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, 2016~~March 31, 2017



¨	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)		Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

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



Class		Outstanding at ~~Oct. 31, 2016~~April 28, 2017
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	2018
Item 4 —	Controls and Procedures	2521

PART II — OTHER INFORMATION

Item 1 —	Legal Proceedings	2522
Item 1A —	Risk Factors	25
~~Item 4~~ —	~~Mine Safety Disclosures~~	26
~~Item 5~~ —	~~Other Information~~	2622
Item 6 —	Exhibits	2622

SIGNATURES		2723



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						Three Months Ended March 31
	2016			2015			2016			2015			2017			2016
Operating revenues
Electric	$	232,216		$	224,666		$	646,619		$	634,571		$	216,309		$	211,524
Natural gas	13,646			11,088			72,671			91,273			48,347			43,020
Other	282			407			877			1,090			275			306
Total operating revenues	246,144			236,161			720,167			726,934			264,931			254,850

Operating expenses
Electric fuel and purchased power, non-affiliates	4,238			2,624			11,870			5,066			2,873			3,981
Purchased power, affiliates	105,734			102,297			311,301			318,542			106,458			108,714
Cost of natural gas sold and transported	6,081			4,375			35,964			54,933			25,987			23,418
Operating and maintenance expenses	49,235			46,292			148,370			134,126			49,862			48,619
Conservation program expenses	3,308			2,977			9,468			8,821			3,054			3,066
Depreciation and amortization	24,700			23,019			72,869			66,908			27,049			24,449
Taxes (other than income taxes)	6,506			7,045			20,757			21,151			6,873			7,155
Loss on Monticello life cycle management/extended power uprate project	—			—			—			5,237
Total operating expenses	199,802			188,629			610,599			614,784			222,156			219,402

Operating income	46,342			47,532			109,568			112,150			42,775			35,448

Other (expense) income, net	(102		)	100			424			384
Other income, net													246			449
Allowance for funds used during construction — equity	1,241			1,929			2,969			5,926			1,287			810

Interest charges and financing costs
Interest charges — includes other financing costs of $465, $461, $1,388 and $1,273, respectively	8,613			8,625			25,800			24,152
Interest charges — includes other financing costs of $456 and $462, respectively													8,682			8,604
Allowance for funds used during construction — debt	(525		)	(931		)	(1,264		)	(2,865		)	(550		)	(347		)
Total interest charges and financing costs	8,088			7,694			24,536			21,287			8,132			8,257

Income before income taxes	39,393			41,867			88,425			97,173			36,176			28,450
Income taxes	15,172			15,635			33,948			36,162			13,757			10,819
Net income	$	24,221		$	26,232		$	54,477		$	61,011		$	22,419		$	17,631

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				Three Months Ended March 31
	2016		2015		2016		2015		2017		2016
Net income	$	24,221	$	26,232	$	54,477	$	61,011	$	22,419	$	17,631
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $13, $13, $38 and $37, respectively	19		19		57		57
Reclassification of losses to net income, net of tax of $12 and $13, respectively									19		19
Other comprehensive income	19		19		57		57		19		19
Comprehensive income	$	24,240	$	26,251	$	54,534	$	61,068	$	22,438	$	17,650

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						Three Months Ended March 31
	2016			2015			2017			2016
Operating activities
Net income	$	54,477		$	61,011		$	22,419		$	17,631
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	74,014			67,936			27,425			24,829
Deferred income taxes	27,769			38,595			11,348			5,284
Amortization of investment tax credits	(396		)	(396		)	(131		)	(132		)
Allowance for equity funds used during construction	(2,969		)	(5,926		)	(1,287		)	(810		)
Loss on Monticello life cycle management/extended power uprate project	—			5,237
Net derivative losses	112			338			166			200
Changes in operating assets and liabilities:
Accounts receivable	9,394			10,026			(10,867		)	(2,797		)
Accrued unbilled revenues	8,203			12,657			12,986			7,326
Inventories	1,290			2,847			4,806			6,717
Other current assets	7,791			14,471			4,305			6,348
Accounts payable	11,946			(25,023		)	19,809			2,325
Net regulatory assets and liabilities	(10,256		)	(13,962		)	656			1,856
Other current liabilities	1,523			5,948			(9,158		)	3,492
Pension and other employee benefit obligations	(6,256		)	(3,931		)	(8,860		)	(7,264		)
Change in other noncurrent assets	(402		)	11			(294		)	(319		)
Change in other noncurrent liabilities	1,918			595			(800		)	798
Net cash provided by operating activities	178,158			170,434			72,523			65,484

Investing activities
Utility capital/construction expenditures	(138,616		)	(171,586		)	(47,999		)	(44,655		)
Allowance for equity funds used during construction	2,969			5,926			1,287			810
Other, net	781			(90		)	(159		)	292
Net cash used in investing activities	(134,866		)	(165,750		)	(46,871		)	(43,553		)

Financing activities
Repayments of short-term borrowings, net	(6,000		)	(78,000		)	(27,000		)	(5,000		)
Proceeds from issuance of long-term debt	—			98,038
Repayments of long-term debt	(44		)	—			(13		)	(14		)
Capital contributions from parent	1,108			25,060
Capital contributions from (to) parent							12,282			(1,545		)
Dividends paid to parent	(38,414		)	(40,265		)	(10,729		)	(15,322		)
Net cash (used in) provided by financing activities	(43,350		)	4,833
Other, net							(70		)	—
Net cash used in financing activities							(25,530		)	(21,881		)

Net change in cash and cash equivalents	(58		)	9,517			122			50
Cash and cash equivalents at beginning of period	1,079			1,285			1,546			1,079
Cash and cash equivalents at end of period	$	1,021		$	10,802		$	1,668		$	1,129

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(21,692	)	$	(18,647	)	$	(6,020	)	$	(6,305	)
Cash (paid) received for income taxes, net	(2,298		)	9,662
Cash paid for income taxes, net							(11,489		)	(2,424		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	16,011		$	13,520		$	15,150		$	9,586

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, 2016			Dec. 31, 2015			March 31, 2017			Dec. 31, 2016
Assets
Current assets
Cash and cash equivalents	$	1,021		$	1,079		$	1,668		$	1,546
Accounts receivable, net	47,811			56,378			64,898			54,031
Accrued unbilled revenues	39,495			47,698			40,652			53,638
Inventories	20,269			21,559			13,503			18,309
Regulatory assets	13,567			16,146			18,126			18,162
Prepaid taxes	17,495			25,976			20,414			25,915
Deferred income taxes	7,671			3,138
Prepayments and other	3,187			2,387			4,831			3,785
Total current assets	150,516			174,361			164,092			175,386

Property, plant and equipment, net	1,901,696			1,828,079			1,972,130			1,947,637

Other assets
Regulatory assets	292,969			289,196			284,587			286,188
Other investments	3,259			4,042			3,003			2,844
Other	471			67			1,079			785
Total other assets	296,699			293,305			288,669			289,817
Total assets	$	2,348,911		$	2,295,745		$	2,424,891		$	2,412,840

