Northern States Power 10-Q 31 Oct 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO /WI/
Entity Central Index Key	72,909
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		933,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating revenues
Electric	$ 232,216	$ 224,666	$ 646,619	$ 634,571
Natural gas	13,646	11,088	72,671	91,273
Other	282	407	877	1,090
Total operating revenues	246,144	236,161	720,167	726,934
Operating expenses
Electric fuel and purchased power, non-affiliates	4,238	2,624	11,870	5,066
Purchased power, affiliates	105,734	102,297	311,301	318,542
Cost of natural gas sold and transported	6,081	4,375	35,964	54,933
Operating and maintenance expenses	49,235	46,292	148,370	134,126
Conservation program expenses	3,308	2,977	9,468	8,821
Depreciation and amortization	24,700	23,019	72,869	66,908
Taxes (other than income taxes)	6,506	7,045	20,757	21,151
Loss on Monticello life cycle management/extended power uprate project	0	0	0	5,237
Total operating expenses	199,802	188,629	610,599	614,784
Operating income	46,342	47,532	109,568	112,150
Other (expense) income, net	(102)	100	424	384
Allowance for funds used during construction — equity	1,241	1,929	2,969	5,926
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
Allowance for funds used during construction — debt	(525)	(931)	(1,264)	(2,865)
Total interest charges and financing costs	8,088	7,694	24,536	21,287
Income before income taxes	39,393	41,867	88,425	97,173
Income taxes	15,172	15,635	33,948	36,162
Net income	$ 24,221	$ 26,232	$ 54,477	$ 61,011

CONSOLIDATED STATEMENTS OF INC3

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Interest charges and financing costs
Other financing costs	$ 465	$ 461	$ 1,388	$ 1,273

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Comprehensive income:
Net income	$ 24,221	$ 26,232	$ 54,477	$ 61,011
Derivative instruments:
Reclassification of losses to net income, net of tax of $13, $13, $38 and $37, 2016 and 2015, respectively	19	19	57	57
Other comprehensive income	19	19	57	57
Comprehensive income	$ 24,240	$ 26,251	$ 54,534	$ 61,068

CONSOLIDATED STATEMENTS OF COM5

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative instruments:
Reclassification of losses to net income, net of tax	$ 13	$ 13	$ 38	$ 37

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities
Net income	$ 54,477	$ 61,011
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	74,014	67,936
Deferred income taxes	27,769	38,595
Amortization of investment tax credits	(396)	(396)
Allowance for equity funds used during construction	(2,969)	(5,926)
Loss on Monticello life cycle management/extended power uprate project	0	5,237
Net derivative losses	112	338
Changes in operating assets and liabilities:
Accounts receivable	9,394	10,026
Accrued unbilled revenues	8,203	12,657
Inventories	1,290	2,847
Other current assets	7,791	14,471
Accounts payable	11,946	(25,023)
Net regulatory assets and liabilities	(10,256)	(13,962)
Other current liabilities	1,523	5,948
Pension and other employee benefit obligations	(6,256)	(3,931)
Change in other noncurrent assets	(402)	11
Change in other noncurrent liabilities	1,918	595
Net cash provided by operating activities	178,158	170,434
Investing activities
Utility capital/construction expenditures	(138,616)	(171,586)
Allowance for equity funds used during construction	2,969	5,926
Other, net	781	(90)
Net cash used in investing activities	(134,866)	(165,750)
Financing activities
Repayments of short-term borrowings, net	(6,000)	(78,000)
Proceeds from issuance of long-term debt	0	98,038
Repayments of long-term debt	(44)	0
Capital contributions from parent	1,108	25,060
Dividends paid to parent	(38,414)	(40,265)
Net cash (used in) provided by financing activities	(43,350)	4,833
Net change in cash and cash equivalents	(58)	9,517
Cash and cash equivalents at beginning of period	1,079	1,285
Cash and cash equivalents at end of period	1,021	10,802
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(21,692)	(18,647)
Cash (paid) received for income taxes, net	(2,298)	9,662
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 16,011	$ 13,520

