 2014, 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. 4, 2014

/s/ MARK E. STOERING

Mark E. Stoering

President, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

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

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

1

EX-99.01

Exhibit 99.01

NSP-Wisconsin Cautionary Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• Social attitudes regarding the utility and power industries;

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

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

• Risks associated with implementations of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in NSP-Wisconsin’s SEC filings, including “Risk Factors” in Item 1A of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2013, 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

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Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014 Greenhouse Gas New Source Performance Standard for Modified and Reconstructed Power Plants	Apr. 30, 2014 Cross-State Air Pollution Rule	Jun. 30, 2014 Capital Commitments Federal Clean Water Act Section 316 (b)
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation			$ 4
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants (in hundredths)	50.00%
Number of issues on which the D.C. Circuit overturned the CSAPR		2

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 568,277	$ 468,597
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 652,505	$ 518,269

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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, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0	$ 0
Gain (Loss) on Fair Value Hedges Recognized in Earnings	0	0	0	0
Cash Flow Hedges | Interest Rate Contract
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
Pre-tax losses reclassified into income during the period from accumulated other comprehensive loss			(100,000)	(100,000)
Other Derivative Instruments | Natural Gas Commodity Contract
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory assets and liabilities		(200,000)	700,000	(200,000)
Pre-tax gains reclassified into income during the period from regulatory assets and liabilities			$ 500,000

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Selected Balance Sheet Data, Inventory (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Public Utilities, Inventory [Line Items]
Inventories	$ 18,803	$ 21,475
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	6,882	6,437
Fuel
Public Utilities, Inventory [Line Items]
Inventories	7,071	5,915
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 4,850	$ 9,123

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2014

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, 2014		Dec. 31, 2013
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.2		0.3

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Segment Information (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Segment Reporting Information [Line Items]
Operating revenues	$ 228,114,000		$ 210,175,000		$ 513,256,000		$ 451,590,000
Net income (loss)	12,022,000		10,544,000		36,257,000		30,229,000
Affiliate electric revenue	33,000,000		33,000,000		63,000,000		65,000,000
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	198,400,000		185,457,000		409,589,000		376,346,000
Net income (loss)	11,799,000		10,068,000		26,865,000		23,671,000
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	30,388,000		24,833,000		107,096,000		75,498,000
Net income (loss)	(141,000)		201,000		7,568,000		5,825,000
All Other
Segment Reporting Information [Line Items]
Operating revenues	298,000		246,000		552,000		493,000
Net income (loss)	364,000		275,000		1,824,000		733,000
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	228,114,000	[1]	210,175,000	[1]	513,256,000	[2]	451,590,000	[2]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	198,277,000	[1]	185,374,000	[1]	409,374,000	[2]	376,185,000	[2]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	29,539,000		24,555,000		103,330,000		74,912,000
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	298,000		246,000		552,000		493,000
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(972,000)		(361,000)		(3,981,000)		(747,000)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	123,000		83,000		215,000		161,000
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	849,000		278,000		3,766,000		586,000
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0		$ 0		$ 0		$ 0

[1] Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013.

[2] Operating revenues include $63 million and $65 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

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Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013
Credit Facility [Abstract]
Credit facility	$ 150,000,000	[1]
Drawn	11,000,000	[2]
Available	139,000,000
Credit facility bank borrowings outstanding	$ 0		$ 0

[1] Credit facility expires in July 2017.

[2] Includes outstanding commercial paper.

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Commitments and Contingencies, Guarantees and Indemnifications (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
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	$ 200,000	$ 300,000

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Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period					$ (361)
Accumulated other comprehensive loss at end of period	(324)				(324)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	(19,309)		(16,987)		(57,467)		(49,003)
Tax benefit	7,287		6,443		21,210		18,774
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(343)		(418)		(361)		(437)
Losses reclassified from net accumulated other comprehensive loss	19		18		37		37
Net current period other comprehensive income	19		18		37		37
Accumulated other comprehensive loss at end of period	(324)		(400)		(324)		(400)
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		32		62		63
Tax benefit	(12)		(14)		(25)		(26)
Total, net of tax	19		18		37		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	$ 31	[1]	$ 32	[1]	$ 62	[1]	$ 63	[1]

[1] Included in interest charges.

