10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)

Minnesota	41-1967505
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
414 Nicollet Mall
Minneapolis, Minnesota	55401
(Address of principal executive offices)	(Zip Code)

(612) 330-5500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller reporting company ¨
(Do not check if smaller reporting company)

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

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

Class	Outstanding at August 4, 2016
Common Stock, $0.01 par value	1,000,000 shares

Northern States Power Company (a Minnesota corporation) meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS

PARTI —	FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 4 —	Controls and Procedures	34
PART II —	OTHER INFORMATION
Item 1 —	Legal Proceedings	34
Item 1A —	Risk Factors	35
Item 4 —	Mine Safety Disclosures	35
Item 5 —	Other Information	35
Item 6 —	Exhibits	35
SIGNATURES		36
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Northern States Power Company, a Minnesota corporation (NSP-Minnesota). NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: NSP-Minnesota; Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Company (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2016			2015			2016			2015
Operating revenues
Electric, non-affiliates	$	903,344		$	882,042		$	1,812,091		$	1,763,321
Electric, affiliates	113,127			117,830			238,023			242,705
Natural gas	64,371			75,239			258,501			354,706
Other	7,258			6,863			14,118			13,724
Total operating revenues	1,088,100			1,081,974			2,322,733			2,374,456
Operating expenses
Electric fuel and purchased power	347,092			384,479			713,258			783,199
Cost of natural gas sold and transported	24,280			37,419			144,503			238,608
Cost of sales — other	4,855			4,467			9,287			8,794
Operating and maintenance expenses	318,540			311,512			639,036			625,562
Conservation program expenses	20,229			14,877			43,498			32,089
Depreciation and amortization	147,444			116,245			293,241			234,320
Taxes (other than income taxes)	65,985			58,487			136,337			122,319
Loss on Monticello life cycle management/extended power uprate project	—			—			—			124,226
Total operating expenses	928,425			927,486			1,979,160			2,169,117
Operating income	159,675			154,488			343,573			205,339
Other (expense) income, net	(587		)	(276		)	2,273			1,685
Allowance for funds used during construction — equity	7,380			5,684			13,028			11,614
Interest charges and financing costs
Interest charges — includes other financing costs of $1,761, $1,637, $3,503, and $3,246, respectively	56,136			49,094			110,151			100,856
Allowance for funds used during construction — debt	(3,278		)	(2,840		)	(5,984		)	(5,754		)
Total interest charges and financing costs	52,858			46,254			104,167			95,102
Income before income taxes	113,610			113,642			254,707			123,536
Income taxes	35,434			39,461			81,902			42,431
Net income	$	78,176		$	74,181		$	172,805		$	81,105

See Notes to Consolidated Financial Statements

3

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30					Six Months Ended June 30
	2016		2015			2016		2015
Net income	$	78,176	$	74,181		$	172,805	$	81,105
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $15, $(2), $26 and ($10), respectively	19		(6		)	38		(12		)
Derivative instruments:
Net fair value increase, net of tax of $5, $6, $4 and $3, respectively	7		9			6		2
Reclassification of losses to net income, net of tax of $151, $148, $305 and $293, respectively	221		214			444		423
	228		223			450		425
Marketable securities:
Net fair value increase, net of tax of $0, $1, $0 and $2, respectively	—		1			—		2
Other comprehensive income	247		218			488		415
Comprehensive income	$	78,423	$	74,399		$	173,293	$	81,520

See Notes to Consolidated Financial Statements

4

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30,
	2016			2015
Operating activities
Net income	$	172,805		$	81,105
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	296,285			237,103
Nuclear fuel amortization	58,267			49,454
Deferred income taxes	47,057			62,445
Amortization of investment tax credits	(840		)	(866		)
Allowance for equity funds used during construction	(13,028		)	(11,614		)
Loss on Monticello life cycle management/extended power uprate project	—			124,226
Net realized and unrealized hedging and derivative transactions	2,725			6,442
Changes in operating assets and liabilities:
Accounts receivable	(15,345		)	78,369
Accrued unbilled revenues	14,731			40,527
Inventories	30,727			5,774
Other current assets	42,890			37,783
Accounts payable	(5,344		)	(35,275		)
Net regulatory assets and liabilities	70,287			15,320
Other current liabilities	(35,304		)	(2,478		)
Pension and other employee benefit obligations	(45,988		)	(29,920		)
Change in other noncurrent assets	(4,460		)	(33		)
Change in other noncurrent liabilities	(6,419		)	(17,436		)
Net cash provided by operating activities	609,046			640,926
Investing activities
Utility capital/construction expenditures	(514,526		)	(610,731		)
Allowance for equity funds used during construction	13,028			11,614
Proceeds from insurance recoveries	—			27,237
Purchases investment securities	(279,566		)	(640,100		)
Proceeds from the sale of investment securities	262,321			636,669
Investments in utility money pool arrangement	(237,000		)	(39,900		)
Repayments from utility money pool arrangement	97,000			39,900
Other, net	(1,242		)	(1,151		)
Net cash used in investing activities	(659,985		)	(576,462		)
Financing activities
Repayments of short-term borrowings, net	(223,000		)	(25,000		)
Borrowings under utility money pool arrangement	424,000			144,500
Repayments under utility money pool arrangement	(424,000		)	(144,500		)
Proceeds from (repayments of) of long-term debt	343,103			(46		)
Capital contributions from parent	89,874			125,935
Dividends paid to parent	(155,726		)	(133,671		)
Net cash provided by (used in) financing activities	54,251			(32,782		)
Net change in cash and cash equivalents	3,312			31,682
Cash and cash equivalents at beginning of period	42,605			40,597
Cash and cash equivalents at end of period	$	45,917		$	72,279
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(100,217	)	$	(93,318	)
Cash received for income taxes, net	4,286			59,175
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	116,698		$	85,735