CONSOLIDATED BALANCE SHEETS (UN

CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents		$ 1,021	$ 1,079
Accounts receivable, net	[1]	47,811	56,378
Accrued unbilled revenues		39,495	47,698
Inventories		20,269	21,559
Regulatory assets		13,567	16,146
Prepaid taxes		17,495	25,976
Deferred income taxes		7,671	3,138
Prepayments and other		3,187	2,387
Total current assets		150,516	174,361
Property, plant and equipment, net		1,901,696	1,828,079
Other assets
Regulatory assets		292,969	289,196
Other investments		3,259	4,042
Other		471	67
Total other assets		296,699	293,305
Total assets		2,348,911	2,295,745
Current liabilities
Current portion of long-term debt		1,138	1,131
Short-term debt		4,000	10,000
Notes payable to affiliates		500	500
Accounts payable		38,153	34,317
Accounts payable to affiliates		30,386	24,538
Dividends payable to parent		14,687	15,322
Regulatory liabilities		17,546	11,781
Environmental liabilities		16,366	17,155
Accrued interest		9,615	7,945
Other		13,226	15,778
Total current liabilities		145,617	138,467
Deferred credits and other liabilities
Deferred income taxes		428,051	393,569
Deferred investment tax credits		8,164	8,560
Regulatory liabilities		146,247	141,289
Environmental liabilities		68,419	77,441
Customer advances		19,678	18,480
Pension and employee benefit obligations		43,461	49,889
Other		16,858	16,347
Total deferred credits and other liabilities		730,878	705,575
Commitments and contingencies
Capitalization
Long-term debt		661,796	661,318
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
Additional paid in capital		398,033	394,553
Retained earnings		319,439	302,741
Accumulated other comprehensive loss		(152)	(209)
Total common stockholder’s equity		810,620	790,385
Total liabilities and equity		$ 2,348,911	$ 2,295,745
[1]	Accounts receivable, net includes an immaterial amount due from affiliates as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

CONSOLIDATED BALANCE SHEETS (U8

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
Capitalization
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, par value (in dollars per share)	$ 100	$ 100
Common stock, shares outstanding (in shares)	933,000	933,000

Management's Opinion

Management's Opinion	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Management's Opinion	In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Wisconsin and its subsidiaries as of Sept. 30, 2016 and Dec. 31, 2015 ; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2016 and 2015; and its cash flows for the nine months ended Sept. 30, 2016 and 2015. 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 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 balance sheet information has been derived from the audited 2015 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2015 . 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 , filed with the SEC on Feb. 22, 2016. 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2015, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Accounting Pronouncements

Accounting Pronouncements	9 Months Ended
	Sep. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Pronouncements	Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09) , which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. The guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. 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 material impact on its consolidated financial statements. 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 and disclosure requirements, 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. Under the new guidance, 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 the impact of adopting ASU 2016-01 on its consolidated financial statements. Leases — In 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 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 adoption is permitted. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2016-02 on its consolidated financial statements. Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. 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.

Selected Balance Sheet Data

Selected Balance Sheet Data	9 Months Ended
	Sep. 30, 2016
Balance Sheet Related Disclosures [Abstract]
Selected Balance Sheet Data	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 (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 (a) Accounts receivable, net includes an immaterial amount due from affiliates as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including a 2009 carryback claim. As of Sept. 30, 2016, 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, the 2013 through 2014 claims, and the anticipated claim for 2015. 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 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 . As of Sept. 30, 2016, the IRS had not proposed any 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, 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, 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). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2016 Dec. 31, 2015 Unrecognized tax benefit — Permanent tax positions $ 0.3 $ 0.2 Unrecognized tax benefit — Temporary tax positions 5.0 4.3 Total unrecognized tax benefit $ 5.3 $ 4.5 The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2016 Dec. 31, 2015 NOL and tax credit carryforwards $ (1.1 ) $ (0.9 ) It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals 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 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2016 or Dec. 31, 2015.

Rate Matters Rate Matters (Note

Rate Matters Rate Matters (Notes)	9 Months Ended
	Sep. 30, 2016
Public Utilities, General Disclosures [Abstract]
Rate Matters	Rate Matters Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 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. 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 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, 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 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 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. In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on $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 . Pending Regulatory Proceedings — 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 (RTO) membership and for being an independent transmission company), effective Nov. 12, 2013. In December 2015, an administrative law judge (ALJ) initial decision recommended the FERC approve a ROE of 10.32 percent , which the FERC upheld in an order issued on Sept. 28, 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 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 . On June 30, 2016, the ALJ issued an initial decision recommending a ROE of 9.7 percent , the midpoint of the upper half of the discounted cash flow (DCF) range. A FERC decision is expected in 2017. As of Sept. 30, 2016, 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 a current liability representing the best estimate of the

