NORTHERN STATES POWER CO /WI/ - FORM 10-Q

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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 Sept. 30, 2014



¨	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 Nov. 3, 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	20
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 Sept. 30						Nine Months Ended Sept. 30
	2014			2013			2014			2013
Operating revenues
Electric	$	216,289		$	216,545		$	625,663		$	592,730
Natural gas	14,484			14,266			117,814			89,178
Other	273			249			825			742
Total operating revenues	231,046			231,060			744,302			682,650

Operating expenses
Electric fuel and purchased power, non-affiliates	2,707			4,968			11,887			11,000
Purchased power, affiliates	105,092			106,554			321,550			305,539
Cost of natural gas sold and transported	7,854			7,483			78,190			52,770
Operating and maintenance expenses	47,899			42,521			140,563			127,189
Conservation program expenses	3,005			3,133			8,692			9,243
Depreciation and amortization	19,940			19,359			59,121			57,265
Taxes (other than income taxes)	7,009			6,273			20,458			19,008
Total operating expenses	193,506			190,291			640,461			582,014

Operating income	37,540			40,769			103,841			100,636

Other (expense) income, net	(9		)	(61		)	45			209
Allowance for funds used during construction — equity	1,576			1,029			4,915			2,755

Interest charges and financing costs
Interest charges — includes other financing costs of $408, $389, $1,159 and $1,150, respectively	7,701			7,191			21,536			20,860
Allowance for funds used during construction — debt	(733		)	(471		)	(2,341		)	(1,280		)
Total interest charges and financing costs	6,968			6,720			19,195			19,580

Income before income taxes	32,139			35,017			89,606			84,020
Income taxes	12,109			13,004			33,319			31,778
Net income	$	20,030		$	22,013		$	56,287		$	52,242

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 Sept. 30				Nine Months Ended Sept. 30
	2014		2013		2014		2013
Net income	$	20,030	$	22,013	$	56,287	$	52,242
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $12, $12, $38 and $38, respectively	20		20		57		57
Other comprehensive income	20		20		57		57
Comprehensive income	$	20,050	$	22,033	$	56,344	$	52,299

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Nine Months Ended Sept. 30
	2014			2013
Operating activities
Net income	$	56,287		$	52,242
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	60,017			58,126
Deferred income taxes	28,691			19,491
Amortization of investment tax credits	(504		)	(500		)
Allowance for equity funds used during construction	(4,915		)	(2,755		)
Net derivative (gains)	(356		)	(658		)
Changes in operating assets and liabilities:
Accounts receivable	7,761			2,566
Accrued unbilled revenues	13,009			11,076
Inventories	(5,172		)	(3,382		)
Other current assets	11,693			9,486
Accounts payable	(9,910		)	(3,755		)
Net regulatory assets and liabilities	(35,546		)	(6,260		)
Other current liabilities	955			9,635
Pension and other employee benefit obligations	(6,882		)	(9,273		)
Change in other noncurrent assets	(46		)	260
Change in other noncurrent liabilities	1,013			1,555
Net cash provided by operating activities	116,095			137,854

Investing activities
Utility capital/construction expenditures	(194,886		)	(134,641		)
Allowance for equity funds used during construction	4,915			2,754
Other, net	(13		)	(249		)
Net cash used in investing activities	(189,984		)	(132,136		)

Financing activities
Repayments of short-term borrowings, net	(60,000		)	(28,000		)
Proceeds from (repayments of) notes payable to affiliate	30			(80		)
Proceeds from issuance of long-term debt	98,625			—
Repayments of long-term debt	(54		)	(109		)
Capital contributions from parent	68,011			42,481
Dividends paid to parent	(32,331		)	(22,943		)
Net cash provided by (used in) financing activities	74,281			(8,651		)

Net change in cash and cash equivalents	392			(2,933		)
Cash and cash equivalents at beginning of period	1,349			4,459
Cash and cash equivalents at end of period	$	1,741		$	1,526

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(17,313	)	$	(18,366	)
Cash received (paid) for income taxes, net	915			(2,127		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	28,693		$	10,347

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)



	Sept. 30, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	1,741		$	1,349
Accounts receivable, net	51,508			57,674
Accounts receivable from affiliates	—			1,595
Accrued unbilled revenues	38,625			51,634
Inventories	26,647			21,475
Regulatory assets	26,846			14,866
Prepaid taxes	17,571			27,518
Deferred income taxes	7,120			14,953
Prepayments and other	3,520			5,056
Total current assets	173,578			196,120