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Prepayments and other	$ 4,356		$ 5,056
Fair Value Measured on a Recurring Basis | Other Current Assets | Natural Gas Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	321	[1]	580	[1]
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Natural Gas Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Natural Gas Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	321		580
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Natural Gas Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Fair Value Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Prepayments and other	4,400		5,100
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Natural Gas Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	321		580
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Natural Gas Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 0	[2]	$ 0	[2]

[1] Included in prepayments and other assets balance of $4.4 million and $5.1 million at June 30, 2014 and Dec. 31, 2013, respectively, 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 June 30, 2014 and Dec. 31, 2013. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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Management's Opinion

6 Months Ended

Jun. 30, 2014

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, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2014 and 2013; and its cash flows for the six months ended June 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2014 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, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2013. 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, 2013, filed with the SEC on Feb. 24, 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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Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangement and Other Short-Term Borrowings (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 470
Intercompany Borrowing Arrangement
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Weighted average interest rate at period end (in hundredths)	0.43%	0.24%

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2014

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, 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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues (a)	$	185,374	$	24,555	$	246	$	—		$	210,175
Intersegment revenues	83		278		—		(361		)	—
Total revenues	$	185,457	$	24,833	$	246	$	(361	)	$	210,175
Net income	$	10,068	$	201	$	275	$	—		$	10,544

^(a)  Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013.

(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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues (a)	$	376,185	$	74,912	$	493	$	—		$	451,590
Intersegment revenues	161		586		—		(747		)	—
Total revenues	$	376,346	$	75,498	$	493	$	(747	)	$	451,590
Net income	$	23,671	$	5,825	$	733	$	—		$	30,229

^(a)  Operating revenues include $63 million and $65 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

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Other (Expense) Income, Net (Tables)

6 Months Ended

Jun. 30, 2014

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

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

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	12		$	197		$	216		$	396
Other nonoperating income	44			29			79			70
Insurance policy expense	(124		)	(69		)	(236		)	(191		)
Other nonoperating expense	(2		)	(2		)	(5		)	(5		)
Other (expense) income, net	$	(70	)	$	155		$	54		$	270

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (First Mortgage Bonds, Series Due June 15, 2024, USD $)	1 Months Ended
	Jun. 30, 2014
First Mortgage Bonds | Series Due June 15, 2024
Debt Instrument [Line Items]
Face Amount	$ 100,000,000
Interest Rate, Stated Percentage (in hundredths)	3.30%
Maturity Date	Jun. 15, 2024

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Benefit Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,132		$	1,420		$	8		$	6
Interest cost	1,814			1,731			197			190
Expected return on plan assets	(2,410		)	(2,498		)	(13		)	(10		)
Amortization of prior service cost (credit)	28			104			(87		)	(88		)
Amortization of net loss	1,654			1,981			166			241
Net benefit cost recognized for financial reporting	$	2,218		$	2,738		$	271		$	339

	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,264		$	2,841		$	17		$	12
Interest cost	3,628			3,462			395			380
Expected return on plan assets	(4,821		)	(4,997		)	(26		)	(21		)
Amortization of prior service cost (credit)	56			208			(175		)	(176		)
Amortization of net loss	3,308			3,962			333			482
Net benefit cost recognized for financial reporting	$	4,435		$	5,476		$	544		$	677

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Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2014

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, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1	$	(343	)	$	(418	)
Losses reclassified from net accumulated other comprehensive loss	19			18
Net current period other comprehensive income	19			18
Accumulated other comprehensive loss at June 30	$	(324	)	$	(400	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(361	)	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	37			37
Net current period other comprehensive income	37			37
Accumulated other comprehensive loss at June 30	$	(324	)	$	(400	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	31		(a)	$	32		(a)
Total, pre-tax	31				32
Tax benefit	(12		)		(14		)
Total amounts reclassified, net of tax	$	19			$	18

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	62		(a)	$	63		(a)
Total, pre-tax	62				63
Tax benefit	(25		)		(26		)
Total amounts reclassified, net of tax	$	37			$	37

^(a)  Included in interest charges.

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
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, Accounts Receivable (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Accounts Receivable, Net
Accounts receivable	$ 56,469	$ 62,585
Less allowance for bad debts	(4,785)	(4,911)
Accounts receivable, net	$ 51,684	$ 57,674

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Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $)	3 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Amount outstanding at period end	$ 11,000,000	$ 68,000,000
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	150,000,000	150,000,000
Amount outstanding at period end	11,000,000	68,000,000
Average amount outstanding	72,000,000	20,000,000
Maximum amount outstanding	$ 101,000,000	$ 71,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.25%	0.31%
Weighted average interest rate at period end (in hundredths)	0.24%	0.27%