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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. 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 Guarantee issued and outstanding $ 1.0 $ 1.0 Current exposure under this guarantee 0.1 0.1 Environmental Contingencies Ashland MGP Site — NSP-Wisconsin has been named a potentially responsible party 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). 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). The current cost estimate for the cleanup of the Phase I Project Area is approximately $71.4 million , of which approximately $52.6 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 the EPA and NSP-Wisconsin regarding the performance of the full scale cleanup of the Sediments. If a court-approved settlement can be reached with the EPA, NSP-Wisconsin anticipates a full scale wet dredge remedy of the Sediments could be performed beginning as early as 2017, and potentially conclude by 2018. At Sept. 30, 2016 and Dec. 31, 2015, NSP-Wisconsin had recorded a total liability of $84.6 million and $94.4 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 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 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, the annual recovery of MGP clean-up costs would increase from $7.6 million in 2016 to $12.4 million in 2017. Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide and nitrogen oxide (NOx) from utilities in the eastern half of the United States, including Wisconsin, using an emissions trading program. CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone National Ambient Air Quality Standard (NAAQS) and the 1997 and 2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. The EPA adopted a final rule in September 2016 for the ozone season emission budget for NOx which did not materially impact NSP-Wisconsin. 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 multi-district litigation (MDL) matter remains and it consists 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 2016, the MDL judge granted summary judgment dismissing defendants from the Farmland lawsuit. e prime and Xcel Energy have 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 e prime defendants filed a summary judgment motion in the 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. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

Borrowings and Other Financing

Borrowings and Other Financing Instruments	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Borrowings and Other Financing Instruments	Borrowings and Other Financing Instruments Commercial Paper — NSP-Wisconsin meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Wisconsin was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2016 Year Ended Dec. 31, 2015 Borrowing limit $ 150 $ 150 Amount outstanding at period end 4 10 Average amount outstanding 6 39 Maximum amount outstanding 23 122 Weighted average interest rate, computed on a daily basis 0.60 % 0.44 % Weighted average interest rate at period end 0.60 0.70 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 and Dec. 31, 2015 , there were no letters of credit outstanding. Credit Facility — In order to use its commercial paper program, NSP-Wisconsin must have a 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 credit facility capacity. 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 , NSP-Wisconsin had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 150 $ 4 $ 146 (a) This credit facility expires in June 2021 . (b) Includes outstanding commercial paper. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the credit facility outstanding at Sept. 30, 2016 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. 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 Notes payable to affiliates $ 0.5 $ 0.5 Weighted average interest rate at period end 0.77 % 0.87 %

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the measurement 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. 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 , accumulated other comprehensive loss related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. Commodity Derivatives — NSP-Wisconsin may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of natural gas to generate electric energy and natural gas for resale. The following table details the gross notional amounts of commodity options at Sept. 30, 2016 and Dec. 31, 2015 : (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. 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 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 . During the three and nine months ended Sept. 30, 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. 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 million and $1.0 million were recognized for the nine months ended Sept. 30, 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 and 2015 . 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 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. 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, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis: 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 Fair Value Fair Value Total Counterparty Netting (a) Total (c) (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Natural gas commodity $ — $ 15 $ — $ 15 $ (11 ) $ 4 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 . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) Included in other current assets balance of $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 million at Dec. 31, 2015, in the consolidated balance sheets. Fair Value of Long-Term Debt As of Sept. 30, 2016 and Dec. 31, 2015 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2016 Dec. 31, 2015 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion (a) $ 662,934 $ 781,939 $ 662,449 $ 742,565 (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 and Dec. 31, 2015 , and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

Other (Expense) Income, Net

Other (Expense) Income, Net	9 Months Ended
	Sep. 30, 2016
Other Income and Expenses [Abstract]
Other (Expense) Income, Net	Other (Expense) Income, Net Other (expense) income, net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2016 2015 2016 2015 Interest (expense) income $ (73 ) $ 11 $ 65 $ 299 Other nonoperating income 33 72 299 202 Insurance policy (expense) income (58 ) 20 70 (109 ) Other nonoperating expense (4 ) (3 ) (10 ) (8 ) Other (expense) income, net $ (102 ) $ 100 $ 424 $ 384

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Segment Information	Segment Information Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Wisconsin’s chief operating decision maker. NSP-Wisconsin evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. NSP-Wisconsin has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • NSP-Wisconsin’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Wisconsin and Michigan. • NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas primarily in portions of Wisconsin and Michigan. • Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include investments in rental housing projects that qualify for low-income housing tax credits. Asset and capital expenditure information is not provided for NSP-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended 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 Three Months Ended Sept. 30, 2015 Operating revenues (a) $ 224,666 $ 11,088 $ 407 $ — $ 236,161 Intersegment revenues 101 177 — (278 ) — Total revenues $ 224,767 $ 11,265 $ 407 $ (278 ) $ 236,161 Net income (loss) $ 28,285 $ (1,993 ) $ (60 ) $ — $ 26,232 (a) Operating revenues include $44 million and $42 million of affiliate electric revenue for the three months ended Sept. 30, 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.

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost Three Months Ended Sept. 30 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 Nine Months Ended Sept. 30 2016 2015 2016 2015 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 3,312 $ 3,570 $ 18 $ 21 Interest cost 5,112 4,890 489 490 Expected return on plan assets (6,867 ) (7,113 ) (18 ) (23 ) Amortization of prior service cost (credit) 84 83 (264 ) (263 ) Amortization of net loss 4,044 5,103 249 342 Net benefit cost recognized for financial reporting $ 5,685 $ 6,533 $ 474 $ 567 In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $7.4 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during 2016.