Property, plant and equipment, net	1,587,443			1,442,779

Other assets
Regulatory assets	256,445			233,193
Other investments	3,663			3,650
Other	4,534			3,651
Total other assets	264,642			240,494
Total assets	$	2,025,663		$	1,879,393

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,195		$	107
Short-term debt	8,000			68,000
Notes payable to affiliates	500			470
Accounts payable	49,481			52,086
Accounts payable to affiliates	19,152			24,986
Dividends payable to parent	11,486			8,032
Regulatory liabilities	10,730			9,717
Taxes accrued	3,708			5,638
Environmental liabilities	25,893			28,785
Accrued interest	8,421			7,507
Other	9,859			9,376
Total current liabilities	148,425			214,704

Deferred credits and other liabilities
Deferred income taxes	329,768			305,139
Deferred investment tax credits	9,112			9,698
Regulatory liabilities	131,996			126,424
Environmental liabilities	81,439			79,703
Customer advances	16,914			16,008
Pension and employee benefit obligations	38,827			45,708
Other	9,225			9,237
Total deferred credits and other liabilities	617,281			591,917

Commitments and contingencies
Capitalization
Long-term debt	567,106			468,490
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Sept. 30, 2014 and Dec. 31, 2013, respectively	93,300			93,300
Additional paid in capital	316,855			248,844
Retained earnings	283,000			262,499
Accumulated other comprehensive loss	(304		)	(361		)
Total common stockholder’s equity	692,851			604,282
Total liabilities and equity	$	2,025,663		$	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 Sept. 30, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2014 and 2013; and its cash flows for the nine months ended Sept. 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 Sept. 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)	Sept. 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	56,852		$	62,585
Less allowance for bad debts	(5,344		)	(4,911		)
	$	51,508		$	57,674



(Thousands of Dollars)	Sept. 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	6,892	$	6,437
Fuel	6,706		5,915
Natural gas	13,049		9,123
	$	26,647	$	21,475

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(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	2,003,119		$	1,913,354
Natural gas plant	244,244			236,047
Common and other property	115,199			112,886
Construction work in progress	210,445			127,954
Total property, plant and equipment	2,573,007			2,390,241
Less accumulated depreciation	(985,564		)	(947,462		)
	$	1,587,443		$	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 Sept. 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 Sept. 30, 2014, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2010. 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 Sept. 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)	Sept. 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)	Sept. 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(0.6	)	$	(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.

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The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2014 or Dec. 31, 2013.


5.	Rate Matters

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

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.

In October 2014, the PSCW Staff filed their direct testimony and recommended an electric rate increase of $16.1 million, or 2.5 percent. The majority of the PSCW Staff’s adjustments are related to the fuel cost forecast, and are primarily the result of more recent data than was available at the time the initial filing was prepared last spring.

In October 2014, NSP-Wisconsin, the PSCW Staff and other parties reached an agreement that resolved all contested issues in the case and accepted the PSCW staff recommendation to increase NSP-Wisconsin’s electric rates by approximately $16.1 million, effective January 2015.

The major cost components of the requested increase and the PSCW Staff recommendation are summarized below:



(Millions of Dollars)	NSP-Wisconsin Request			PSCW Staff Recommendation
Production and transmission fixed charges	$	28.1		$	26.4
Fuel and purchased power	13.9			11.1
Sub-Total	$	42.0		$	37.5

NSP-Minnesota transmission depreciation reserve	$	(16.2	)	$	(16.2	)
Monticello extended power uprate deferral	(5.2		)	(5.2		)
Total	$	20.6		$	16.1

A final PSCW decision is anticipated by the end of 2014.

Pending Regulatory Proceedings — Michigan Public Service Commission (MPSC)

Michigan 2015 Electric Rate Case — In October 2014, NSP-Wisconsin filed a request with the MPSC to increase rates for electric service by $900,000, or 6.1 percent. The filing was based on a 2015 forecast test year, a 10.3 percent ROE, an equity ratio of 52.59 percent and a forecasted average rate base of approximately $35.2 million. The primary drivers of the requested increase is continuing investment in transmission and distribution infrastructure. The filing also included a request for a $289,000, or 1.9 percent, step increase in 2016, to reflect the expiration in 2016 of certain credits that were used to offset the 2015 rate request. A prehearing conference has been scheduled for Nov. 19, 2014.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (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.

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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 complaint should be dismissed.

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.

In October 2014, the FERC upheld the determination of the long term growth rate to be used together with a short term growth rate in its new ROE methodology. The FERC separately set the ROE complaint against the MISO transmission owners for settlement judge and hearing procedures, which are expected to begin later this year. The FERC directed parties to apply this methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with the new ROE as of Sept. 30, 2014. The new FERC ROE methodology is estimated 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 its exposure to a maximum amount stated in the guarantee. The guarantee contains no recourse provisions and requires no collateral.