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,138		$	1,131		$	1,110		$	1,123
Short-term debt	4,000			10,000			33,000			60,000
Notes payable to affiliates	500			500			500			500
Accounts payable	38,153			34,317			31,886			41,068
Accounts payable to affiliates	30,386			24,538			55,082			29,037
Dividends payable to parent	14,687			15,322			13,071			10,729
Regulatory liabilities	17,546			11,781			20,830			17,428
Environmental liabilities	16,366			17,155			40,413			41,438
Accrued interest	9,615			7,945			9,681			8,012
Other	13,226			15,778			15,128			26,484
Total current liabilities	145,617			138,467			220,701			235,819

Deferred credits and other liabilities
Deferred income taxes	428,051			393,569			442,771			430,593
Deferred investment tax credits	8,164			8,560			7,906			8,037
Regulatory liabilities	146,247			141,289			149,713			148,189
Environmental liabilities	68,419			77,441			21,827			23,003
Customer advances	19,678			18,480			18,780			19,425
Pension and employee benefit obligations	43,461			49,889			46,157			55,164
Other	16,858			16,347			18,695			18,814
Total deferred credits and other liabilities	730,878			705,575			705,849			703,225

Commitments and contingencies
Capitalization
Long-term debt	661,796			661,318			662,125			661,946
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Sept. 30, 2016 and Dec. 31, 2015, respectively	93,300			93,300
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at March 31, 2017 and Dec. 31, 2016, respectively							93,300			93,300
Additional paid in capital	398,033			394,553			410,315			395,315
Retained earnings	319,439			302,741			332,715			323,368
Accumulated other comprehensive loss	(152		)	(209		)	(114		)	(133		)
Total common stockholder’s equity	810,620			790,385			836,216			811,850
Total liabilities and equity	$	2,348,911		$	2,295,745		$	2,424,891		$	2,412,840

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, 2016~~March 31, 2017 and Dec. 31, ~~2015;~~2016; the results of its operations, including the components of net income and comprehensive income, for the three ~~and nine~~ months ended ~~Sept. 30, 2016~~March 31, 2017 and ~~2015;~~2016; and its cash flows for the ~~nine~~three months ended ~~Sept. 30, 2016~~March 31, 2017 and ~~2015.~~2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~Sept. 30, 2016~~March 31, 2017 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, ~~2015~~2016 balance sheet information has been derived from the audited ~~2015~~2016 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, ~~2015.~~2016. 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, ~~2015,~~2016, filed with the SEC on Feb. ~~22, 2016.~~24, 2017. 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, ~~2015,~~2016, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a new framework for the recognition of ~~revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive~~revenue. NSP-Wisconsin expects its adoption will result in ~~exchange for goods and services. The new guidance also includes additional disclosure requirements~~increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs. NSP-Wisconsin has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. NSP-Wisconsin currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with ~~customers. The guidance is~~customers effective ~~for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating~~Jan. 1, 2018, with the ~~impact of adopting ASU 2014-09 on its consolidated financial statements.~~

~~Presentation of Deferred Taxes —~~ ~~In November 2015, the FASB issued~~ ~~Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17)~~, which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, NSP-Wisconsin does not expect the implementation of ASU 2015-17 to have a materialcumulative impact on ~~its consolidated financial statements.~~contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which ~~among other changes in accounting~~eliminates the available-for-sale classification for marketable equity securities, and ~~disclosure requirements,~~also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price ~~changes, and also eliminates the available-for-sale classification for marketable equity securities.~~changes. Under the new ~~guidance,~~standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin ~~is currently evaluating~~expects that the ~~impact~~overall impacts of ~~adopting ASU 2016-01 on its consolidated financial statements.~~the Jan. 1, 2018 adoption will not be material.

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Leases — InIn February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for ~~all~~most leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, ~~2018, and early~~2018. NSP-Wisconsin has not yet fully determined the impacts of implementation. However, adoption is ~~permitted.~~expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. NSP-Wisconsin ~~is currently evaluating~~expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the ~~impact~~new standard, but has not yet completed its evaluation of ~~adopting ASU 2016-02 on its consolidated financial statements.~~certain other contracts, including arrangements for the secondary use of assets, such as land easements.

~~Stock Compensation~~Presentation of Net Periodic Benefit Cost — InIn March ~~2016,~~2017, the FASB issued ~~Improvements to Employee Share-Based Payment Accounting,~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic ~~718~~715 (ASU ~~2016-09),~~No. 2017-07), which ~~amends existing~~establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, ~~to simplify several aspects~~only the service cost component of pension cost is eligible for capitalization. NSP-Wisconsin has not yet fully determined the impacts of adoption of the standard, but expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment, and ~~presentation for share-based payment transactions, including~~that the ~~accounting for income taxes and forfeitures, as well as presentation~~impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of ~~cash flows.~~income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, ~~2016, and early adoption is permitted. NSP-Wisconsin does not expect the implementation of ASU 2016-09 to have a material impact on its consolidated financial statements.~~

~~Recently Adopted~~

~~Consolidation~~— ~~In February 2015, the FASB issued~~ ~~Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02)~~, which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. NSP-Wisconsin implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its consolidated financial statements.

~~Presentation of Debt Issuance Costs~~— ~~In April 2015, the FASB issued~~ ~~Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03)~~, which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. NSP-Wisconsin implemented the new guidance as required on Jan. 1, 2016, and as a result, $5.0 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $5.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

~~Fair Value Measurement~~— ~~In May 2015, the FASB issued~~ ~~Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07),~~ which eliminates the requirement to categorize fair value measurements using a net asset value methodology in the fair value hierarchy. NSP-Wisconsin implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements.2017.


3.	Selected Balance Sheet Data

(Thousands of Dollars) Sept. 30, 2016 Dec. 31, 2015
Accounts receivable, net ^(a)

Accounts receivable $ 52,270
$ 61,506
Less allowance for bad debts (4,459 ) (5,128 )
$ 47,811
$ 56,378

(Thousands of Dollars) Sept. 30, 2016 Dec. 31, 2015
Inventories
Materials and supplies $ 7,100
$ 6,785
Fuel 4,887
6,528
Natural gas 8,282
8,246
$ 20,269
$ 21,559

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(Thousands of Dollars) Sept. 30, 2016 Dec. 31, 2015
Property, plant and equipment, net
Electric plant $ 2,471,420
$ 2,411,562
Natural gas plant 285,829
275,376
Common and other property 134,988
132,329
Construction work in progress 117,543
65,755
Total property, plant and equipment 3,009,780
2,885,022
Less accumulated depreciation (1,108,084 ) (1,056,943 )
$ 1,901,696
$ 1,828,079



(Thousands of Dollars)	March 31, 2017			Dec. 31, 2016
Accounts receivable, net ^(a)
Accounts receivable	$	69,975		$	58,896
Less allowance for bad debts	(5,077		)	(4,865		)
	$	64,898		$	54,031


^(a)	Accounts receivable, net includes an immaterial amount due from affiliates as of ~~Sept. 30, 2016~~March 31, 2017 and Dec. 31, ~~2015,~~2016, respectively.