Other Comprehensive Income

Other Comprehensive Income	9 Months Ended
	Sep. 30, 2016
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 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 (Thousands of Dollars) Nine Months Ended Sept. 30, 2016 Nine Months Ended Sept. 30, 2015 Accumulated other comprehensive loss at Jan. 1 $ (209 ) $ (285 ) Losses reclassified from net accumulated other comprehensive loss 57 57 Net current period other comprehensive income 57 57 Accumulated other comprehensive loss at Sept. 30 $ (152 ) $ (228 ) Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 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 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2016 Nine Months Ended Sept. 30, 2015 Losses on cash flow hedges: Interest rate derivatives $ 95 (a) $ 94 (a) Total, pre-tax 95 94 Tax benefit (38 ) (37 ) Total amounts reclassified, net of tax $ 57 $ 57 (a) Included in interest charges.

Selected Balance Sheet Data (Ta

Selected Balance Sheet Data (Tables)	9 Months Ended
	Sep. 30, 2016
Balance Sheet Related Disclosures [Abstract]
Accounts Receivable, Net	(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	[1]
Inventories	(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
Property, Plant and Equipment, Net	(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
[1]	Accounts receivable, net includes an immaterial amount due from affiliates as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2016 Dec. 31, 2015 Unrecognized tax benefit — Permanent tax positions $ 0.3 $ 0.2 Unrecognized tax benefit — Temporary tax positions 5.0 4.3 Total unrecognized tax benefit $ 5.3 $ 4.5
Tax Benefits Associated with NOL and Tax Credit Carryforwards	The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2016 Dec. 31, 2015 NOL and tax credit carryforwards $ (1.1 ) $ (0.9 )

Rate Matters Rate Matters (Tabl

Rate Matters Rate Matters (Tables)	9 Months Ended
	Sep. 30, 2016
Public Utilities, General Disclosures [Abstract]
NSP-WI 2017 Electric Rate Request [Table Text Block]	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. 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 .

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Guarantees Issued and Outstanding	The following table presents the guarantee issued and outstanding for NSP-Wisconsin: (Millions of Dollars) Sept. 30, 2016 Dec. 31, 2015 Guarantee issued and outstanding $ 1.0 $ 1.0 Current exposure under this guarantee 0.1 0.1

Borrowings and Other Financin26

Borrowings and Other Financing Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Borrowings and Other Financing Instruments [Abstract]
Credit Facilities	At Sept. 30, 2016 , NSP-Wisconsin had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 150 $ 4 $ 146 (a) This credit facility expires in June 2021 . (b) Includes outstanding commercial paper.
Commercial Paper
Borrowings and Other Financing Instruments [Abstract]
Short-Term Borrowings	Commercial paper outstanding for NSP-Wisconsin was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2016 Year Ended Dec. 31, 2015 Borrowing limit $ 150 $ 150 Amount outstanding at period end 4 10 Average amount outstanding 6 39 Maximum amount outstanding 23 122 Weighted average interest rate, computed on a daily basis 0.60 % 0.44 % Weighted average interest rate at period end 0.60 0.70
Notes Payable To Affiliates
Borrowings and Other Financing Instruments [Abstract]
Short-Term Borrowings	Other Short-Term Borrowings — The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.: (Amounts in Millions, Except Interest Rates) Sept. 30, 2016 Dec. 31, 2015 Notes payable to affiliates $ 0.5 $ 0.5 Weighted average interest rate at period end 0.77 % 0.87 %

Fair Value of Financial Asset27

Fair Value of Financial Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Gross Notional Amounts of Commodity Forwards and Options	The following table details the gross notional amounts of commodity options at Sept. 30, 2016 and Dec. 31, 2015 : (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.
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level	Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis: 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 Fair Value Fair Value Total Counterparty Netting (a) Total (c) (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Natural gas commodity $ — $ 15 $ — $ 15 $ (11 ) $ 4 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 . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) Included in other current assets balance of $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 million at Dec. 31, 2015, in the consolidated balance sheets.
Carrying Amount and Fair Value of Long-term Debt	As of Sept. 30, 2016 and Dec. 31, 2015 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2016 Dec. 31, 2015 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion (a) $ 662,934 $ 781,939 $ 662,449 $ 742,565 (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.