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



(Millions of Dollars)	Sept. 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. 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.

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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. 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 cost estimate for the cleanup of the Phase I Project Area is approximately $52 million, of which approximately $21 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. 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. It is NSP-Wisconsin’s view that the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent for the Wet Dredge pilot study with the EPA. In September 2014, the EPA granted an extension of time to perform the pilot in 2015.

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 Sept. 30, 2014 and Dec. 31, 2013, NSP-Wisconsin had recorded a liability of $106.9 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 $25.4 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 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.

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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) — Section 316(b) of 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. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. Many of the compliance requirements depend on site-specific determinations by state regulators; therefore, the exact cost is somewhat uncertain. NSP-Wisconsin estimates the likely cost for complying with impingement requirements 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 Dec. 1, 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.

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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. 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 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 (PM) 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 set more stringent requirements than the proposed Clean Air Transport Rule. The rule also creates 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 the CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit granted the EPA’s motion in October 2014. In addition, the D.C. Circuit set a briefing schedule and plans to hear arguments on the remaining issues in the case in March 2015.

NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO₂ due to cessation of coal combustion at Bay Front Unit 5. NSP-Wisconsin anticipates compliance with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not expected to have a material impact on the results of operations, financial position or cash flows.

The EPA will begin to administer the CSAPR in 2015, which will replace the CAIR. In 2014, NSP-Wisconsin expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. At Sept. 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.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where NSP-Wisconsin operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In August 2014, EPA issued its proposed designations, which did not include areas in any states in which NSP-Wisconsin operates. The EPA is expected to finalize its designation of non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.

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Legal Contingencies

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


7.	Borrowings and Other Financing Instruments

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



(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	150		$	150
Amount outstanding at period end	8			68
Average amount outstanding	7			20
Maximum amount outstanding	22			71
Weighted average interest rate, computed on a daily basis	0.24		%	0.31		%
Weighted average interest rate at period end	0.25			0.27

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



Credit Facility ^(a)		Drawn ^(b)		Available
$	150.0	$	8.0	$	142.0


^(a)	Credit facility has been amended to expire in October 2019.


^(b)	Includes outstanding commercial paper.

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

Amended Credit Agreement — On Oct. 14, 2014, NSP-Wisconsin entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an extension of maturity from July 2017 to October 2019. The borrowing limit for NSP-Wisconsin remained at $150 million. The Eurodollar borrowing margin on the line of credit ranges from 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fee, calculated on the unused portion of the line of credit, ranges from 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period, subject to majority bank group approval.

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



(Amounts in Millions, Except Interest Rates)	Sept. 30, 2014			Dec. 31, 2013
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate at period end	0.35		%	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.

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

Specific valuation methods include the following:

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

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

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

Derivative Instruments Fair Value Measurements

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

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

At Sept. 30, 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 Sept. 30, 2014 and Dec. 31, 2013:


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


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

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Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — There were immaterial pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings during the three months ended Sept. 30, 2014 and 2013, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the nine months ended Sept. 30, 2014 and 2013.

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

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

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 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 Sept. 30, 2014 and Dec. 31, 2013:



	Sept. 30, 2014
	Fair Value						Fair Value Total		Counterparty Netting ^(a)		Total ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(a)		Total ^(b)
Current derivative assets
Natural gas commodity	$	—	$	791	$	—	$	791	$	—	$	791



	Dec. 31, 2013
	Fair Value						Fair Value Total		Counterparty Netting ^(a)		Total ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(a)		Total ^(b)
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 Sept. 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 $3.5 million and $5.1 million at Sept. 30, 2014 and Dec. 31, 2013, respectively, in the consolidated balance sheets.

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Fair Value of Long-Term Debt

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



	Sept. 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	568,301	$	654,698	$	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 Sept. 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.


9.	Other (Expense) Income, Net

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



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	21		$	23		$	237		$	419
Other nonoperating income	29			38			108			108
Insurance policy expense	(56		)	(119		)	(292		)	(310		)
Other nonoperating expense	(3		)	(3		)	(8		)	(8		)
Other (expense) income, net	$	(9	)	$	(61	)	$	45		$	209


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.