See Notes to Consolidated Financial Statements

5

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	June 30, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	45,917		$	42,605
Accounts receivable, net	304,837			292,806
Accounts receivable from affiliates	28,044			32,850
Investments in utility money pool arrangement	140,000			—
Accrued unbilled revenues	212,371			227,102
Inventories	313,270			343,916
Regulatory assets	182,052			187,793
Derivative instruments	30,015			18,941
Deferred income taxes	72,661			15,577
Prepayments and other	39,932			89,559
Total current assets	1,369,099			1,251,149
Property, plant and equipment, net	12,928,362			12,807,338
Other assets
Nuclear decommissioning fund and other investments	1,799,298			1,758,208
Regulatory assets	1,191,984			1,159,217
Derivative instruments	22,946			22,334
Other	5,845			1,385
Total other assets	3,020,073			2,941,144
Total assets	$	17,317,534		$	16,999,631
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	10		$	11
Short-term debt	—			223,000
Accounts payable	360,691			350,660
Accounts payable to affiliates	49,929			59,785
Regulatory liabilities	76,957			43,920
Taxes accrued	193,372			225,361
Accrued interest	67,975			66,979
Dividends payable to parent	80,484			73,498
Derivative instruments	17,087			17,211
Customer Deposits	122,235			94,388
Other	133,554			177,795
Total current liabilities	1,102,294			1,332,608
Deferred credits and other liabilities
Deferred income taxes	2,684,664			2,572,087
Deferred investment tax credits	24,998			25,838
Regulatory liabilities	468,757			491,887
Asset retirement obligations	2,388,208			2,331,092
Derivative instruments	120,654			128,213
Pension and employee benefit obligations	292,938			339,663
Other	134,044			114,768
Total deferred credits and other liabilities	6,114,263			6,003,548
Commitments and contingencies
Capitalization
Long-term debt	4,841,577			4,496,410
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively	10			10
Additional paid in capital	3,405,564			3,323,810
Retained earnings	1,874,419			1,864,326
Accumulated other comprehensive loss	(20,593		)	(21,081		)
Total common stockholder’s equity	5,259,400			5,167,065
Total liabilities and equity	$	17,317,534		$	16,999,631

See Notes to Consolidated Financial Statements

6

NSP-MINNESOTA AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of June 30, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2016 and 2015; and its cash flows for the six months endedJune 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 June 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-Minnesota 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-Minnesota 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-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Minnesota 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.

2. Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. The guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Minnesota 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-Minnesota 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-Minnesota is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.

7

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-Minnesota 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-Minnesota 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-Minnesota implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, 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-Minnesota implemented the new guidance as required on Jan. 1, 2016, and as a result, $36.9 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 $37.7 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 (NAV) methodology in the fair value hierarchy. NSP-Minnesota implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	322,275		$	313,556
Less allowance for bad debts	(17,438		)	(20,750		)
	$	304,837		$	292,806

(Thousands of Dollars)	June 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	213,237	$	200,888
Fuel	83,974		104,499
Natural gas	16,059		38,529
	$	313,270	$	343,916

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(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	16,394,295		$	16,256,887
Natural gas plant	1,264,860			1,248,408
Common and other property	639,731			624,409
Construction work in progress	785,838			545,535
Total property, plant and equipment	19,084,724			18,675,239
Less accumulated depreciation	(6,495,449		)	(6,251,498		)
Nuclear fuel	2,461,008			2,447,251
Less accumulated amortization	(2,121,921		)	(2,063,654		)
	$	12,928,362		$	12,807,338

4. Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Minnesota’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 Tax Loss Carryback Claims — In 2012, 2013, 2014 and 2015, NSP-Minnesota identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, NSP-Minnesota recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.