Other (Expense) Income, Net (Ta

Other (Expense) Income, Net (Tables)	9 Months Ended
	Sep. 30, 2016
Other Income and Expenses [Abstract]
Other (Expense) Income, Net	Other (expense) income, net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2016 2015 2016 2015 Interest (expense) income $ (73 ) $ 11 $ 65 $ 299 Other nonoperating income 33 72 299 202 Insurance policy (expense) income (58 ) 20 70 (109 ) Other nonoperating expense (4 ) (3 ) (10 ) (8 ) Other (expense) income, net $ (102 ) $ 100 $ 424 $ 384

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	(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 Three Months Ended Sept. 30, 2015 Operating revenues (a) $ 224,666 $ 11,088 $ 407 $ — $ 236,161 Intersegment revenues 101 177 — (278 ) — Total revenues $ 224,767 $ 11,265 $ 407 $ (278 ) $ 236,161 Net income (loss) $ 28,285 $ (1,993 ) $ (60 ) $ — $ 26,232 (a) Operating revenues include $44 million and $42 million of affiliate electric revenue for the three months ended Sept. 30, 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.

Benefit Plans and Other Postr30

Benefit Plans and Other Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Cost	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 Nine Months Ended Sept. 30 2016 2015 2016 2015 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 3,312 $ 3,570 $ 18 $ 21 Interest cost 5,112 4,890 489 490 Expected return on plan assets (6,867 ) (7,113 ) (18 ) (23 ) Amortization of prior service cost (credit) 84 83 (264 ) (263 ) Amortization of net loss 4,044 5,103 249 342 Net benefit cost recognized for financial reporting $ 5,685 $ 6,533 $ 474 $ 567

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2016
Stockholders' Equity Note [Abstract]
Changes in Accumulated Other Comprehensive Loss, Net of Tax	Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 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 (Thousands of Dollars) Nine Months Ended Sept. 30, 2016 Nine Months Ended Sept. 30, 2015 Accumulated other comprehensive loss at Jan. 1 $ (209 ) $ (285 ) Losses reclassified from net accumulated other comprehensive loss 57 57 Net current period other comprehensive income 57 57 Accumulated other comprehensive loss at Sept. 30 $ (152 ) $ (228 )
Reclassifications out of Accumulated Other Comprehensive Loss	Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 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 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2016 Nine Months Ended Sept. 30, 2015 Losses on cash flow hedges: Interest rate derivatives $ 95 (a) $ 94 (a) Total, pre-tax 95 94 Tax benefit (38 ) (37 ) Total amounts reclassified, net of tax $ 57 $ 57 (a) Included in interest charges.

Accounting Pronouncements Debt

Accounting Pronouncements Debt Issuance Costs (Details) - Accounting Standards Update 2015-03 - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Long-term Debt
Debt Instrument [Line Items]
Reclassification of deferred debt issuance costs, net	$ 5	$ 5.1
Other Noncurrent Assets
Debt Instrument [Line Items]
Reclassification of deferred debt issuance costs, net		$ (5.1)

Selected Balance Sheet Data, Ac

Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
Accounts Receivable, Net
Accounts receivable		$ 52,270	$ 61,506
Less allowance for bad debts		(4,459)	(5,128)
Accounts receivable, net	[1]	$ 47,811	$ 56,378
[1]	Accounts receivable, net includes an immaterial amount due from affiliates as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

Selected Balance Sheet Data, In

Selected Balance Sheet Data, Inventory (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 20,269	$ 21,559
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	7,100	6,785
Fuel
Public Utilities, Inventory [Line Items]
Inventories	4,887	6,528
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 8,282	$ 8,246

Selected Balance Sheet Data, Pr

Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 3,009,780	$ 2,885,022
Less accumulated depreciation	(1,108,084)	(1,056,943)
Property, plant and equipment, net	1,901,696	1,828,079
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,471,420	2,411,562
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	285,829	275,376
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	134,988	132,329
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 117,543	$ 65,755

Income Taxes (Details)

Income Taxes (Details) - USD ($)	1 Months Ended	9 Months Ended		12 Months Ended
	Aug. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2012	Dec. 31, 2015
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions		$ 300,000			$ 200,000
Unrecognized tax benefit — Temporary tax positions		5,000,000			4,300,000
Total unrecognized tax benefit		5,300,000			4,500,000
NOL and tax credit carryforwards		(1,100,000)			(900,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible		2,000,000
Amounts accrued for penalties related to unrecognized tax benefits		0			$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination			2012 and 2013	2010 and 2011
Year of carryback claim under examination				2,009
Potential Tax Adjustments		$ 14,000,000
Earliest year subject to examination		2,009
State Jurisdiction (Wisconsin)
Tax Audits [Abstract]
Year(s) under examination	2012 and 2013
Earliest year subject to examination		2,012

Rate Matters Rate Matters (Deta

Rate Matters Rate Matters (Details)

Oct. 26, 2016USD ($)

Sep. 28, 2016

Jun. 30, 2016

Oct. 31, 2016USD ($)

Aug. 31, 2016USD ($)

Jul. 31, 2016USD ($)