(Thousands of Dollars)	March 31, 2017		Dec. 31, 2016
Inventories
Materials and supplies	$	6,798	$	6,582
Fuel	4,893		4,743
Natural gas	1,812		6,984
	$	13,503	$	18,309



(Thousands of Dollars)	March 31, 2017			Dec. 31, 2016
Property, plant and equipment, net
Electric plant	$	2,520,158		$	2,499,401
Natural gas plant	299,926			294,986
Common and other property	156,213			156,316
Construction work in progress	135,927			118,822
Total property, plant and equipment	3,112,224			3,069,525
Less accumulated depreciation	(1,140,094		)	(1,121,888		)
	$	1,972,130		$	1,947,637


4.	Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2015~~2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

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Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including athe 2009 carryback claim. As of ~~Sept. 30, 2016,~~March 31, 2017, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through ~~2014 claims, and the anticipated claim for 2015.~~2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their case to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in ~~June~~December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS's proposed adjustment of the carryback claims. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the first quarter of 2017, the IRS proposed an adjustment to tax years 2012 and 2013 that could have impacted Xcel Energy’s net operating loss (NOL) and tax credit carryforwards and effective tax rate (ETR). After additional review, the IRS withdrew their proposed adjustment. As of ~~Sept. 30, 2016,~~March 31, 2017, the IRS had not proposed any other material adjustments to tax years 2012 and 2013.

State Audits — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of ~~Sept. 30, 2016,~~March 31, 2017, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2012. In ~~August~~ 2016, Wisconsin began an audit of years 2012 and 2013. As of ~~Sept. 30, 2016,~~March 31, 2017, Wisconsin had not proposed any adjustments, and there were no other state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ~~effective tax rate (ETR).~~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~~impact the ~~payment~~timing of cash payment to the taxing ~~authority to an earlier period.~~authority.

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


(Millions of Dollars)	Sept. 30, 2016		Dec. 31, 2015		March 31, 2017		Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions	$	0.3	$	0.2	$	0.4	$	0.4
Unrecognized tax benefit — Temporary tax positions	5.0		4.3		5.0		4.9
Total unrecognized tax benefit	$	5.3	$	4.5	$	5.4	$	5.3

The unrecognized tax benefit amounts were reduced by the tax benefits associated with ~~net operating loss (NOL)~~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, 2016 Dec. 31, 2015
NOL and tax credit carryforwards $ (1.1 ) $ (0.9 )

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(Millions of Dollars)	March 31, 2017			Dec. 31, 2016
NOL and tax credit carryforwards	$	(1.2	)	$	(1.2	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Wisconsin audit progresses, and other state audits resume. As the IRS Appeals and IRS and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at ~~Sept. 30, 2016~~March 31, 2017 and Dec. 31, ~~2015~~2016 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of ~~Sept. 30, 2016~~March 31, 2017 or Dec. 31, ~~2015.~~2016.


5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2015, and in Note 5 to NSP-Wisconsin's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30,~~ 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

~~Wisconsin 2017 Electric and Gas Rate Case —~~ In April 2016, NSP-Wisconsin filed a request with the PSCW for an increase in annual electric rates of $17.4 million, or 2.4 percent, and an increase in natural gas rates by $4.8 million, or 3.9 percent, effective January 2017.

The electric rate request is for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average rate base of $1.188 billion in 2017.

The natural gas rate request is for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former manufactured gas plant (MGP) site and adjacent area in Ashland, Wis.

No changes are being requested to the capital structure or the 10.0 percent return on equity (ROE) authorized by the PSCW in the 2016 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, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.

In August 2016, the PSCW Staff (Staff) and the intervenors filed their direct testimony in the case. The Staff recommended an electric rate increase of $19.5 million, or 2.7 percent and a natural gas rate increase of $4.8 million, or 3.9 percent. The Staff adjustments reflect revisions to previously forecasted rate base as well as fuel and purchased power expense. The Staff’s recommended rate increase also encompasses the PSCW’s July 2016 decision to remove the $9.5 million fuel refund credit from the rate case and refund that amount directly to customers in 2016. Adjusting for the treatment of the fuel refund, the Staff’s recommendation is $7.4 million less than NSP-Wisconsin’s request.

On Oct. 26, 2016, the PSCW verbally approved an electric rate increase of approximately $22.5 million, or 3.2 percent, and a natural gas rate increase of $4.8 million, or 3.9 percent. The difference between the Staff’s recommendation and the PSCW’s approved electric increase is attributable to an increase in forecasted fuel and purchased power expense. Consistent with long-standing PSCW policy, these costs were updated prior to the PSCW’s decision to reflect current market forecasts. The PSCW approved NSP-Wisconsin’s requested natural gas rate increase consistent with the Staff’s recommendation.

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~~The major components of the retail electric rate increase, the Staff’s recommendation, and the PSCW’s approval are summarized below:~~

Electric Rate Request (Millions of Dollars) NSP-Wisconsin Request Staff Recommendation Final Decision
Rate base investments $ 11.0
$ 7.6
7.6
Generation and transmission expenses (excluding fuel and purchased power) ^(a)
6.8
6.1
6.1
Fuel and purchased power expenses 11.0
7.7
10.7
Subtotal 28.8
21.4
24.4
2015 fuel refund ^(b)
(9.5 ) —
—
Department of Energy settlement refund (1.9 ) (1.9 ) (1.9 )
Total electric rate increase $ 17.4
$ 19.5
$ 22.5

^(a)

Includes Interchange Agreement billings. The Interchange Agreement is a Federal Energy Regulatory Commission (FERC) tariff under which NSP-Wisconsin and its affiliate, NSP-Minnesota, own and operate a single integrated electric generation and transmission system and both companies pay a pro-rata share of system capital and operating costs. For financial reporting purposes, these expenses are included in operating and maintenance (O&M).

^(b)

In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively increases NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.

~~NSP-Wisconsin anticipates a final written order later this year, with new rates effective on Jan. 1, 2017.~~

~~Pending~~Recently Concluded Regulatory Proceedings - Michigan Public Service Commission (MPSC)

Michigan 2017 Natural Gas Rate Case — In October 2016, NSP-Wisconsin filed a request with the MPSC to increase base rates for natural gas service by approximately $347 thousand annually, or 6.5 percent. The filing was based on a 2017 forecast test year, a 10.2 percent ~~ROE,~~return on equity (ROE), an equity ratio of 52.56 percent and a forecasted average rate base of approximately $6.4 million. The primary driver of the requested increase is investment in natural gas distribution infrastructure, mainly in conjunction with the ~~company’s~~NSP-Wisconsin’s Distribution Integrity Management Program (DIMP). NSP-Wisconsin also proposed an Infrastructure Cost Recovery Mechanism (ICRM) rate rider to recover ongoing costs associated with the DIMP. In addition, the filing requested recovery of approximately $129 thousand, or 2.4 percent, through the ICRM, beginning in January 2018. Under the proposal, the ICRM rider would be adjusted annually.

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

~~Nuclear Project Prudence Investigation~~ ~~— In 2013, NSP-Minnesota completed~~ No party sought to intervene in the Monticello life cycle management (LCM)/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.case.

In ~~2013,~~March 2017, NSP-Wisconsin reached a settlement with the ~~MPUC initiated an investigation to determine whether~~MPSC staff that eliminated the ~~final costs~~ICRM rider in lieu of a multi-year rate plan that includes funding for the ~~Monticello LCM/EPU project were prudent. In~~DIMP. The settlement authorized a $266 thousand, or 5 percent overall rate increase for 2017, followed by a $140 thousand, or 2.5 percent step increase in January 2018, and another $143 thousand, or 2.5 percent step increase in January 2019. The settlement was based on a 10.0 percent ROE and a 52.56 percent equity ratio. On March ~~2015,~~28, 2017 the ~~MPUC voted to allow for full recovery, including a return,~~MPSC issued an order approving the settlement agreement and new rates went into effect on $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million.April 1, 2017.