Federal Audit — NSP-Minnesota 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 the 2009 carryback claim. As of June 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 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). During the second quarter of 2016 the IRS audit team 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 expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of June 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2016, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In June 2016, Minnesota began an audit of years 2010 through 2014. As of June 30, 2016 Minnesota 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.

9

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

(Millions of Dollars)	June 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	20.8	$	20.1
Unrecognized tax benefit — Temporary tax positions	37.5		35.3
Total unrecognized tax benefit	$	58.3	$	55.4

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

(Millions of Dollars)	June 30, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(16.9	)	$	(15.2	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Minnesota audit progresses, and other state audits resume. As the IRS Appeals and IRS and Minnesota audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $32 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 June 30, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2016 or Dec. 31, 2015.

5. Rate Matters

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

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

Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. The request is detailed in the table below:

Request (Millions of Dollars)	2016			2017			2018
Rate request	$	194.6		$	52.1		$	50.4
Increase percentage	6.4		%	1.7		%	1.7		%
Interim request	$	163.7		$	44.9		N/A
Rate base	$	7,800		$	7,700		$	7,700

In December 2015, the MPUC approved interim rates for 2016.

Intervenor Testimony:

In June 2016, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) subsequently filed revised testimony recommending an increase of approximately $45.6 million in 2016, a step increase of $53.8 million for 2017, and a step decrease of $5.0 million for 2018, based on a recommended ROE of 9.06 percent and an equity ratio of 52.50 percent.

10

Based on NSP-Minnesota’s interpretation of the DOC’s testimony, certain recommended adjustments of approximately $72.7 million would not be expected to impact earnings, assuming MPUC approval. The following table summarizes NSP-Minnesota’s estimate of the DOC’s recommendations:

(Millions of Dollars)	2016			2017 Step			2018 Step			Total
Filed rate request	$	194.6		$	52.1		$	50.4		$	297.1
DOC recommended adjustments:
ROE	(65.0		)	0.3			1.0			(63.7		)
Sales forecast	(39.4		)	—			—			(39.4		)
Property tax	(5.2		)	(0.3		)	(0.1		)	(5.6		)
Depreciation life	(8.0		)	0.4			(2.2		)	(9.8		)
Purchased demand timing changes	—			—			(19.4		)	(19.4		)
Nuclear capital costs	(3.6		)	0.8			(11.2		)	(14.0		)
Tax related items	(12.2		)	18.4			(6.9		)	(0.7		)
Operating and maintenance (O&M)	(15.5		)	(17.8		)	(16.7		)	(50.0		)
Other, net	(0.1		)	(0.1		)	0.1			(0.1		)
Total DOC Adjustments	(149.0		)	1.7			(55.4		)	(202.7		)
Total DOC recommended rate increase	$	45.6		$	53.8		$	(5.0	)	$	94.4
Estimated non-earnings DOC adjustments:
Depreciation life	8.0			(0.4		)	2.2			9.8
Sales forecast	37.4			—			—			37.4
Property tax	5.2			0.3			0.1			5.6
Purchased demand timing changes	—			—			19.4			19.4
Other	0.5			—			—			0.5
Total estimated non-earnings adjustments	51.1			(0.1		)	21.7			72.7
Total pre-tax earnings impact	$	96.7		$	53.7		$	16.7		$	167.1

The DOC also presented several nuclear recommendations related to capital recovery for spent fuel storage investments and Prairie Island life cycle management (LCM) projects.

• The use of certificate of need estimates as a recovery cap, and/or provisionally exclude recovery of amounts in excess of the cap unless the costs are deemed reasonable by the DOC’s nuclear consultant and/or the MPUC.

• No recovery of a portion of capital costs associated with Monticello fuel storage Cask 16, representing the amount beyond the originally anticipated project cost, or approximately $15 million. The additional costs incurred were for testing of cask lid welds to demonstrate compliance with Nuclear Regulatory Commission (NRC) requirements.

Settlement Agreement

In August 2016, NSP-Minnesota reached a settlement in principal with several of the parties, which resolves all revenue requirement issues in dispute. The terms and conditions of the agreement are still subject to final documentation. The settlement agreement requires the approval of the MPUC.

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

• Rebuttal testimony — Aug. 9, 2016;

• Surrebuttal testimony — Sept. 16, 2016;

• Settlement conference — Sept. 26, 2016;

• Evidentiary hearing — Oct. 4-7, 2016;

• Administrative Law Judge report — Feb. 21, 2017; and

• MPUC order — June 1, 2017.

A current liability representing NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of June 30, 2016.