Apr. 30, 2016USD ($)

Mar. 31, 2015USD ($)

Feb. 28, 2015

Nov. 30, 2013

Sep. 30, 2016USD ($)

Sep. 30, 2015USD ($)

Mar. 31, 2015USD ($)

Sep. 30, 2016USD ($)

Sep. 30, 2015USD ($)

Dec. 31, 2015MW

Dec. 31, 2013USD ($)

Dec. 31, 2008USD ($)

Public Utilities, General Disclosures [Line Items]

Loss on Monticello life cycle management/extended power uprate project

$ 0

$ 0

$ 0

$ 5,237,000

NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 17,400,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

2.40%

Public Utilities, Requested Rate Base, Amount

$ 1,188,000,000

Public Utilities, Requested Increase Related to Rate Base Investments

11,000,000

Public Utilities, Requested Increase Related to Generation and Transmission Expenses

6,800,000

Public Utilities, Requested Increase Related to Fuel and Purchased Power Expenses

11,000,000

Public Utilities, Total Requested Rate Increase Excluding Refunds

28,800,000

Public Utilities, Requested Decrease Related to Fuel Refunds

(9,500,000)

Public Utilities, Requested Decrease Related to Settlement Refund

(1,900,000)

NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017 | Public Service Commission of Wisconsin (PSCW) Staff [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 19,500,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

2.70%

Public Utilities, Difference Between Filed Request and PSCW Staff Recommendation

$ 7,400,000

Public Utilities, Requested Increase Related to Rate Base Investments

7,600,000

Public Utilities, Requested Increase Related to Generation and Transmission Expenses

6,100,000

Public Utilities, Requested Increase Related to Fuel and Purchased Power Expenses

7,700,000

Public Utilities, Total Requested Rate Increase Excluding Refunds

21,400,000

Public Utilities, Requested Decrease Related to Fuel Refunds

0

Public Utilities, Requested Decrease Related to Settlement Refund

(1,900,000)

NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017 | Public Service Commission of Wisconsin (PSCW)

Public Utilities, General Disclosures [Line Items]

Public Utilities, Adjustment to Rate Request Related to Fuel Refund

$ 9,500,000

Public Utilities, Revised Requested Rate Increase, Amount

$ 29,900,000

Public Utilities, Revised Requested Rate Increase, Percentage

4.20%

NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Gas Rates 2017

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 4,800,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

3.90%

NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Gas Rates 2017 | Public Service Commission of Wisconsin (PSCW) Staff [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 4,800,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

3.90%

NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Return on Equity, Percentage

10.00%

Public Utilities, Percentage of Excess Earnings to be Refunded due to Earnings Cap

100.00%

NSP-Wisconsin | MPUC Proceeding - Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Loss on Monticello life cycle management/extended power uprate project

$ 5,000,000

NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Nuclear Project Expenditures, Amount

$ 665,000,000

Total Capitalized Nuclear Project Costs

$ 748,000,000

Initial Estimated Nuclear Project Expenditures

$ 320,000,000

NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | Minnesota Public Utilities Commission

Public Utilities, General Disclosures [Line Items]

Public Utilities, Amount Of Recoverable Investment, With Return

$ 415,000,000

Public Utilities, Amount Of Recoverable Investment, Without A Return

$ 333,000,000

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint

Public Utilities, General Disclosures [Line Items]

Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates

12.38%

12.38%

Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties

8.67%

9.15%

Public Utilities, Maximum Equity Capital Structure Percentage Allowed Per The Complaint

50.00%

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | Administrative Law Judge

Public Utilities, General Disclosures [Line Items]

Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties

9.70%

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | MPUC, NDPSC, SDPUC, and DOC

Public Utilities, General Disclosures [Line Items]

Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties

8.81%

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | FERC Staff

Public Utilities, General Disclosures [Line Items]

Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties

8.78%

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | MISO TOs

Public Utilities, General Disclosures [Line Items]

Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties

10.92%

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | Federal Energy Regulatory Commission (FERC)

Public Utilities, General Disclosures [Line Items]

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved

10.32%

Public Utilities, Length of Refund Period, In Months

15 months

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved

10.82%

Public Utilities, ROE Basis Point Adder, Approved

50

Xcel Energy Inc. | MPUC Proceeding - Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Loss on Monticello life cycle management/extended power uprate project

$ 129,000,000

Minimum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Public Utilities, Facility Generating Capacity, In MW | MW

600

Maximum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Public Utilities, Facility Generating Capacity, In MW | MW

671

Subsequent Event [Member] | NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017 | Public Service Commission of Wisconsin (PSCW)

Public Utilities, General Disclosures [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 22,500,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.20%

Public Utilities, Approved Increase Related to Rate Base Investments

$ 7,600,000

Public Utilities, Approved Increase Related to Generation and Transmission Expenses