Pending Regulatory ~~Proceedings~~Proceeding — ~~FERC~~Federal Energy Regulatory Commission (FERC)

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

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In December 2015, an ~~administrative law judge~~Administrative Law Judge (ALJ) ~~initial decision~~ recommended the FERC approve a ROE of 10.32 percent using a FERC ROE methodology adopted in June 2014, which the FERC upheld in an order issued ~~on Sept. 28,~~in September 2016. This ROE is applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE is 10.82 percent, which includes a ~~previously approved~~ 50 basis point adder for RTO membership.

In February 2015, a second complaint seeking to reduce the MISO ~~region~~ ROE from 12.38 percent to 8.67 percent prior to any adder was filed ~~which~~with the FERC, ~~set for hearings,~~ resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, the North Dakota Public Service Commission, the South Dakota Public Utilities Commission and the Minnesota Department of Commerce joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. OnIn June ~~30,~~ 2016, the ALJ ~~issued an initial decision recommending~~recommended a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow (DCF) ~~range.~~range, applying the June 2014 FERC ROE methodology. A decision was expected later in 2017, but could be delayed by the lack of a quorum at the FERC.

On April 14, 2017 the D.C. Circuit Court of Appeals vacated and remanded the June 2014 FERC decision, previously made in a New England ROE case. The court decision found that the FERC in that case had not established that the prior ROE was unjust and unreasonable, and that the FERC also failed to adequately support the newly approved ROE. The New England ROE ruling was then the basis for the ROE methodology used in the MISO complaint cases. The court found that the ROE methodology used in the New England ROE case was inadequate because it relied on approaches other than the DCF model. The impact of this court decision on the pending MISO complaint cases is ~~expected in 2017.~~uncertain.

As of ~~Sept. 30, 2016,~~March 2017, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the FERC ~~order, as well as~~order. This liability is net of refunds processed during the first quarter of 2017. NSP-Minnesota has also recognized a current liability representing the best estimate of the final ROE for the ~~second~~Feb. 12, 2015 to May 11, 2016 complaint period.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10 and 11 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2015, and in Note 6 to NSP-Wisconsin’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30,~~ 2016, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Wisconsin’s financial position.

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Guarantees

NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program. NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement. The guarantee issued by NSP-Wisconsin has a stated maximum amount. The guarantee contains no recourse provisions and requires no collateral. These agreements have expiration dates through 2020.

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


(Millions of Dollars)	Sept. 30, 2016		Dec. 31, 2015		March 31, 2017		Dec. 31, 2016
Guarantee issued and outstanding	$	1.0	$	1.0	$	1.0	$	1.0
Current exposure under this guarantee	0.1		0.1		0.1		0.1

Environmental Contingencies

Ashland ~~MGP~~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 Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the ~~park (the Sediments).~~park.

In 2012, ~~under a settlement agreement with the United States Environmental Protection Agency (EPA),~~ NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site)., under a settlement agreement with the United States Environmental Protection Agency (EPA), The current cost estimate for the cleanup of the Phase I Project Area is approximately ~~$71.4~~$77.2 million, of which approximately ~~$52.6~~$57.2 million has been spent.

NSP-Wisconsin performed a wet dredge pilot study in ~~the summer of~~ 2016 and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the Sediments. As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge pilot to additional areas of the Site. ~~Settlement negotiations are ongoing between~~In January 2017, NSP-Wisconsin agreed to remediate the ~~EPA and NSP-Wisconsin regarding the performance of the full scale cleanup of the Sediments. If~~Phase II Project Area (the Sediments), under a ~~court-approved~~ settlement ~~can be reached~~agreement with the ~~EPA,~~EPA. The settlement was approved by the U.S. District Court for the Western District of Wisconsin NSP-Wisconsin ~~anticipates~~has initiated field activities to perform a full scale wet dredge remedy of the Sediments ~~could be performed beginning as early as~~in 2017, ~~and potentially conclude by~~with performance of restoration activities in 2018.

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At ~~Sept. 30, 2016~~March 31, 2017 and Dec. 31, ~~2015,~~2016, NSP-Wisconsin had recorded a total liability of ~~$84.6~~$62.1 million and ~~$94.4~~$64.3 million,, respectively, for the entire site. NSP-Wisconsin’s potential liability, the actual cost of remediation and the timing of expenditures are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the remediation cost.

NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The ~~PSCW~~Public Service Commission of Wisconsin (PSCW) has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ~~ten-year~~ten-year period and to apply a three percent carrying cost to the unamortized regulatory asset. In April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovery of additional expenses associated with remediating the Site. ~~If approved,~~In December 2016, the PSCW issued a written order approving the requested increase in annual recovery of MGP clean-up costs ~~would increase~~ from $7.6 million in 2016 to $12.4 million in 2017.

Other MGP Sites — In addition to the site in Ashland, Wis., NSP-Wisconsin has identified one site where former MGP disposal activities may have resulted in site contamination and is under current investigation. There are other parties that may have responsibility for some portion of any remediation. NSP-Wisconsin anticipates that the majority of the investigation or remediation at this site will continue through at least 2018. NSP-Wisconsin had accrued $0.1 million for this site at March 31, 2017 and Dec. 31, 2016. There may be insurance recovery and/or recovery from other PRPs to offset any costs incurred. NSP-Wisconsin anticipates that any significant amounts incurred will be recovered from customers.

~~Cross-State Air Pollution Rule (CSAPR)~~ ~~— CSAPR addresses long range transport~~

Table of ~~particulate matter~~Contents

Environmental Requirements

Water and ~~ozone by requiring reductions in sulfur dioxide and nitrogen oxide (NOx) from utilities in the eastern half~~Waste

Federal Clean Water Act (CWA) Waters of the United States ~~including Wisconsin, using an emissions trading program.~~Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The final rule will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by the end of 2017.

~~CSAPR was adopted~~In February 2017, President Trump issued an executive order requiring the EPA and the Corps to ~~address interstate emissions impacting downwind states’ attainment~~review and revise the final rule. The executive order directs the agencies to consider interpreting the term “Waters of the ~~1997 ozone National Ambient Air Quality Standard (NAAQS)~~U.S.” in a manner that is more narrow than the final rule. In March 2017, the EPA and the ~~1997~~Corps published formal notice of the agencies’ intent to review the final rule and ~~2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any~~engage in further ~~reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program.~~ rulemaking.

Federal CWA Effluent Limitations Guidelines (ELG) —In ~~December~~ 2015, the EPA ~~proposed adjustments~~issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to ~~CSAPR emission budgets which address attainment~~surface waters as well as utility-owned landfills that receive coal combustion residuals. NSP-Wisconsin continues to evaluate the cost of compliance at its facilities potentially affected by this rule. NSP-Wisconsin believes that compliance costs would be recoverable through regulatory mechanisms. Consolidated challenges to the rule are being heard by the Fifth Circuit Court of Appeals. On April 12, 2017, the EPA issued an administrative stay to delay the ELG rule’s compliance deadlines during the pendency of the ~~more stringent 2008 ozone NAAQS. The~~ongoing litigation in order to give the agency the opportunity to reconsider and review the rule.

Air

Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, the EPA ~~adopted a~~issued its final rule for existing power plants. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.