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NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider —In July 2016, the MPUC verbally approved NSP-Minnesota’s request to recover approximately $15 million in natural gas infrastructure costs through the GUIC Rider, based on NSP-Minnesota’s proposed capital structure and a ROE of 9.64 percent, as proposed by the DOC. Recovery was approved for the 15-month period from January 2016 to March 2017.

Annual Automatic Adjustment (AAA) of Charges — In June 2016, the DOC recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. As it pertains to NSP-Minnesota, the DOC’s recommendation could impact replacement power cost recovery for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction during the 2015 AAA fiscal year. NSP-Minnesota expects a MPUC decision in mid-2017.

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello 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 approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014.  As a result of these determinations, 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.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

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

In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent. A FERC order is expected to be issued in late 2016 or in 2017.

In February 2015, a second complaint was filed seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent, prior to any adder.  The FERC set the second complaint for hearings, and established a refund effective date of Feb. 12, 2015. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of either 8.82 percent or 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, with refunds for the 15 month period beginning Feb. 12, 2015. A FERC decision is expected in 2017.

FERC approved of a 50 basis point ROE adder for RTO membership, effective Jan. 6, 2015, subject to the outcome of the ROE complaint. Under FERC policy, the total ROE including the RTO membership adder cannot exceed the top of the DCF range.

NSP-Minnesota has recorded a current liability representing the best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of June 30, 2016. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $8 million and $10 million, annually, for the NSP System.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2015, 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-Minnesota’s financial position.

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Purchased Power Agreements (PPAs)

Under certain PPAs, NSP-Minnesota purchases power from independent power producing entities for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

NSP-Minnesota had approximately 1,069 MW of capacity under long-term PPAs as of June 30, 2016 and Dec. 31, 2015, with entities that have been determined to be variable interest entities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2028.

Guarantees

Under NSP-Minnesota’s railcar lease agreement, accounted for as an operating lease, NSP-Minnesota guarantees the lessor proceeds from sale of the leased assets at the end of the lease term will at least equal the guaranteed residual value. The guarantee issued by NSP-Minnesota limits its exposure to a maximum amount stated in the guarantee; however, NSP-Minnesota expects sale proceeds to exceed the guaranteed amount. This lease agreement expires in 2019.

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

(Millions of Dollars)	June 30, 2016		Dec. 31, 2015
Guarantee issued and outstanding	$	4.8	$	4.8

Environmental Contingencies

Fargo, N.D. Manufactured Gas Plant (MGP) Site — In May 2015, underground pipes, tars and impacted soils were discovered in Fargo, N.D., which may be related to a former MGP site operated by NSP-Minnesota or a prior company. NSP-Minnesota has removed the impacted soils and other materials from the project area. NSP-Minnesota is undertaking further investigation of the location of the historic MGP site and nearby properties. In October 2015, NSP-Minnesota initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until November 2016 to allow NSP-Minnesota time to further investigate site conditions.

As of June 30, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $1.6 million and $2.7 million, respectively, related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as potentially responsible parties. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer the portion of investigation and response costs allocable to the North Dakota jurisdiction.

Environmental Requirements

Water and Waste

Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In April 2015, the United States Environmental Protection Agency (EPA) published a final rule regulating the management and disposal of coal combustion byproducts (coal ash) as a nonhazardous waste. Under the final rule, NSP-Minnesota’s costs to manage and dispose of coal ash has not significantly increased.

In 2015, industry and environmental non-governmental organizations sought judicial review of the final rule. In June 2016, the D.C Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. Oral arguments are expected to be heard in the second half of 2016 and a final decision is anticipated in early 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on NSP-Minnesota.

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Air

Implementation of the National Ambient Air Quality Standard (NAAQS) for Sulfur Dioxide (SO₂) — The EPA adopted a more stringent NAAQS for SO₂ in 2010. The EPA is requiring states to evaluate areas in three phases. If an area is designated as nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due in 18 months, designed to achieve the NAAQS within five years. It is anticipated the areas near NSP-Minnesota’s power plants will be evaluated in the next designation phase, ending December 2017. NSP-Minnesota’s King and Sherco plants already utilize scrubbers to control SO₂ emissions. NSP-Minnesota cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plans are developed. NSP-Minnesota believes that, should SO₂ control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

Legal Contingencies

NSP-Minnesota 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-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

7. Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	25			5
Maximum amount outstanding	117			69
Weighted average interest rate, computed on a daily basis	0.66		%	0.53		%
Weighted average interest rate at period end	N/A			N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	500		$	500
Amount outstanding at period end	—			223
Average amount outstanding	64			96
Maximum amount outstanding	231			327
Weighted average interest rate, computed on a daily basis	0.59		%	0.43		%
Weighted average interest rate at period end	N/A			0.72

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Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2016 and Dec. 31, 2015, there were $18 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program, NSP-Minnesota 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 June 30, 2016, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	18	$	482

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

^(b)  Includes outstanding letters of credit.