6,100,000

Public Utilities, Approved Increase Related to Fuel and Purchased Power Expenses

10,700,000

Public Utilities, Total Approved Rate Increase, Excluding Refunds

24,400,000

Public Utilities, Approved Decrease Related to Fuel Refunds

0

Public Utilities, Approved Decrease Related to Settlement Refund

(1,900,000)

Subsequent Event [Member] | NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Gas Rates 2017 | Public Service Commission of Wisconsin (PSCW)

Public Utilities, General Disclosures [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 4,800,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.90%

Subsequent Event [Member] | NSP-Wisconsin | MPSC Proceeding - Michigan 2017 Natural Gas Rate Case [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 347,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

6.50%

Public Utilities, Requested Rate Base, Amount

$ 6,400,000

Public Utilities, Requested Return on Equity, Percentage

10.20%

Public Utilities, Requested Equity Capital Structure, Percentage

52.56%

Public Utilities, Requested Rider Revenue, Amount

$ 129,000

Public Utilities, Requested Rider Revenue, Percentage

2.40%

Commitments and Contingencies,

Commitments and Contingencies, Guarantees and Indemnifications (Details) - USD ($)	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Guarantor Obligations [Line Items]
Assets Held As Collateral	$ 0	$ 0
Payment or Performance Guarantee | Customer Loans for Farm Rewiring Program
Guarantor Obligations [Line Items]
Payment Guarantee Expiration (year)	2,020
Guarantee issued and outstanding	$ 1,000,000	1,000,000
Current exposure under this guarantee	$ 100,000	$ 100,000

Commitments and Contingencies39

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)Site	Dec. 31, 2017USD ($)	Dec. 31, 2015USD ($)
Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Number of properties not owned included in superfund site | Site	2
Accrual for Environmental Loss Contingencies, Gross	$ 84.6		$ 94.4
Ashland MGP Site - Phase I Project Area
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Accrual for Environmental Loss Contingencies, Gross	71.4
Estimated amount spent on cleanup	$ 52.6
Approved amortization period for recovery of remediation costs in natural gas rates (in years)	10 years
Carrying cost percentage to be applied to unamortized regulatory asset	3.00%
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 | Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Public Utilities, Approved annual recovery collected through base rates	$ 7.6
Scenario, Forecast [Member] | PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2017 | Ashland MGP Site
Ashland Manufactured Gas Plant (MGP) Site [Abstract]
Public Utilities, Requested annual recovery collected through base rates		$ 12.4

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies - Legal Contingencies (Details) - Gas Trading Litigation	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2009
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	1	13
Loss Contingency, Claims Settled, Number	5
Loss Contingency, Claims Dismissed, Number	7
Loss Contingency, Subset of Cases within Multi-District Litigation, Number	2
NSP-Wisconsin
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number		2

Borrowings and Other Financin41

Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 4,000,000	$ 10,000,000
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	150,000,000	150,000,000
Amount outstanding at period end	4,000,000	10,000,000
Average amount outstanding	6,000,000	39,000,000
Maximum amount outstanding	$ 23,000,000	$ 122,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.60%	0.44%
Weighted average interest rate at period end (percentage)	0.60%	0.70%

Borrowings and Other Financin42

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 4,000	$ 10,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 0
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

Borrowings and Other Financin43

Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility - USD ($)		9 Months Ended
		Sep. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Credit Facility	[1]	$ 150,000,000
Drawn	[2]	4,000,000
Available		$ 146,000,000
Debt Instrument, Maturity Date		Jun. 30, 2021
Direct advances on the credit facility outstanding		$ 0	$ 0
[1]	This credit facility expires in June 2021.
[2]	Includes outstanding commercial paper.

Borrowings and Other Financin44

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) - Credit Facility	9 Months Ended
	Sep. 30, 2016USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 150,000,000	[1]
Debt Instrument, Maturity Date	Jun. 30, 2021
NSP-Wisconsin
Line of Credit Facility [Line Items]
Debt Instrument, Term	5 years
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	1
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	1 year
NSP-Wisconsin | Original Terms and Conditions [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date	Oct. 31, 2019
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.875%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.75%
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.075%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.275%
NSP-Wisconsin | Amended Terms and Conditions [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date	Jun. 30, 2021
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.75%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.50%
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.06%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.225%
[1]	This credit facility expires in June 2021.