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating revenues
Electric	$ 198,277	$ 185,374	$ 409,374	$ 376,185
Natural gas	29,539	24,555	103,330	74,912
Other	298	246	552	493
Total operating revenues	228,114	210,175	513,256	451,590
Operating expenses
Electric fuel and purchased power, non-affiliates	2,684	1,862	9,180	6,032
Purchased power, affiliates	104,532	100,043	216,458	198,985
Cost of natural gas sold and transported	19,194	14,302	70,336	45,287
Operating and maintenance expenses	48,433	42,992	92,664	84,668
Conservation program expenses	3,015	3,118	5,687	6,110
Depreciation and amortization	19,874	19,051	39,181	37,906
Taxes (other than income taxes)	6,652	6,341	13,449	12,735
Total operating expenses	204,384	187,709	446,955	391,723
Operating income	23,730	22,466	66,301	59,867
Other (expense) income, net	(70)	155	54	270
Allowance for funds used during construction — equity	1,767	780	3,339	1,726
Interest charges and financing costs
Interest charges — includes other financing costs of $377, $380, $751 and $761, respectively	6,968	6,814	13,835	13,669
Allowance for funds used during construction — debt	(850)	(400)	(1,608)	(809)
Total interest charges and financing costs	6,118	6,414	12,227	12,860
Income before income taxes	19,309	16,987	57,467	49,003
Income taxes	7,287	6,443	21,210	18,774
Net income	$ 12,022	$ 10,544	$ 36,257	$ 30,229

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014 MMBTU		Dec. 31, 2013 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 Contract
Gross Notional Amounts of Commodity Options [Abstract]
Notional amount	448,000	[1],[2]	987,000	[1],[2]

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

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Operating activities
Net income	$ 36,257	$ 30,229
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	39,754	38,476
Deferred income taxes	16,877	15,407
Amortization of investment tax credits	(337)	(332)
Allowance for equity funds used during construction	(3,339)	(1,726)
Net derivative losses (gains)	108	(344)
Changes in operating assets and liabilities:
Accounts receivable	2,105	1,134
Accrued unbilled revenues	10,460	9,928
Inventories	2,672	1,913
Other current assets	3,680	3,442
Accounts payable	(3,981)	(5,435)
Net regulatory assets and liabilities	(23,547)	(806)
Other current liabilities	(22)	1,670
Pension and other employee benefit obligations	(7,378)	(10,234)
Change in other noncurrent assets	101	329
Change in other noncurrent liabilities	872	630
Net cash provided by operating activities	74,282	84,281
Investing activities
Utility capital/construction expenditures	(124,624)	(81,603)
Allowance for equity funds used during construction	3,339	1,726
Other, net	8	(230)
Net cash used in investing activities	(121,277)	(80,107)
Financing activities
Repayments of short-term borrowings, net	(57,000)	(37,000)
Proceeds from (repayments of) notes payable to affiliate	30	(80)
Proceeds from Issuance of Long-term Debt	98,926	0
Repayments of long-term debt	(36)	(92)
Capital contributions from parent	20,479	45,093
Dividends paid to parent	(16,089)	(15,186)
Net cash provided by (used in) financing activities	46,310	(7,265)
Net change in cash and cash equivalents	(685)	(3,091)
Cash and cash equivalents at beginning of period	1,349	4,459
Cash and cash equivalents at end of period	664	1,368
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(11,516)	(12,122)
Cash (paid) received for income taxes, net	(359)	39
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 16,844	$ 9,134

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Income Taxes (Details) (USD $)			3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Sep. 30, 2012 Internal Revenue Service (IRS)	Jun. 30, 2014 Internal Revenue Service (IRS)	Mar. 31, 2014 State Jurisdiction (Wisconsin)	Jun. 30, 2014 State Jurisdiction (Wisconsin)
Tax Audits [Abstract]
Year(s) no longer subject to audit as statute of limitations has expired				2008
Earliest year subject to examination				2009		2009
Year(s) under examination			2010 and 2011
Potential Tax Adjustments				$ 10,000,000
Tax year(s) for which income tax examination has been completed					2009 through 2011
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions	100,000	100,000
Unrecognized tax benefit — Temporary tax positions	1,700,000	1,400,000
Total unrecognized tax benefit	1,800,000	1,500,000
NOL and tax credit carryforwards	(400,000)	(400,000)
Amounts accrued for penalties related to unrecognized tax benefits	$ 0	$ 0

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Selected Balance Sheet Data (Tables)

6 Months Ended

Jun. 30, 2014

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	56,469		$	62,585
Less allowance for bad debts	(4,785		)	(4,911		)
	$	51,684		$	57,674