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

Amended Credit Agreements - In June 2016, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $500 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-Minnesota has the right to request an extension of the revolving credit facility termination date for two additional one-year periods, subject to majority bank group approval.

Long-Term Borrowings

In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046.

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

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

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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.

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using a net asset value (NAV) methodology, which takes into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities— Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

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.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, referred to as financial transmission rights (FTRs). FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by transmission load and transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity. Unplanned plant outages, scheduled plant maintenance, changes in the costs of fuels used in generation, weather and changes in demand for electricity can each impact the operating schedules of the power plants and the value of an FTR. NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model fair value measurements for FTRs have been assigned a Level 3. Monthly settlements for non-trading FTRs are included in fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

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NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs, given the purpose and legal restrictions on the use of nuclear decommissioning fund assets. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $336.5 million and $328.8 million at June 30, 2016 and Dec. 31, 2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $95.2 million and $100.2 million at June 30, 2016 and Dec. 31, 2015, respectively.

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at June 30, 2016 and Dec. 31, 2015:

	June 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	15,749	$	15,749	$	—	$	—	$	—	$	15,749
Commingled funds	389,700		—		—		—		411,788		411,788
International equity funds	259,090		—		—		—		236,087		236,087
Private equity investments	119,370		—		—		—		166,054		166,054
Real estate	72,956		—		—		—		102,144		102,144
Debt securities:
Government securities	35,199		—		35,828		—		—		35,828
U.S. corporate bonds	96,110		—		91,350		—		—		91,350
International corporate bonds	19,959		—		19,394		—		—		19,394
Municipal bonds	11,966		—		12,826		—		—		12,826
Asset-backed securities	2,844		—		2,881		—		—		2,881
Mortgage-backed securities	10,708		—		11,180		—		—		11,180
Equity securities:
Common stock	479,865		649,521		—		—		—		649,521
Total	$	1,513,516	$	665,270	$	173,459	$	—	$	916,073	$	1,754,802

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $44.5 million of rabbi trust assets and miscellaneous investments.

^(b)  Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

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	Dec. 31, 2015
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	27,484	$	27,484	$	—	$	—	$	—	$	27,484
Commingled funds	392,838		—		—		—		410,634		410,634
International equity funds	259,114		—		—		—		231,122		231,122
Private equity investments	105,965		—		—		—		157,528		157,528
Real estate	61,816		—		—		—		84,750		84,750
Debt securities:
Government securities	24,444		—		21,356		—		—		21,356
U.S. corporate bonds	73,061		—		65,276		—		—		65,276
International corporate bonds	13,726		—		12,801		—		—		12,801
Municipal bonds	49,255		—		51,589		—		—		51,589
Asset-backed securities	2,837		—		2,830		—		—		2,830
Mortgage-backed securities	11,444		—		11,621		—		—		11,621
Equity securities:
Common stock	473,615		647,159		—		—		—		647,159
Total	$	1,495,599	$	674,643	$	165,473	$	—	$	884,034	$	1,724,150

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $34.1 million of miscellaneous investments.

^(b)  Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

For the six months ended June 30, 2016 and 2015 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2016:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	—	$	10,659	$	982	$	24,187	$	35,828
U.S. corporate bonds	261		26,988		59,368		4,733		91,350
International corporate bonds	—		3,966		12,368		3,060		19,394
Municipal bonds	—		212		4,248		8,366		12,826
Asset-backed securities	—		—		2,881		—		2,881
Mortgage-backed securities	—		—		—		11,180		11,180
Debt securities	$	261	$	41,825	$	79,847	$	51,526	$	173,459

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Rabbi Trusts

In June 2016, NSP-Minnesota established a rabbi trust to provide funding for future distributions of its nonqualified pension plan. The following table presents the cost and fair value of the assets held in rabbi trust at June 30, 2016:

	June 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	7,448	$	7,448	$	—	$	—	$	7,448
Mutual funds	1,593		1,778		—		—		1,778
Total	$	9,041	$	9,226	$	—	$	—	$	9,226

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

An immaterial amount of mutual funds were held in rabbi trusts at Dec. 31, 2015.

Derivative Instruments Fair Value Measurements

NSP-Minnesota 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, utility commodity prices and vehicle fuel prices.

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

At June 30, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.8 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 any unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

Commodity Derivatives — NSP-Minnesota enters 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 energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives.

At June 30, 2016, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2016 and 2015.

At June 30, 2016, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

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The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	June 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	71,297	43,611
Million British thermal units of natural gas	42,991	7,971
Gallons of vehicle fuel	39	77

^(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.