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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 Sept. 30, 2014
Operating revenues ^(a)	$	216,289	$	14,484		$	273	$	—		$	231,046
Intersegment revenues	93		425			—		(518		)	—
Total revenues	$	216,382	$	14,909		$	273	$	(518	)	$	231,046
Net income (loss)	$	21,227	$	(2,003	)	$	806	$	—		$	20,030



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


^(a)	Operating revenues include $33 million and $36 million of affiliate electric revenue for the three months ended Sept. 30, 2014 and 2013, respectively.



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2014
Operating revenues ^(a)	$	625,663	$	117,814	$	825	$	—		$	744,302
Intersegment revenues	308		4,191		—		(4,499		)	—
Total revenues	$	625,971	$	122,005	$	825	$	(4,499	)	$	744,302
Net income	$	48,092	$	5,565	$	2,630	$	—		$	56,287



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


^(a)	Operating revenues include $97 million and $101 million of affiliate electric revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.

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11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost



	Three Months Ended Sept. 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	1,132		$	1,421		$	9		$	6
Interest cost	1,814			1,731			198			190
Expected return on plan assets	(2,411		)	(2,499		)	(13		)	(11		)
Amortization of prior service cost (credit)	28			104			(88		)	(88		)
Amortization of net loss	1,654			1,981			167			241
Net benefit cost recognized for financial reporting	$	2,217		$	2,738		$	273		$	338



	Nine Months Ended Sept. 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	3,396		$	4,262		$	26		$	18
Interest cost	5,442			5,193			593			570
Expected return on plan assets	(7,232		)	(7,496		)	(39		)	(32		)
Amortization of prior service cost (credit)	84			312			(263		)	(264		)
Amortization of net loss	4,962			5,943			500			723
Net benefit cost recognized for financial reporting	$	6,652		$	8,214		$	817		$	1,015

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.


12.	Other Comprehensive Income

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



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended Sept. 30, 2014			Three Months Ended Sept. 30, 2013
Accumulated other comprehensive loss at July 1	$	(324	)	$	(400	)
Losses reclassified from net accumulated other comprehensive loss	20			20
Net current period other comprehensive income	20			20
Accumulated other comprehensive loss at Sept. 30	$	(304	)	$	(380	)



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2014			Nine Months Ended Sept. 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(361	)	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	57			57
Net current period other comprehensive income	57			57
Accumulated other comprehensive loss at Sept. 30	$	(304	)	$	(380	)

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



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2014				Three Months Ended Sept. 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	32		^(a)	$	32		^(a)
Total, pre-tax	32				32
Tax benefit	(12		)		(12		)
Total amounts reclassified, net of tax	$	20			$	20



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2014				Nine Months Ended Sept. 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	95		^(a)	$	95		^(a)
Total, pre-tax	95				95
Tax benefit	(38		)		(38		)
Total amounts reclassified, net of tax	$	57			$	57


^(a)	Included in interest charges.

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

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

Financial Review

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

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Wisconsin and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Wisconsin has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Wisconsin and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the Nuclear Regulatory Commission (NRC); financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2013, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2014.

Results of Operations

NSP-Wisconsin’s net income was $56.3 million for the nine months ended Sept. 30, 2014 compared with $52.2 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 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:



	Nine Months Ended Sept. 30
(Millions of Dollars)	2014			2013
Electric revenues	$	626		$	593
Electric fuel and purchased power	(333		)	(317		)
Electric margin	$	293		$	276

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

Electric Revenues



(Millions of Dollars)	2014 vs. 2013
Retail rate increase (Wisconsin)	$	17
Interchange agreement billings with NSP-Minnesota	8
Retail sales growth, excluding weather impact	5
Fuel and purchased power cost recovery	4
Estimated impact of weather	(2		)
Other, net	1
Total increase in electric revenues	$	33

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Electric Margin



(Millions of Dollars)	2014 vs. 2013
Retail rate increase (Wisconsin)	$	17
Retail sales growth, excluding weather impact	5
Timing of fuel recovery	3
Interchange agreement billings with NSP-Minnesota	(7		)
Estimated impact of weather	(2		)
Other, net	1
Total increase in electric margin	$	17

Natural Gas Revenues and Margin

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



	Nine Months Ended Sept. 30
(Millions of Dollars)	2014			2013
Natural gas revenues	$	118		$	89
Cost of natural gas sold and transported	(78		)	(53		)
Natural gas margin	$	40		$	36

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

Natural Gas Revenues



(Millions of Dollars)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	25
Estimated impact of weather	2
Other, net	2
Total increase in natural gas revenues	$	29

Natural Gas Margin



(Millions of Dollars)	2014 vs. 2013
Estimated impact of weather	$	2
Retail sales growth, excluding weather impact	1
Other, net	1
Total increase in natural gas margin	$	4

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $13.4 million, or 10.5 percent, for the nine months ended Sept. 30, 2014. The following table summarizes the changes in O&M expenses:



(Millions of Dollars)	2014 vs. 2013
Interchange agreement billings with NSP-Minnesota	$	10
Electric and gas distribution expenses	3
Total increase in O&M expenses	$	13

Allowance for funds used during construction, Equity and Debt (AFUDC) — AFUDC increased $3.2 million for the nine months ended Sept. 30, 2014. The increase was primarily due to the expansion of transmission facilities.