Inventories

(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	6,882	$	6,437
Fuel	7,071		5,915
Natural gas	4,850		9,123
	$	18,803	$	21,475

Property, Plant and Equipment, Net

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	1,984,497		$	1,913,354
Natural gas plant	239,659			236,047
Common and other property	114,063			112,886
Construction work in progress	154,992			127,954
Total property, plant and equipment	2,493,211			2,390,241
Less accumulated depreciation	(971,382		)	(947,462		)
	$	1,521,829		$	1,442,779

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Rate Matters Rate Matters (Details) (USD $)	1 Months Ended
	May 31, 2014 Electric Rate Case 2015 [Member] Public Service Commission of Wisconsin (PSCW) [Member]	May 31, 2014 Natural Gas Rate Case 2014 [Member] Michigan Public Service Commission (MPSC) [Member]	Dec. 31, 2013 Natural Gas Rate Case 2014 [Member] Michigan Public Service Commission (MPSC) [Member]	Jun. 30, 2014 FERC Proceeding, MISO ROE Complaint [Member] Federal Energy Regulatory Commission (FERC) [Member]	Jan. 31, 2014 FERC Proceeding, MISO ROE Complaint [Member] Federal Energy Regulatory Commission (FERC) [Member]	Nov. 30, 2013 FERC Proceeding, MISO ROE Complaint [Member] Federal Energy Regulatory Commission (FERC) [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage	3.20%		8.80%
Public Utilities, Requested Return on Equity, Percentage	10.20%		10.40%
Public Utilities, percentage of earnings above the authorized ROE that will be refunded to customers	100.00%
Public Utilities, amount requested by public utility related to production and transmission fixed charges	$ 28,100,000
Public Utilities, amount requested by public utility related to fuel and purchased power	13,900,000
Public Utilities, requested base revenue increase (decrease) excluding NSP-Minnesota depreciation reserve and Monticello EPU deferral adjustments	42,000,000
Public Utilities, Adjustment to requested rate increase (decrease) related to the NSP-Minnesota transmission depreciation reserve	(16,200,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to the Monticello EPU deferral	(5,200,000)
Public Utilities, Requested Rate Increase (Decrease), Amount	20,600,000		527,000
Public Utilities, Requested Equity Capital Structure, Percentage			52.54%
Public Utilities, Requested Rate Base, Amount			4,700,000
Public Utilities, Approved Rate Increase (Decrease), Amount		500,000
Public Utilities, Approved Rate Increase (Decrease), Percentage		8.40%
Public Utilities, Approved Return on Equity, Percentage		10.20%
Public Utilities, number of years rate case is applicable for		2 years
Public Utilities, ROE applicable to transmission formula rates in the MISO region, upper bound						12.38%
Public Utilities, ROE applicable to transmission formula rates in the MISO region, lower bound					9.15%	9.15%
Public Utilities, maximum equity capital structure percentage allowed per the complaint						50.00%
Public Utilities, number of steps required for newly adopted ROE discounted cash flow methodology				2
Public Utilities, reduction of transmission revenue, net of expense due to the new ROE methodology, lower bound				5,000,000
Public Utilities, reduction of transmission revenue, net of expense due to the new ROE methodology, upper bound				$ 7,000,000

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Rate Matters Rate Matters (Tables)

6 Months Ended

Jun. 30, 2014

Public Utilities, General Disclosures [Abstract]

NSP-Wisconsin 2015 Electric Rate Case [Table Text Block]

The major cost components of the requested increase are summarized below:

(Millions of Dollars)	Request
Production and transmission fixed charges	$	28.1
Fuel and purchased power	13.9
Sub-Total	$	42.0
NSP-Minnesota transmission depreciation reserve	$	(16.2	)
Monticello extended power uprate deferral	(5.2		)
Total	$	20.6