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2016 and 2015 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	346	(a)	$	—		$	—
Vehicle fuel and other commodity	12		—			26		(b)	—			—
Total	$	12	$	—		$	372		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	269	(c)
Electric commodity	—		(1,193		)	—			13,572		(d)	—
Natural gas commodity	—		379			—			—			—
Total	$	—	$	(814	)	$	—		$	13,572		$	269

	Six Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	692	(a)	$	—		$	—
Vehicle fuel and other commodity	10		—			57		(b)	—			—
Total	$	10	$	—		$	749		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	1,261		(c)
Electric commodity	—		(2,752		)	—			24,284		(d)	—
Natural gas commodity	—		(253		)	—			3,460		(e)	(1,595		)	(e)
Total	$	—	$	(3,005	)	$	—		$	27,744		$	(334	)

20

	Three Months Ended June 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	346	(a)	$	—			$	—
Vehicle fuel and other commodity	15		—			16		(b)	—				—
Total	$	15	$	—		$	362		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	4,210	(c)
Electric commodity	—		(3,517		)	—			(6,327		)	(d)	—
Natural gas commodity	—		56			—			—			(e)	—		(e)
Total	$	—	$	(3,461	)	$	—		$	(6,327	)		$	4,210

	Six Months Ended June 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	686	(a)	$	—			$	—
Vehicle fuel and other commodity	5		—			30		(b)	—				—
Total	$	5	$	—		$	716		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	7,902	(c)
Electric commodity	—		(12,223		)	—			(11,520		)	(d)	—
Natural gas commodity	—		18			—			(2,751		)	(e)	3,008		(e)
Total	$	—	$	(12,205	)	$	—		$	(14,271	)		$	10,910

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to O&M expenses.

^(c)  Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

^(d)  Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

^(e)  Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and six months ended June 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-Minnesota 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-Minnesota’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.

21

NSP-Minnesota 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.

NSP-Minnesota’s most significant concentrations of credit risk are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At June 30, 2016, five of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $20.1 million or 58 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $6.6 million or 19 percent of this credit exposure, were not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. The remaining two most significant counterparties, comprising $7.1 million or 21 percent of this credit exposure, had credit quality less than investment grade, based on ratings from internal analysis. Nine of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings. At June 30, 2016 and Dec. 31, 2015, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2016 and Dec. 31, 2015.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2016:

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	3,428	$	9,669	$	—	$	13,097	$	(8,067	)	$	5,030
Electric commodity	—		—		24,130		24,130		(642		)	23,488
Natural gas commodity	—		879		—		879		—			879
Total current derivative assets	$	3,428	$	10,548	$	24,130	$	38,106	$	(8,709	)	29,397
PPAs (a)												618
Current derivative instruments												$	30,015
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	997	$	28,051	$	—	$	29,048	$	(6,986	)	$	22,062
Total noncurrent derivative assets	$	997	$	28,051	$	—	$	29,048	$	(6,986	)	22,062
PPAs (a)												884
Noncurrent derivative instruments												$	22,946

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	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	45	$	—	$	45	$	—		$	45
Other derivative instruments:
Commodity trading	3,238		8,319		—		11,557		(8,625		)	2,932
Electric commodity	—		—		642		642		(642		)	—
Total current derivative liabilities	$	3,238	$	8,364	$	642	$	12,244	$	(9,267	)	2,977
PPAs (a)												14,110
Current derivative instruments												$	17,087
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	$	9,710
Total noncurrent derivative liabilities	$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	9,710
PPAs (a)												110,944
Noncurrent derivative instruments												$	120,654

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.7 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	88	$	10,269	$	1,250	$	11,607	$	(5,542	)	$	6,065
Electric commodity	—		—		12,441		12,441		(167		)	12,274
Natural gas commodity	—		128		—		128		(6		)	122
Total current derivative assets	$	88	$	10,397	$	13,691	$	24,176	$	(5,715	)	18,461
PPAs (a)												480
Current derivative instruments												$	18,941
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	27,399	$	—	$	27,399	$	(6,555	)	$	20,844
Total noncurrent derivative assets	$	—	$	27,399	$	—	$	27,399	$	(6,555	)	20,844
PPAs (a)												1,490
Noncurrent derivative instruments												$	22,334

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	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	113	$	—	$	113	$	—		$	113
Other derivative instruments:
Commodity trading	118		7,541		554		8,213		(6,580		)	1,633
Electric commodity	—		—		167		167		(167		)	—
Natural gas commodity	—		1,362		—		1,362		(6		)	1,356
Total current derivative liabilities	$	118	$	9,016	$	721	$	9,855	$	(6,753	)	3,102
PPAs (a)												14,109
Current derivative instruments												$	17,211
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	19,865	$	—	$	19,865	$	(9,780	)	$	10,085
Total noncurrent derivative liabilities	$	—	$	19,865	$	—	$	19,865	$	(9,780	)	10,085
PPAs (a)												118,128
Noncurrent derivative instruments												$	128,213