The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. Parties in the litigation, who support the CPP, have filed briefs opposing the EPA’s motion. A court ruling on the EPA’s motion is expected in the second quarter of 2017.

NSP-Wisconsin has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in states in which NSP-Wisconsin operates. If state plans do not provide credit for the ~~ozone season~~investments NSP-Wisconsin has already made to reduce GHG emissions, or if they require additional initiatives or emission ~~budget for NOx which did~~reductions, then their requirements would potentially impose additional substantial costs. NSP-Wisconsin cannot predict the costs of compliance with the final rule once it takes effect due to the uncertainty about what, if anything, the final rules may require. NSP-Wisconsin believes compliance costs will be recoverable through regulatory mechanisms. If NSP-Wisconsin’s regulators do not ~~materially~~allow recovery of all or a part of the cost of capital investment or the operating and maintenance (O&M) costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact ~~NSP-Wisconsin.~~on results of operations, financial position or cash flows.

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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.

Employment, Tort and Commercial Litigation

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.

The cases were consolidated in U.S. District Court in Nevada. Five of the cases have since been settled and seven ~~have been dismissed. One~~remain active, which include one multi-district litigation (MDL) matter ~~remains and it consists~~consisting of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In ~~May~~November 2016, the MDL judge ~~granted summary judgment dismissing defendants from the Farmland lawsuit.~~dismissed e prime and Xcel Energy ~~have~~from the Farmland lawsuit, and Farmland has appealed the dismissal. Motions for summary judgment were filed ~~a motion seeking clarification that this order includes them. This motion is currently pending and is expected to be heard in December 2016. The~~by defendants, including e prime, ~~defendants filed a~~in all of the remaining lawsuits. In March 2017 the U.S. District Court issued an order dismissing the claims against e prime in the Sinclair lawsuit and denied plaintiffs motions for class certification in the other lawsuits. The U.S. District Court did not grant e prime’s summary judgment ~~motion~~motions in the Wisconsin or Colorado class lawsuit (Breckenridge) and oppositions to class certifications in all the class actions, which is also expected to be heard in December 2016. Trial dates are not expected to occur prior to early 2017.cases. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

~~Table of Contents~~


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, 2016			Year Ended Dec. 31, 2015			Three Months Ended March 31, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	150		$	150		$	150		$	150
Amount outstanding at period end	4			10			33			60
Average amount outstanding	6			39			52			15
Maximum amount outstanding	23			122			98			64
Weighted average interest rate, computed on a daily basis	0.60		%	0.44		%	0.93		%	0.69		%
Weighted average interest rate at period end	0.60			0.70			1.10			0.95

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, 2016~~March 31, 2017 and Dec. 31, ~~2015,~~2016, 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 capacity.~~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, 2016,~~March 31, 2017, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Credit Facility ^(a)	Drawn ^(b)		Available
$	150	$	4	$	146	150	$	33	$	117


^(a)	This credit facility ~~expires~~matures in June 2021.


^(b)	Includes outstanding commercial paper.

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All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the credit facility outstanding at ~~Sept. 30, 2016~~March 31, 2017 and Dec. 31, ~~2015.~~

~~Amended Credit Agreements~~ - In June 2016, NSP-Wisconsin entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $150 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:

~~The maturity extended from October 2019 to June 2021.~~

The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.

The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 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 credit facility termination date for an additional one-year period, subject to majority bank group approval.~~2016.

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, 2016			Dec. 31, 2015			March 31, 2017			Dec. 31, 2016
Notes payable to affiliates	$	0.5		$	0.5		$	0.5		$	0.5
Weighted average interest rate at period end	0.77		%	0.87		%	1.20		%	0.95		%

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8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the ~~measurement~~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 ~~prices.~~net asset values.

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

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

Derivative Instruments Fair Value Measurements

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

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

At ~~Sept. 30, 2016,~~March 31, 2017, accumulated other comprehensive loss related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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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, 2016~~March 31, 2017 and Dec. 31, ~~2015:~~2016:

(Amounts in Thousands) ^(a)(b)
Sept. 30, 2016 Dec. 31, 2015
Million British thermal units of natural gas 284
388


^(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, 2016~~March 31, 2017 and ~~2015, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the nine months ended Sept. 30, 2016 and 2015.~~2016.

During the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2017 and 2016, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.1 million ~~and $0.2 million~~ recognized as regulatory assets and liabilities, respectively. For the three and nine months ended Sept. 30, 2015, changes in the fair value of natural gas commodity derivatives resulted in immaterial and $0.1 million of net losses recognized as regulatory assets and liabilities, respectively.liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Natural gas commodity derivatives settlement losses of ~~$0.6~~$0.2 million and ~~$1.0~~$0.6 million were recognized for the ~~nine~~three months ended ~~Sept. 30,~~March 31, 2017 and 2016, ~~and 2015,~~ respectively, and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate. ~~There were no natural gas commodity derivatives settlement losses recognized during the three months ended Sept. 30, 2016 and 2015, respectively.~~

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three ~~and nine~~ months ended ~~Sept. 30, 2016~~March 31, 2017 and ~~2015.~~2016. 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.~~transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-Wisconsin’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

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

Recurring Fair Value Measurements — The following ~~tables present~~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:

Sept. 30, 2016
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 $ —
$ 114
$ —
$ 114
$ —
$ 114


	Dec. 31, 2015															Dec. 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting ^(a)				Total ^(c)			Fair Value								Fair Value Total			Counterparty Netting ^(a)			Total ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Counterparty Netting ^(a)			Level 1				Level 2			Level 3					Fair Value Total			Counterparty Netting ^(a)			Total ^(b)
Current derivative assets							Fair Value Total
Natural gas commodity	$	—	$	15	$	—	$	15	$	(11	)		Total ^(c)	$	4		$	—		$	149	$	—		$	149		$	—		$	149
Total current derivative assets	$	—	$	15	$	—	$	15	$	(11	)		$	4
Current derivative liabilities
Natural gas commodity	$	—	$	194	$	—	$	194	$	(11	)		$	183
Total current derivative liabilities	$	—	$	194	$	—	$	194	$	(11	)		$	183

^(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, 2016 and~~ Dec. 31, ~~2015~~.2016. 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 current assets balance of ~~$3.2 million at Sept. 30, 2016, in the consolidated balance sheets.~~


^(c)	~~Included in other current assets balance of $2.4 million and other current liabilities balance of $15.8~~$3.8 million at Dec. 31, ~~2015,~~2016, in the consolidated balance sheets.

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Fair Value of Long-Term Debt

As of ~~Sept. 30, 2016~~March 31, 2017 and Dec. 31, ~~2015,~~2016, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Sept. 30, 2016				Dec. 31, 2015				March 31, 2017				Dec. 31, 2016
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion ^(a)	$	662,934	$	781,939	$	662,449	$	742,565	$	663,235	$	731,767	$	663,069	$	730,284


^(a)	~~Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2,~~ ~~Accounting Pronouncements~~ ~~for more information on the adoption of ASU 2015-03.~~

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, 2016~~March 31, 2017 and Dec. 31, ~~2015,~~2016, 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						Three Months Ended March 31
(Thousands of Dollars)	2016			2015			2016			2015			2017			2016
Interest (expense) income	$	(73	)	$	11		$	65		$	299
Interest income													$	143		$	124
Other nonoperating income	33			72			299			202			155			158
Insurance policy (expense) income	(58		)	20			70			(109		)	(49		)	170
Other nonoperating expense	(4		)	(3		)	(10		)	(8		)	(3		)	(3		)
Other (expense) income, net	$	(102	)	$	100		$	424		$	384		$	246		$	449


10.	Segment Information

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

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

NSP-Wisconsin’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Wisconsin and Michigan.