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 664	$ 1,349
Accounts receivable, net	51,684	57,674
Accounts receivable from affiliates	5,480	1,595
Accrued unbilled revenues	41,174	51,634
Inventories	18,803	21,475
Regulatory assets	24,835	14,866
Prepaid taxes	24,278	27,518
Deferred income taxes	10,975	14,953
Prepayments and other	4,356	5,056
Total current assets	182,249	196,120
Property, plant and equipment, net	1,521,829	1,442,779
Other assets
Regulatory assets	252,169	233,193
Other investments	3,643	3,650
Other	4,164	3,651
Total other assets	259,976	240,494
Total assets	1,964,054	1,879,393
Current liabilities
Current portion of long-term debt	1,207	107
Short-term debt	11,000	68,000
Notes payable to affiliates	500	470
Accounts payable	34,353	52,086
Accounts payable to affiliates	28,360	24,986
Dividends payable to parent	16,243	8,032
Regulatory liabilities	4,047	9,717
Taxes accrued	5,539	5,638
Environmental liabilities	34,380	28,785
Accrued interest	7,593	7,507
Other	8,341	9,376
Total current liabilities	151,563	214,704
Deferred credits and other liabilities
Deferred income taxes	320,334	305,139
Deferred investment tax credits	9,361	9,698
Regulatory liabilities	134,492	126,424
Environmental liabilities	80,109	79,703
Customer advances	16,678	16,008
Pension and employee benefit obligations	38,330	45,708
Other	9,362	9,237
Total deferred credits and other liabilities	608,666	591,917
Commitments and contingencies
Capitalization
Long-term debt	567,070	468,490
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively	93,300	93,300
Additional paid in capital	269,322	248,844
Retained earnings	274,457	262,499
Accumulated other comprehensive loss	(324)	(361)
Total common stockholder’s equity	636,755	604,282
Total liabilities and equity	$ 1,964,054	$ 1,879,393

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Interest charges and financing costs
Other financing costs	$ 377	$ 380	$ 751	$ 761

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Fair Value of Financial Assets and Liabilities

6 Months Ended

Jun. 30, 2014

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, 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, 2014, 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.

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, 2014 and Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	June 30, 2014	Dec. 31, 2013
Million British thermal units of natural gas	448	987

^(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.

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, 2014 and 2013, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the six months ended June 30, 2014 and 2013.

During the three months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses recognized as regulatory assets and liabilities.  For the three months ended June 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities.  During the six months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in net gains of $0.7 million, recognized as regulatory assets and liabilities. During the six months ended June 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Natural gas commodity derivatives settlement gains of $0.5 million were recognized for the six months ended June 30, 2014, 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, 2014, and three and six months ended June 30, 2013.

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2014 and 2013. 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 table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2014 and Dec. 31, 2013:

	June 30, 2014
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	321	$	—	$	321	$	—	$	321

	Dec. 31, 2013
	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	$	—	$	580	$	—	$	580	$	—	$	580

^(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 June 30, 2014 and Dec. 31, 2013.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  Included in prepayments and other assets balance of $4.4 million and $5.1 million at June 30, 2014 and Dec. 31, 2013, respectively, in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	568,277	$	652,505	$	468,597	$	518,269

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, 2014 and Dec. 31, 2013, 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	6 Months Ended
	Jun. 30, 2014	Aug. 04, 2014
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, 2014
Document Fiscal Year Focus	2014
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

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Other (Expense) Income, Net

6 Months Ended

Jun. 30, 2014

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

Other (Expense) Income, Net

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

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	12		$	197		$	216		$	396
Other nonoperating income	44			29			79			70
Insurance policy expense	(124		)	(69		)	(236		)	(191		)
Other nonoperating expense	(2		)	(2		)	(5		)	(5		)
Other (expense) income, net	$	(70	)	$	155		$	54		$	270

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Comprehensive income:
Net income	$ 12,022	$ 10,544	$ 36,257	$ 30,229
Derivative instruments:
Reclassification of losses to net income, net of tax of $12, $14, $25 and $26, respectively	19	18	37	37
Other comprehensive income	19	18	37	37
Comprehensive income	$ 12,041	$ 10,562	$ 36,294	$ 30,266

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Selected Balance Sheet Data

6 Months Ended

Jun. 30, 2014

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	56,469		$	62,585
Less allowance for bad debts	(4,785		)	(4,911		)
	$	51,684		$	57,674

(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	6,882	$	6,437
Fuel	7,071		5,915
Natural gas	4,850		9,123
	$	18,803	$	21,475

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	1,984,497		$	1,913,354
Natural gas plant	239,659			236,047
Common and other property	114,063			112,886
Construction work in progress	154,992			127,954
Total property, plant and equipment	2,493,211			2,390,241
Less accumulated depreciation	(971,382		)	(947,462		)
	$	1,521,829		$	1,442,779

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Accounting Pronouncements

6 Months Ended

Jun. 30, 2014

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 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. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2014

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, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.7		1.4
Total unrecognized tax benefit	$	1.8	$	1.5

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, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(0.4	)	$	(0.4	)

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Segment Information

6 Months Ended

Jun. 30, 2014

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 operating and maintenance (O&M) expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended 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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues (a)	$	185,374	$	24,555	$	246	$	—		$	210,175
Intersegment revenues	83		278		—		(361		)	—
Total revenues	$	185,457	$	24,833	$	246	$	(361	)	$	210,175
Net income	$	10,068	$	201	$	275	$	—		$	10,544

^(a)  Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013.