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at April 1	$	5,124		$	10,972
Purchases	27,870			40,162
Settlements	(6,981		)	(7,294		)
Net transactions recorded during the period:
Gains recognized in earnings (a)	22			1,220
Losses recognized as regulatory assets and liabilities	(2,547		)	(9,697		)
Balance at June 30	$	23,488		$	35,363
	Six Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	12,969		$	40,271
Purchases	27,870			41,025
Settlements	(12,039		)	(18,845		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(2		)	1,280
Losses recognized as regulatory assets and liabilities	(5,310		)	(28,368		)
Balance at June 30	$	23,488		$	35,363

^(a)  These amounts relate to commodity derivatives held at the end of the period.

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NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 2016 and 2015.

Fair Value of Long-Term Debt

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

	June 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,841,587	$	5,730,663	$	4,496,421	$	4,917,080

^(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-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 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.

9. Other (Expense) Income, Net

Other income, net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2016			2015			2016			2015
Interest income	$	129		$	92		$	3,465		$	3,424
Other nonoperating income	107			60			271			92
Insurance policy expense	(823		)	(428		)	(1,463		)	(1,831		)
Other (expense) income, net	$	(587	)	$	(276	)	$	2,273		$	1,685

10. Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Minnesota’s chief operating decision maker. NSP-Minnesota 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-Minnesota has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

• NSP-Minnesota’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.

• NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota and North Dakota.

• 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 appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota 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.

25

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2016
Operating revenues (a)(b)	$	1,016,471	$	64,371	$	7,258		$	—		$	1,088,100
Intersegment revenues	262		86		—			(348		)	—
Total revenues	$	1,016,733	$	64,457	$	7,258		$	(348	)	$	1,088,100
Net income (loss)	$	78,781	$	458	$	(1,063	)	$	—		$	78,176

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2015
Operating revenues (a)(b)	$	999,872	$	75,239		$	6,863		$	—		$	1,081,974
Intersegment revenues	253		106			—			(359		)	—
Total revenues	$	1,000,125	$	75,345		$	6,863		$	(359	)	$	1,081,974
Net income (loss)	$	90,697	$	(16,422	)	$	(94	)	$	—		$	74,181

^(a)  Operating revenues include $113 million and $118 million of affiliate electric revenue for the three months ended June 30, 2016 and 2015, respectively.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2016 and 2015.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2016
Operating revenues (a)(b)	$	2,050,114	$	258,501	$	14,118		$	—		$	2,322,733
Intersegment revenues	407		248		—			(655		)	—
Total revenues	$	2,050,521	$	258,749	$	14,118		$	(655	)	$	2,322,733
Net income (loss)	$	150,102	$	23,600	$	(897	)	$	—		$	172,805

(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2015
Operating revenues (a)(b)	$	2,006,026		$	354,706	$	13,724		$	—		$	2,374,456
Intersegment revenues	386			516		—			(902		)	—
Total revenues	$	2,006,412		$	355,222	$	13,724		$	(902	)	$	2,374,456
Net income (loss)	$	61,098	(c)	$	23,850	$	(3,843	)	$	—		$	81,105

^(a)  Operating revenues include $238 million and $243 million of affiliate electric revenue for the six months ended June 30, 2016 and 2015, respectively.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2016 and 2015.

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

26

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,077		$	7,889		$	31		$	40
Interest cost	11,358			10,803			981			953
Expected return on plan assets	(15,236		)	(15,707		)	(43		)	(30		)
Amortization of prior service cost (credit)	234			234			(759		)	(759		)
Amortization of net loss	9,194			11,548			401			523
Net periodic benefit cost	12,627			14,767			611			727
Costs not recognized due to the effects of regulation	(5,296		)	(7,843		)	—			—
Net benefit cost recognized for financial reporting	$	7,331		$	6,924		$	611		$	727

	Six Months Ended June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	14,154		$	15,778		$	62		$	80
Interest cost	22,716			21,607			1,962			1,907
Expected return on plan assets	(30,472		)	(31,415		)	(86		)	(60		)
Amortization of prior service cost (credit)	468			468			(1,518		)	(1,518		)
Amortization of net loss	18,388			23,096			802			1,046
Net periodic benefit cost	25,254			29,534			1,222			1,455
Costs not recognized due to the effects of regulation	(10,592		)	(15,685		)	—			—
Net benefit cost recognized for financial reporting	$	14,662		$	13,849		$	1,222		$	1,455

In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $49.4 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2016.