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

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include investments in rental housing projects that qualify for low-income housing tax credits.

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

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

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(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Three Months Ended Sept. 30, 2016
Operating revenues ^(a)
$ 232,216
$ 13,646
$ 282
$ —
$ 246,144
Intersegment revenues 110
97
—
(207 ) —
Total revenues $ 232,326
$ 13,743
$ 282
$ (207 ) $ 246,144
Net income (loss) $ 25,459
$ (1,201 ) $ (37 ) $ —
$ 24,221



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other			Reconciling Eliminations			Consolidated Total		Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2015
Three Months Ended March 31, 2017
Operating revenues ^(a)	$	224,666	$	11,088		$	407		$	—		$	236,161	$	216,309	$	48,347	$	275	$	—		$	264,931
Intersegment revenues	101		177			—			(278		)	—		96		114		—		(210		)	—
Total revenues	$	224,767	$	11,265		$	407		$	(278	)	$	236,161	$	216,405	$	48,461	$	275	$	(210	)	$	264,931
Net income (loss)	$	28,285	$	(1,993	)	$	(60	)	$	—		$	26,232
Net income														$	15,470	$	6,545	$	404	$	—		$	22,419




(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2016
Operating revenues ^(a)	$	211,524	$	43,020	$	306	$	—		$	254,850
Intersegment revenues	109		80		—		(189		)	—
Total revenues	$	211,633	$	43,100	$	306	$	(189	)	$	254,850
Net income	$	11,501	$	6,092	$	38	$	—		$	17,631


^(a)	Operating revenues include ~~$44~~$42 million and ~~$42~~$41 million of affiliate electric revenue for the three months ended ~~Sept. 30,~~March 31, 2017 and 2016, ~~and 2015,~~ respectively.

(Thousands of Dollars)
Regulated
Electric

Regulated
Natural Gas
All Other
Reconciling
Eliminations

Consolidated
Total
Nine Months Ended Sept. 30, 2016
Operating revenues ^(a)
$ 646,619
$ 72,671
$ 877
$ —
$ 720,167
Intersegment revenues 317
299
—
(616 ) —
Total revenues $ 646,936
$ 72,970
$ 877
$ (616 ) $ 720,167
Net income $ 52,058
$ 2,426
$ (7 ) $ —
$ 54,477

(Thousands of Dollars)
Regulated
Electric

Regulated
Natural Gas
All Other
Reconciling
Eliminations

Consolidated
Total
Nine Months Ended Sept. 30, 2015
Operating revenues ^(a)
$ 634,571
$ 91,273
$ 1,090
$ —
$ 726,934
Intersegment revenues 308
475
—
(783 ) —
Total revenues $ 634,879
$ 91,748
$ 1,090
$ (783 ) $ 726,934
Net income (loss) $ 57,586
^(b)
$ 3,714
$ (289 ) $ —
$ 61,011


^(a)	~~Operating revenues include $127 million and $121 million of affiliate electric revenue for the nine months ended Sept. 30, 2016 and 2015, respectively.~~


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


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

Three Months Ended Sept. 30
2016 2015 2016 2015
(Thousands of Dollars) Pension Benefits
Postretirement Health
Care Benefits
Service cost $ 1,104
$ 1,190
$ 6
$ 7
Interest cost 1,704
1,630
163
164
Expected return on plan assets (2,289 ) (2,371 ) (6 ) (8 )
Amortization of prior service cost (credit) 28
27
(88 ) (87 )
Amortization of net loss 1,348
1,701
83
114
Net benefit cost recognized for financial reporting $ 1,895
$ 2,177
$ 158
$ 190

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	Nine Months Ended Sept. 30												Three Months Ended March 31
	2016			2015			2016			2015			2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	3,312		$	3,570		$	18		$	21		$	1,154		$	1,104		$	7		$	6
Interest cost	5,112			4,890			489			490			1,554			1,704			148			163
Expected return on plan assets	(6,867		)	(7,113		)	(18		)	(23		)	(2,295		)	(2,289		)	(8		)	(6		)
Amortization of prior service cost (credit)	84			83			(264		)	(263		)	35			28			(88		)	(88		)
Amortization of net loss	4,044			5,103			249			342			1,462			1,348			109			83
Net benefit cost recognized for financial reporting	$	5,685		$	6,533		$	474		$	567		$	1,910		$	1,895		$	168		$	158

In January ~~2016,~~2017, contributions of ~~$125.0~~$150.0 million were made across four of Xcel Energy’s pension plans, of which ~~$7.4~~$9.0 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during ~~2016.~~2017.

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12.	Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2017 and 2016 ~~and 2015~~ were as follows:

Gains and Losses on
Cash Flow Hedges
(Thousands of Dollars) Three Months Ended Sept. 30, 2016 Three Months Ended Sept. 30, 2015
Accumulated other comprehensive loss at July 1 $ (171 ) $ (247 )
Losses reclassified from net accumulated other comprehensive loss 19
19
Net current period other comprehensive income 19
19
Accumulated other comprehensive loss at Sept. 30 $ (152 ) $ (228 )


	Gains and Losses on Cash Flow Hedges						Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2016			Nine Months Ended Sept. 30, 2015			Three Months Ended March 31, 2017			Three Months Ended March 31, 2016
Accumulated other comprehensive loss at Jan. 1	$	(209	)	$	(285	)	$	(133	)	$	(209	)
Losses reclassified from net accumulated other comprehensive loss	57			57			19			19
Net current period other comprehensive income	57			57			19			19
Accumulated other comprehensive loss at Sept. 30	$	(152	)	$	(228	)
Accumulated other comprehensive loss at March 31							$	(114	)	$	(190	)

Reclassifications from accumulated other comprehensive loss for the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2017 and 2016 ~~and 2015~~ were as follows:

Amounts Reclassified from
Accumulated Other
Comprehensive Loss

(Thousands of Dollars) Three Months Ended Sept. 30, 2016 Three Months Ended Sept. 30, 2015
Losses on cash flow hedges:
Interest rate derivatives $ 32
^(a)
$ 32
^(a)
Total, pre-tax 32
32

Tax benefit (13 ) (13 )
Total amounts reclassified, net of tax $ 19
$ 19

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	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2016				Nine Months Ended Sept. 30, 2015				Three Months Ended March 31, 2017				Three Months Ended March 31, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	95		^(a)	$	94		^(a)	$	31		^(a)	$	32		^(a)
Total, pre-tax	95				94				31				32
Tax benefit	(38		)		(37		)		(12		)		(13		)
Total amounts reclassified, net of tax	$	57			$	57			$	19			$	19


^(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 herein, 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 expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including NSP-Wisconsin’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2015 and Quarterly Reports on Form 10-Q for the quarters ended March 31,~~ 2016 and ~~June 30, 2016)~~subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: 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; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability ofor cost of capital; and employee work force factors.