(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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues (a)	$	376,185	$	74,912	$	493	$	—		$	451,590
Intersegment revenues	161		586		—		(747		)	—
Total revenues	$	376,346	$	75,498	$	493	$	(747	)	$	451,590
Net income	$	23,671	$	5,825	$	733	$	—		$	30,229

^(a)  Operating revenues include $63 million and $65 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 10 and 11 to the consolidated financial statements in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 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 their 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, 2014		Dec. 31, 2013
Guarantees issued and outstanding	$	1.0	$	1.0
Current exposure under these guarantees	0.2		0.3

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. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site. As a result of 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. The settlement reflects a cost estimate for the cleanup of the Phase I Project Area of $40 million. Demolition activities occurred at the Ashland site in 2013. The final design for the soil, including excavation and treatment, as well as containment wall remedies was submitted to the EPA in April 2014 and work commenced in May 2014. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and those activities are expected to commence in 2015. Based on these updated designs, the updated cost estimate for the cleanup of the Phase I Project Area is approximately $52 million, of which $12 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. As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations 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. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates 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. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. 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. Implementation of the pilot is anticipated in late summer or early fall of 2014.

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 is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At June 30, 2014 and Dec. 31, 2013, NSP-Wisconsin had recorded a liability of $113.3 million and $104.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $33.4 million and $25.2 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

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

In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; (2) approval to amortize these estimated costs over a ten-year period; and (3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area. The PSCW determined the timing of the cleanup of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the cleanup in 2014 rates. However, the PSCW 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. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

Environmental Requirements

Water and waste

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule was signed by the EPA in May 2014. The timing of compliance with the requirements will vary from plant-to-plant since the new rules do not have a final compliance deadline. Since some of the compliance requirements depend on site-specific determinations by state regulators, the exact cost is somewhat uncertain. NSP-Wisconsin estimates the most likely cost for compliance is approximately $4 million and anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.

Air

EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. NSP-Wisconsin is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Wisconsin’s power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which NSP-Wisconsin operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards are not based on and would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at NSP-Wisconsin’s power plants.

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address 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. The CSAPR would set more stringent requirements than the proposed Clean Air Transport Rule. The rule would also create an emissions trading program.

In August 2012, the 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 (CAIR) 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 will now need to be considered on remand. In June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit has not yet ruled on the motion to lift the stay. Because it is not yet known how the litigation over the remaining issues will be resolved or how the D.C. Circuit will rule on the motion to lift the stay, it is not yet known what requirements may be imposed in the future, or their timing.

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

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. At June 30, 2014, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin did not have a material impact on the results of operations, financial position or cash flows.

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, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but 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, 2014, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the first quarter of 2014, the state of Wisconsin completed an examination of tax years 2009 through 2011. No material adjustments were proposed for those tax years. As of June 30, 2014, 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, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.7		1.4
Total unrecognized tax benefit	$	1.8	$	1.5

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

(Millions of Dollars)	June 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(0.4	)	$	(0.4	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, 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, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2014 or Dec. 31, 2013.

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Rate Matters Rate Matters (Notes)

6 Months Ended

Jun. 30, 2014

Public Utilities, General Disclosures [Abstract]

Public Utilities Disclosure [Text Block]

Rate Matters

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

NSP-Wisconsin 2015 Electric Rate Case — In May 2014, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $20.6 million, or 3.2 percent, effective Jan. 1, 2015. The request is for the limited purpose of updating 2015 electric rates to reflect anticipated increases in the production and transmission fixed charges and the fuel and purchased power components of the interchange agreement with NSP-Minnesota. No changes are being requested to the capital structure or the 10.2 percent return on equity (ROE) authorized by the PSCW in the 2014 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100 percent of the earnings above the authorized ROE would be refunded to customers.