Borrowings and Other Financin45

Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangement and Other Short-Term Borrowings (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Notes Payable To Affiliates
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Weighted average interest rate at period end (percentage)	0.77%	0.87%

Fair Value of Financial Asset46

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MMBTU in Thousands, $ in Millions		Sep. 30, 2016USD ($)MMBTU	Dec. 31, 2015MMBTU
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $		$ (0.1)
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Options [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	284	388
[1]	Amounts are not reflective of net positions in the underlying commodities.
[2]	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Fair Value of Financial Asset47

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	$ 0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss			100,000	100,000
Other Derivative Instruments | Natural Gas Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	$ (100,000)		(200,000)	(100,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)			$ 600,000	$ 1,000,000

Fair Value of Financial Asset48

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Sep. 30, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Prepayments and other		$ 3,187		$ 2,387
Other Liabilities, Current		13,226		15,778
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]			(11)
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[2]			4
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		114	[3]	4
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	0		(11)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]			183
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]			(11)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				183
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]			(11)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				15
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		114		15
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				194
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				194
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis
Derivatives, Fair Value [Line Items]
Prepayments and other		3,200		2,400
Other Liabilities, Current				15,800
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				15
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 114		15
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				194
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				$ 194
[1]	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. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[2]	Included in other current assets balance of $2.4 million and other current liabilities balance of $15.8 million at Dec. 31, 2015, in the consolidated balance sheets.
[3]	Included in other current assets balance of $3.2 million at Sept. 30, 2016, in the consolidated balance sheets.

Fair Value of Financial Asset49

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion (a)	[1]	$ 662,934	$ 662,449
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion (a)	[1]	$ 781,939	$ 742,565
[1]	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.

Other (Expense) Income, Net (De

Other (Expense) Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Income and Expenses [Abstract]
Interest (expense) income	$ (73)	$ 11	$ 65	$ 299
Other nonoperating income	33	72	299	202
Insurance policy (expense) income	(58)	20	70	(109)
Other nonoperating expense	(4)	(3)	(10)	(8)
Other (expense) income, net	$ (102)	$ 100	$ 424	$ 384

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 246,144		$ 236,161		$ 720,167		$ 726,934
Net income (loss)	24,221		26,232		54,477		61,011
Affiliate electric revenue	44,000		42,000		127,000		121,000
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	232,326		224,767		646,936		634,879
Net income (loss)	25,459		28,285		52,058		57,586	[1]
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	13,743		11,265		72,970		91,748
Net income (loss)	(1,201)		(1,993)		2,426		3,714
All Other
Segment Reporting Information [Line Items]
Operating revenues	282		407		877		1,090
Net income (loss)	(37)		(60)		(7)		(289)
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	246,144	[2]	236,161	[2]	720,167	[3]	726,934	[3]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	232,216	[2]	224,666	[2]	646,619	[3]	634,571	[3]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	13,646		11,088		72,671		91,273
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	282		407		877		1,090
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(207)		(278)		(616)		(783)
Net income (loss)	0		0		0		0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	110		101		317		308
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	97		177		299		475
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0		$ 0		$ 0		$ 0
[1]	(b) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5.
[2]	(a) Operating revenues include $44 million and $42 million of affiliate electric revenue for the three months ended Sept. 30, 2016 and 2015, respectively.
[3]	(a) Operating revenues include $127 million and $121 million of affiliate electric revenue for the nine months ended Sept. 30, 2016 and 2015, respectively.

Benefit Plans and Other Postr52

Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2016USD ($)Plan	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 1,104	$ 1,190	$ 3,312	$ 3,570
Interest cost		1,704	1,630	5,112	4,890
Expected return on plan assets		(2,289)	(2,371)	(6,867)	(7,113)
Amortization of prior service cost (credit)		28	27	84	83
Amortization of net loss		1,348	1,701	4,044	5,103
Net benefit cost recognized for financial reporting		1,895	2,177	5,685	6,533
Total contributions to the pension plans during the period	$ 7,400
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		6	7	18	21
Interest cost		163	164	489	490
Expected return on plan assets		(6)	(8)	(18)	(23)
Amortization of prior service cost (credit)		(88)	(87)	(264)	(263)
Amortization of net loss		83	114	249	342
Net benefit cost recognized for financial reporting		$ 158	$ 190	$ 474	$ 567
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to the pension plans during the period	$ 125,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period			$ 790,385
Accumulated other comprehensive loss at end of period	$ 810,620		810,620
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(171)	$ (247)	(209)	$ (285)
Losses reclassified from net accumulated other comprehensive loss	19	19	57	57
Net current period other comprehensive income	19	19	57	57
Accumulated other comprehensive loss at end of period	$ (152)	$ (228)	$ (152)	$ (228)

Other Comprehensive Income (Rec

Other Comprehensive Income (Reclassification from AOCI) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		$ (39,393)	$ (41,867)	$ (88,425)	$ (97,173)
Tax benefit		15,172	15,635	33,948	36,162
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		32	32	95	94
Tax benefit		(13)	(13)	(38)	(37)
Total, net of tax		19	19	57	57
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	$ 32	$ 32	$ 95	$ 94
[1]	Included in interest charges.