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Income Taxes — Income tax expense increased $1.5 million for the nine months ended Sept. 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 37.2 percent for the nine months ended Sept. 30, 2014 compared with 37.8 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 megawatts (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 purchased power agreement (PPA) with Geronimo Energy, a natural gas, combined-cycle PPA with Calpine, and a natural gas, combustion turbine PPA with Invenergy. 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.

In September 2014, NSP-Minnesota filed an updated assessment of generating resource needs which indicates that it will have surplus generating capacity through at least 2019. NSP-Minnesota requested to postpone negotiations of the thermal PPAs until spring 2015. NSP-Minnesota also expressed reservations about the significant price differences in the solar options resulting from solar request for proposals. NSP-Minnesota suggested the MPUC consolidate its determinations regarding the amount of solar to be added to the NSP System, as well as the specific mix of PPAs that will be best for NSP-Minnesota’s customers.

In October 2014, NSP-Minnesota filed a petition with the MPUC seeking approval of two to three solar PPAs, depending on the MPUC’s determination regarding the Geronimo Energy solar PPA. The MPUC is anticipated to act on NSP-Minnesota’s recommendations in December 2014.

NSP-Minnesota’s next Resource Plan is expected to be filed with the MPUC in January 2015.

CapX2020 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.

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 based on the permitted route. 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. 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. The project is currently pending before the PSCW, with a decision expected in April 2015. 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, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In October 2014, the FERC upheld the determination of the long term growth rate to be used in its new ROE methodology. Several parties sought rehearing of the June 2014 order and therefore the new FERC policy may be subject to additional changes.

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FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued a final ruling, 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. Various parties, including the MISO Transmission Owners, filed appeals of Order 1000 with the D.C. Circuit. In August 2014, the Court denied all appeals and upheld Order 1000 in its entirety. The Court indicated, however, that challenges to removal of federal ROFR provisions from individual contracts or tariffs could be considered in individual compliance filings.

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. Subsequently, the FERC ruled on the initial regional compliance filings, directing further compliance changes. The MISO regional compliance filings remain pending further action by the FERC.

Initial filings to address Order 1000 interregional planning and cost allocation requirements with other regions were also made by MISO and are pending initial action by the FERC.

NSP System

Minnesota, North Dakota and South Dakota legislation preserves ROFR rights; however, Wisconsin does not have legislation protecting ROFR rights for incumbent utilities.

Regional planning and cost allocation

The FERC’s initial order on MISO’s compliance filing required MISO to remove pre-existing federal ROFR provisions in the MISO Transmission Owners Agreement (TOA) and tariff, and rejected proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project. Xcel Energy and other parties requested rehearing of this issue. In May 2014, FERC denied rehearing on the issue of whether ROFR provisions must be removed from the MISO TOA and MISO tariff, but ruled that MISO can consider state statutes when determining whether to approve an applicant for a competitive project. The MISO transmission owners filed an appeal of the FERC orders with the U.S. Court of Appeals for the Seventh Circuit; action on the appeal is pending. The FERC also accepted changes to MISO’s transmission cost allocation procedures that will protect the ROFR for projects needed for system reliability. MISO submitted a compliance filing to the May 2014 order on July 14, 2014, which is pending FERC action. MISO has proposed that the Order 1000 compliance tariffs be effective for projects approved in December 2014.

Interregional planning and cost allocation

MISO submitted its initial Order 1000 interregional compliance filing in July 2013. The filing is pending initial action by the FERC.

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 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. NSP-Wisconsin expects prompt action by FERC to finalize the rule with a likely effective date 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.

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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. 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 which are still underway.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

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. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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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)).
10.01*	Amended and Restated Credit Agreement, dated as of Oct. 14, 2014 among NSP-Wisconsin, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.05 to Form 8-K, dated Oct. 14, 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 Sept. 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)

Nov. 3, 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

(Amounts in Thousands) ^(a)(b)

Sept. 30, 2014

Dec. 31, 2013

Million British thermal units of natural gas