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Results of Operations

NSP-Wisconsin’s net income was ~~$54.5~~$22.4 million for the ~~nine~~three months ended ~~Sept. 30, 2016~~March 31, 2017 compared with ~~$61.0~~$17.6 million for the same period in ~~2015.~~2016. The ~~impact of the 2015 Monticello LCM/EPU project loss along with~~increase is due to higher electric margins primarily driven by ~~an electric~~ rate ~~increase were more than offset by higher O&M expenses and depreciation. See Note 5 to the consolidated financial statements for further discussion of the Monticello LCM/EPU project loss.~~increases.

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						Three Months Ended March 31
(Millions of Dollars)	2016			2015			2017			2016
Electric revenues	$	647		$	635		$	216		$	212
Electric fuel and purchased power	(323		)	(324		)	(109		)	(113		)
Electric margin	$	324		$	311		$	107		$	99

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

~~Sept. 30:~~March 31:

Electric Revenues


(Millions of Dollars)	2016 vs. 2015			2017 vs. 2016
Retail rate increases (Wisconsin)	$	23
Retail rate increase				$	4
Interchange agreement billings with NSP-Minnesota	7			1
Fuel and purchased power cost recovery	(19		)	1
Other, net	1			(2		)
Total increase in electric revenues	$	12		$	4

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Electric Margin


(Millions of Dollars)	2016 vs. 2015			2017 vs. 2016
Retail rate increases (Wisconsin)	$	23
Interchange agreement billings with NSP-Minnesota	(7		)	$	6
Fuel cost recovery	(7		)
Retail rate increase				4
Other, net	4			(2		)
Total increase in electric margin	$	13		$	8

Natural Gas Revenues and Margin

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

Nine Months Ended Sept. 30
(Millions of Dollars) 2016 2015
Natural gas revenues $ 73
$ 91
Cost of natural gas sold and transported (36 ) (55 )
Natural gas margin $ 37
$ 36

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	Three Months Ended March 31
(Millions of Dollars)	2017			2016
Natural gas revenues	$	48		$	43
Cost of natural gas sold and transported	(26		)	(23		)
Natural gas margin	$	22		$	20

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the ~~nine~~three months ended ~~Sept. 30:~~March 31:

Natural Gas Revenues

(Millions of Dollars) 2016 vs. 2015
Purchased natural gas adjustment clause recovery $ (19 )
Estimated impact of weather (2 )
Retail rate increases 3
Total decrease in natural gas revenues $ (18 )



(Millions of Dollars)	2017 vs. 2016
Purchased natural gas adjustment clause recovery	$	3
Retail rate increase	2
Total increase in natural gas revenues	$	5

Natural Gas Margin


(Millions of Dollars)	2016 vs. 2015			2017 vs. 2016
Retail rate increases (Wisconsin)	$	3
Estimated impact of weather	(2		)
Retail rate increase				$	2
Total increase in natural gas margin	$	1		$	2

Non-Fuel Operating Expenses and Other Items

~~O&M Expenses~~ — O&M expenses increased $14.2 million, or 10.6 percent, for the nine months ended Sept. 30, 2016 compared with the same period in 2015. The increase was primarily due to interchange agreement billings with NSP-Minnesota related to timing of transmission projects.

Depreciation and Amortization — Depreciation and amortization increased ~~$6.0~~$2.6 million, or ~~8.9~~10.6 percent, for the ~~nine months ended Sept. 30, 2016~~first quarter of 2017 compared with ~~the same period in 2015.~~2016. The increase was primarily attributable to capital investments.

Income Taxes — Income tax expense ~~decreased $2.2~~increased $2.9 million for the ~~nine months ended Sept. 30, 2016~~first quarter of 2017 compared with ~~the same period in 2015.~~2016. The ~~decrease~~increase in income tax expense was primarily due to ~~lower~~higher pretax earnings in ~~2016 partially offset by decreased permanent plant-related adjustments (e.g., AFUDC-equity) in 2016.~~2017. The ETR was ~~38.4~~38.0 percent for the ~~nine months ended Sept. 30, 2016 compared with 37.2 percent for the same period in 2015. The higher ETR in 2016 is primarily due to the adjustments referenced above.~~first quarter of 2017 and 2016.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1.1 of NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2015, and Public Utility Regulation included in Item 2 of NSP-Wisconsin’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30,~~ 2016, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

~~NSP Resource Plans~~ ~~— In January 2015, NSP-Minnesota filed its 2016-2030 Integrated Resource Plan (the Plan) with the MPUC.~~

Subsequently, NSP-Minnesota proposed revisions to the Plan, which addressed stakeholder recommendations as well as the Clean Power Plan issued by the EPA. The revised plan was based on four primary elements: (1) accelerate the transition from coal energy to renewables, (2) preserve regional system reliability, (3) pursue energy efficiency gains and grid modernization, and (4) ensure customer benefits. The revised plan includes substantial opportunities for NSP-Minnesota ownership of renewable generation, and would result in 63 percent of NSP System energy being carbon-free by 2030 and a 60 percent reduction in carbon emissions from 2005 levels by 2030.

~~Table of Contents~~

~~Specific terms of the proposal include:~~

~~The addition of 1,800 MW of wind and 1,400 MW of solar between 2016-2030, including approximately 650 MW of solar from NSP-Minnesota’s community solar gardens program by 2020;~~

~~The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;~~

~~Partial replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site to coincide with the Unit 1 retirement;~~

~~The addition of a 230 MW natural gas combustion turbine in North Dakota by the end of 2025;~~

~~Operation of the Monticello and PI nuclear plants through their current license periods in the early 2030’s~~ - and a commitment to provide additional information regarding forecasted cost increases at PI through end of licensed life if the MPUC wishes to further explore alternatives to operating PI through its current license periods.

~~In October 2016, the MPUC verbally approved NSP-Minnesota’s plan, with modifications as follows:~~

The acquisition of at least 1,000 MW of wind by 2019, with additional acquisitions dependent on considerations such as price, bidder qualifications, rate impact, transmission availability and location;

The acquisition of 650 MW of solar before 2021 through the community solar gardens program or other acquisitions - and pursuit of additional, cost-effective solar resources if it is in the best interests of its customers;

~~Determination of the proper mix of purchased power and Company-owned renewable resources shall be made during the resource acquisition process;~~

Retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026, and a finding that more likely than not, there will be a need for approximately 750 MW of capacity coinciding with the retirement of Sherco Unit 1 in 2026;

Authorization for NSP-Minnesota to file a petition for a certificate of need to select the resource that best meets the system resource and local reliability needs associated with the retirement of Sherco Unit 1 in 2026;

~~Acquisition of no less than 400 MW of additional demand response by 2023; and~~

~~Submission of NSP-Minnesota’s next Resource Plan by February 2019.~~

~~The MPUC’s order on NSP-Minnesota’s Resource Plan is expected in late 2016.~~

~~NSP-Minnesota – Request for Proposal (RFP)~~ —In September 2016, NSP-Minnesota issued a RFP for 1,500 MW of wind generation to be in service by 2020. The RFP requests both purchased power agreements and Build-Own-Transfer proposals. NSP-Minnesota intends to compare self-build options to the RFP bids to ensure that all resource additions are cost-competitive.

In October 2016, NSP-Minnesota submitted a petition for approval to the MPUC of a 750 MW self-build wind farm portfolio. RFP bids were received in October 2016 and will be evaluated in conjunction with the self-build proposal.