The major cost components of the requested increase are summarized below:

(Millions of Dollars)	Request
Production and transmission fixed charges	$	28.1
Fuel and purchased power	13.9
Sub-Total	$	42.0
NSP-Minnesota transmission depreciation reserve	$	(16.2	)
Monticello extended power uprate deferral	(5.2		)
Total	$	20.6

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

• Direct Testimony (PSCW staff and intervenors) — Oct. 3, 2014;

• Rebuttal Testimony — Oct. 17, 2014;

• Surrebuttal Testimony — Oct. 24, 2014; and

• Evidentiary Hearing — Oct. 28, 2014;

A final PSCW decision is anticipated by the end of the year with final rates implemented in January 2015.

Recently Concluded Regulatory Proceedings — Michigan Public Service Commission (MPSC)

Michigan 2014 Natural Gas Rate Case — In December 2013, NSP-Wisconsin filed a request with the MPSC to increase rates for natural gas distribution service by $527,000, or 8.8 percent and implement a gas meter pressure correction factor. The filing was based on a 2014 forecast test year, a ROE of 10.4 percent, an equity ratio of 52.54 percent and a forecasted average rate base of approximately $4.7 million. The MPSC staff was the only other party to the proceeding.

In May 2014, the MPSC issued an order approving the settlement agreement reached by NSP-Wisconsin and the MPSC staff, authorizing an increase of $500,000 or 8.4 percent, based on a 10.2 percent ROE and accepting the proposed gas meter pressure correction factor. Under the terms of the settlement agreement, the rate increase will be phased in over two years, with phase one rates effective July 1, 2014 and phase two rates effective July 1, 2015.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

MISO ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to 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 January 2014, Xcel Energy filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO transmission owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO transmission owners’ motion to dismiss. The complaint is pending FERC action.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth. The FERC set the issue of the appropriate long-term growth rate for further hearing procedures. The FERC could order settlement judge procedures, and if necessary a hearing, to apply the new methodology to MISO transmission owners. The new FERC ROE methodology is expected to reduce transmission revenue, net of expense, between $5 million and $7 million annually for NSP-Minnesota and NSP-Wisconsin.

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Borrowings and Other Financing Instruments

6 Months Ended

Jun. 30, 2014

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, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	150		$	150
Amount outstanding at period end	11			68
Average amount outstanding	72			20
Maximum amount outstanding	101			71
Weighted average interest rate, computed on a daily basis	0.25		%	0.31		%
Weighted average interest rate at period end	0.24			0.27

Letters of Credit— NSP-Wisconsin may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2014 and Dec. 31, 2013, 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, 2014, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

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

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the credit facility outstanding at June 30, 2014 and Dec. 31, 2013.

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, 2014			Dec. 31, 2013
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate at period end	0.43		%	0.24		%

Long-Term Borrowings

In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

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Selected Balance Sheet Data, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 2,493,211	$ 2,390,241
Less accumulated depreciation	(971,382)	(947,462)
Property, plant and equipment, net	1,521,829	1,442,779
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,984,497	1,913,354
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	239,659	236,047
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	114,063	112,886
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 154,992	$ 127,954

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Benefit Plans and Other Postretirement Benefits (Details) (USD $)	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2014	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 1,132,000	$ 1,420,000	$ 2,264,000	$ 2,841,000
Interest cost		1,814,000	1,731,000	3,628,000	3,462,000
Expected return on plan assets		(2,410,000)	(2,498,000)	(4,821,000)	(4,997,000)
Amortization of prior service cost (credit)		28,000	104,000	56,000	208,000
Amortization of net loss		1,654,000	1,981,000	3,308,000	3,962,000
Net benefit cost recognized for financial reporting		2,218,000	2,738,000	4,435,000	5,476,000
Total contributions to the pension plans during the period	8,000,000
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		8,000	6,000	17,000	12,000
Interest cost		197,000	190,000	395,000	380,000
Expected return on plan assets		(13,000)	(10,000)	(26,000)	(21,000)
Amortization of prior service cost (credit)		(87,000)	(88,000)	(175,000)	(176,000)
Amortization of net loss		166,000	241,000	333,000	482,000
Net benefit cost recognized for financial reporting		271,000	339,000	544,000	677,000
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to the pension plans during the period	$ 130,000,000
Number of Xcel Energy's pension plans to which contributions were made	3

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Other Comprehensive Income

6 Months Ended

Jun. 30, 2014

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, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1	$	(343	)	$	(418	)
Losses reclassified from net accumulated other comprehensive loss	19			18
Net current period other comprehensive income	19			18
Accumulated other comprehensive loss at June 30	$	(324	)	$	(400	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(361	)	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	37			37
Net current period other comprehensive income	37			37
Accumulated other comprehensive loss at June 30	$	(324	)	$	(400	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	31		(a)	$	32		(a)
Total, pre-tax	31				32
Tax benefit	(12		)		(14		)
Total amounts reclassified, net of tax	$	19			$	18

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	62		(a)	$	63		(a)
Total, pre-tax	62				63
Tax benefit	(25		)		(26		)
Total amounts reclassified, net of tax	$	37			$	37

^(a)  Included in interest charges.