~~An overview of the anticipated RFP schedule is as follows:~~

~~Project proposal selection and negotiation will occur from November 2016 to March 2017;~~

~~An NSP-Minnesota recommendation for proposed wind additions to the MPUC in the first quarter of 2017; and~~

~~MPUC approval is expected by July 2017.~~

2016 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the ~~nine months~~year ended ~~Sept. 30,~~Dec. 31, 2016 were lower than authorized in rates and outside the two percent annual tolerance band established in the Wisconsin fuel cost recovery ~~rules.~~rules, primarily due to lower sales volume and lower purchased power costs coupled with moderate weather. Under the fuel cost recovery rules, NSP-Wisconsin may retain the amount of over-recovery up to two percent of authorized annual fuel costs, or approximately ~~$3.5~~$3.4 million. However, NSP-Wisconsin must defer the amount of over-recovery in excess of the two percent annual tolerance band for future refund to customers. Accordingly, NSP-Wisconsin recorded a deferral of approximately $6.6 million through Sept. 30, 2016. The amount of the deferral could increase or decrease based on actual fuel costs incurred for the remainder of the year. In ~~the first quarter of~~March 2017 NSP-Wisconsin ~~will file~~filed a reconciliation of 2016 fuel costs with the ~~PSCW.~~PSCW indicating a refund liability of $9.5 million. The final amount of ~~any potential~~the refund is subject to review and approval by the PSCW, which is ~~not~~ expected ~~until~~in mid-2017.

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Summary of Recent Federal Regulatory Developments

~~The Pipeline and Hazardous Materials Safety Administration~~

~~Pipeline Safety Act~~ — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. In April 2016, the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations. These changes include requirements around use of automatic or remote-controlled shut-off valves; testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations.

NSP-Wisconsin continues to analyze the proposed rule changes as they relate to costs, current operations and financial results. PHMSA has indicated that they intend for the rules to go into effect in late 2017 or early 2018.

While NSP-Wisconsin cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of NSP-Wisconsin, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Wisconsin’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, ~~2015 and Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30,~~ 2016. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

Status of FERC Commissioners — The FERC is comprised of five commissioners appointed by the President and confirmed by the Senate. There are currently only two sitting commissioners. It is uncertain when the President will appoint new commissioners or when those appointments may be confirmed. Without three commissioners, the FERC does not have a quorum to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or pending, newly submitted and future filings involving, among other things, contested electric rate matters and certificates of public convenience and necessity for construction of interstate natural gas pipeline facilities.

FERC Order, ~~New~~ ROE Policy — The FERC has adopted a ~~new~~ two-step ROE methodology for electric utilities. The issue of how to apply the ~~new~~ FERC ROE methodology is being contested in various complaint proceedings. There are two ROE complaints against the MISO TOs, which ~~include NSP-Minnesota and~~includes NSP-Wisconsin. In September 2016, the FERC issued an order in the first MISO ROE complaint ~~which upheld~~establishing an ROE of 10.32 percent for the ~~initial decision made by the ALJ in December 2015.~~period Nov. 12, 2013 to Feb. 11, 2015, and prospectively. The second complaint is pending FERC action after issuance of an initial decision by the ALJ in June 2016, recommending an ROE of 9.7 percent for the period Feb. 12, 2015 to May 11, 2016. The FERC ~~is not~~had been expected to issue an order in the second litigated MISO ROE complaint proceeding ~~until 2017.~~during 2017, but the lack of a quorum may delay a final order. See Note 5 to the consolidated financial statements for discussion of the MISO ROE Complaints.

~~Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT)~~ — In 2015, NSP-Minnesota and NSP-Wisconsin filed changes to their transmission formula rates to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings were intended to ensure that NSP-Minnesota and NSP-Wisconsin are in compliance with IRS rules and may continue to use accelerated tax depreciation. In December 2015, the FERC partially accepted the proposed NSP-Minnesota and NSP-Wisconsin transmission formula rate changes, but rejected changes regarding the treatment of ADIT in the formula rate true-up. In September 2016, FERC issued an order clarifying that NSP-Minnesota and NSP-Wisconsin may incorporate ADIT true-up provisions in their formula rate. However, submission of a new tariff change filing is required to implement the change. NSP-Minnesota and NSP-Wisconsin expect to file a change to their transmission formula rate in the fourth quarter of 2016 and will request a Jan. 1, 2016 effective date.

~~Southwest Power Pool, Inc. (SPP) and MISO Complaints Regarding RTO Joint Operating Agreement (JOA)~~ —SPP and MISO were involved in a long-running dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagreed over MISO’s authority to transmit power between the traditional MISO region in the Midwest and the Entergy system. Several cases were filed with the FERC by MISO and SPP between 2011 and 2014.

~~Table of Contents~~

In January 2016, the FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provides a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period (February 2014 to January 2016) and $16 million annually prospectively starting Feb. 1, 2016, subject to a true-up. In January 2016, SPP filed a proposal regarding distribution of the MISO revenues to SPP members, including SPS. In March 2016, the FERC issued an order rejecting one component of the SPP filing, accepting the remainder of the SPP tariff proposal subject to refund. In August 2016, MISO and other parties filed a settlement regarding the April 2014 MISO tariff change filing to recover SPP JOA charges in MISO rates. The settlement is pending FERC approval. NSP-Minnesota and NSP-Wisconsin expect to be able to recover any resulting MISO charges in retail rates. The JOA revenue allocated to SPS under the filed SPP proposal was not expected to be material.

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 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, 2016,~~March 31, 2017, 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

~~Effective January~~In 2016, NSP-Wisconsin implemented the general ledger modules, as well as initiated deployment of work management systems modules, of a new enterprise resource planning ~~(ERP)~~ system to improve certain financial and related transaction processes. ~~During 2016 and 2017,~~ NSP-Wisconsin ~~will continue implementing~~is continuing to implement additional modules ~~and expects to begin~~including the conversion of existing work management systems to this ~~new ERP system.~~same system during 2017. In connection with this ongoing implementation, NSP-Wisconsin ~~has updated and will continue~~is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting ~~procedures.~~systems. NSP-Wisconsin does not ~~expect the~~believe that this implementation ~~of the additional modules to materially affect~~will have an adverse effect on its internal control over financial reporting.

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

Table of Contents

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 Part I Item 2 and Note 5 to the consolidated financial statements for a 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, ~~2015,~~2016, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

~~Table of Contents~~

~~Item 4~~ — ~~MINE SAFETY DISCLOSURES~~

~~None.~~

~~Item 5~~ — ~~OTHER INFORMATION~~

~~None.~~

Item 6 — EXHIBITS



*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors



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*+~~	Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to Form 10-Q of Xcel Energy dated Oct. 28, 2016 (file no. 001-03034)).
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, 2016~~March 31, 2017 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)

~~Oct. 31, 2016~~April 28, 2017	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			Staff Recommendation			Final Decision
Rate base investments	$	11.0		$	7.6		7.6
Generation and transmission expenses (excluding fuel and purchased power) ^(a)	6.8			6.1			6.1
Fuel and purchased power expenses	11.0			7.7			10.7
Subtotal	28.8			21.4			24.4
2015 fuel refund ^(b)	(9.5		)	—			—
Department of Energy settlement refund	(1.9		)	(1.9		)	(1.9		)
Total electric rate increase	$	17.4		$	19.5		$	22.5

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

March 31, 2017

Dec. 31, 2016

Million British thermal units of natural gas