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Borrowings and Other Financing Instruments (Tables)

6 Months Ended

Jun. 30, 2014

Debt Instruments [Abstract]

Committed Credit Facility Available

At June 30, 2014, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

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

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper.

Commercial Paper

Debt Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for NSP-Wisconsin was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	150		$	150
Amount outstanding at period end	11			68
Average amount outstanding	72			20
Maximum amount outstanding	101			71
Weighted average interest rate, computed on a daily basis	0.25		%	0.31		%
Weighted average interest rate at period end	0.24			0.27

Intercompany Borrowing Arrangement

Debt Instruments [Abstract]

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	June 30, 2014			Dec. 31, 2013
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate at period end	0.43		%	0.24		%

Long-Term Borrowings

In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

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Other (Expense) Income, Net (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Other Income and Expenses [Abstract]
Interest income	$ 12	$ 197	$ 216	$ 396
Other nonoperating income	44	29	79	70
Insurance policy expense	(124)	(69)	(236)	(191)
Other nonoperating expense	(2)	(2)	(5)	(5)
Other (expense) income, net	$ (70)	$ 155	$ 54	$ 270

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Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $)	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Letters of Credit [Abstract]
Terms of letters of credit (in years)	1 year
Letters of credit outstanding under credit facilities	$ 0	$ 0

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative instruments:
Reclassification of losses to net income, net of tax	$ 12	$ 14	$ 25	$ 26

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2014

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, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2014

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, 2014 and Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	June 30, 2014	Dec. 31, 2013
Million British thermal units of natural gas	448	987

^(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 table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2014 and Dec. 31, 2013:

	June 30, 2014
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	321	$	—	$	321	$	—	$	321

	Dec. 31, 2013
	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	$	—	$	580	$	—	$	580	$	—	$	580

^(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 June 30, 2014 and Dec. 31, 2013.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  Included in prepayments and other assets balance of $4.4 million and $5.1 million at June 30, 2014 and Dec. 31, 2013, respectively, in the consolidated balance sheets.

Carrying Amount and Fair Value of Long-term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	568,277	$	652,505	$	468,597	$	518,269

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Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (USD $)	6 Months Ended
	Jun. 30, 2014 Site	Dec. 31, 2013
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites, current	$ 34,380,000	$ 28,785,000
Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Number of properties included in superfund site which NSP-Wisconsin does not own	2
Liability for estimated cost of remediating sites	113,300,000	104,600,000
Liability for estimated cost of remediating sites, current	33,400,000	25,200,000
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years)	4 years
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years)	6 years
Ashland MGP Site - Phase I Project Area
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites as reflected in the settlement	40,000,000
Liability for estimated cost of remediating sites	52,000,000
Estimated amount spent on Phase I Project Area cleanup	12,000,000
Number of acres of land conveyed to the State of Wisconsin and tribal trustees (in acres)	1,390
Approved amortization period for recovery of remediation costs in natural gas rates (in years)	10 years
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths)	3.00%
Approved increase (decrease) in amortization expense granted by a regulatory body	1,100,000
Ashland MGP Site - Sediments
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Estimated cost of remediating site, low end of range	63,000,000
Estimated cost of remediating site, high end of range	$ 77,000,000
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths)	50.00%
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths)	30.00%

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Benefit Plans and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2014

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
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,132		$	1,420		$	8		$	6
Interest cost	1,814			1,731			197			190
Expected return on plan assets	(2,410		)	(2,498		)	(13		)	(10		)
Amortization of prior service cost (credit)	28			104			(87		)	(88		)
Amortization of net loss	1,654			1,981			166			241
Net benefit cost recognized for financial reporting	$	2,218		$	2,738		$	271		$	339

	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,264		$	2,841		$	17		$	12
Interest cost	3,628			3,462			395			380
Expected return on plan assets	(4,821		)	(4,997		)	(26		)	(21		)
Amortization of prior service cost (credit)	56			208			(175		)	(176		)
Amortization of net loss	3,308			3,962			333			482
Net benefit cost recognized for financial reporting	$	4,435		$	5,476		$	544		$	677

In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $8.0 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during 2014.