12. Other Comprehensive Income

Changes in accumulated other comprehensive (loss) income, net of tax, for the three and six months ended June 30, 2016 and 2015 were as follows:

	Three Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at April 1	$	(18,868	)	$	105	$	(2,077	)	$	(20,840	)
Other comprehensive income before reclassifications	7			—		—			7
Losses reclassified from net accumulated other comprehensive loss	221			—		19			240
Net current period other comprehensive income	228			—		19			247
Accumulated other comprehensive (loss) income at June 30	$	(18,640	)	$	105	$	(2,058	)	$	(20,593	)

27

	Three Months Ended June 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at April 1	$	(19,707	)	$	106	$	(1,016	)	$	(20,617	)
Other comprehensive income before reclassifications	9			1		—			10
Losses (gains) reclassified from net accumulated other comprehensive loss	214			—		(6		)	208
Net current period other comprehensive income (loss)	223			1		(6		)	218
Accumulated other comprehensive (loss) income at June 30	$	(19,484	)	$	107	$	(1,022	)	$	(20,399	)

	Six Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,090	)	$	105	$	(2,096	)	$	(21,081	)
Other comprehensive income before reclassifications	6			—		—			6
Losses reclassified from net accumulated other comprehensive loss	444			—		38			482
Net current period other comprehensive income	450			—		38			488
Accumulated other comprehensive (loss) income at June 30	$	(18,640	)	$	105	$	(2,058	)	$	(20,593	)

	Six Months Ended June 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,909	)	$	105	$	(1,010	)	$	(20,814	)
Other comprehensive income before reclassifications	2			2		—			4
Losses (gains) reclassified from net accumulated other comprehensive loss	423			—		(12		)	411
Net current period other comprehensive income (loss)	425			2		(12		)	415
Accumulated other comprehensive (loss) income at June 30	$	(19,484	)	$	107	$	(1,022	)	$	(20,399	)

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Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		(a)	$	346		(a)
Vehicle fuel derivatives	26			(b)	16			(b)
Total, pre-tax	372				362
Tax benefit	(151		)		(148		)
Total, net of tax	221				214
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	83			(c)	40			(c)
Prior service credit	(49		)	(c)	(48		)	(c)
Total, pre-tax	34				(8		)
Tax (benefit) expense	(15		)		2
Total, net of tax	19				(6		)
Total amounts reclassified, net of tax	$	240			$	208

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	692		(a)	$	686		(a)
Vehicle fuel derivatives	57			(b)	30			(b)
Total, pre-tax	749				716
Tax benefit	(305		)		(293		)
Total, net of tax	444				423
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	166			(c)	77			(c)
Prior service credit	(98		)	(c)	(99		)	(c)
Total, pre-tax	68				(22		)
Tax (benefit) expense	(30		)		10
Total, net of tax	38				(12		)
Total amounts reclassified, net of tax	$	482			$	411

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

^(c)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.

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

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

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Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including NSP-Minnesota’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2016), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.

Results of Operations

NSP-Minnesota’s net income was approximately $172.8 million for the six months ended June 30, 2016, compared with approximately $81.1 million for the same period in 2015. The impact of the 2015 Monticello LCM/EPU project loss along with higher electric revenue, primarily due to an electric rate increase in Minnesota (interim, subject to refund), and non-fuel riders were partially offset by higher depreciation, property taxes, O&M expenses and interest charges. See Note 5 to the consolidated financial statements for further discussion of the Monticello LCM/EPU project loss.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have minimal impact on electric margin. The following table details the electric revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2016			2015
Electric revenues	$	2,050		$	2,006
Electric fuel and purchased power	(713		)	(783		)
Electric margin	$	1,337		$	1,223

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

Electric Revenues

(Millions of Dollars)	2016 vs. 2015
Retail rate increases (a)	$	58
Transmission revenue	18
Non-fuel riders	17
Trading	10
Conservation program revenue (offset by expenses)	9
Fuel and purchased power cost recovery	(67		)
Other, net	(1		)
Total increase in electric revenues	$	44

Electric Margin

(Millions of Dollars)	2016 vs. 2015
Retail rate increases (a)	$	58
Non-fuel riders	17
Interchange revenues from NSP-Wisconsin	13
Conservation program revenue (offset by expenses)	9
Transmission revenue, net of costs	6
Other, net	11
Total increase in electric margin	$	114

^(a)  Increase is primarily related to the Minnesota Electric Rate Case (interim, subject to and net of estimated provision for refund). See Note 5 to the consolidated financial statements.

Natural Gas Revenues and Margin

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

	Six Months Ended June 30
(Millions of Dollars)	2016			2015
Natural gas revenues	$	259		$	355
Cost of natural gas sold and transported	(145		)	(239		)
Natural gas margin	$	114		$	116

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

Natural Gas Revenues

(Millions of Dollars)	2016 vs. 2015
Purchased natural gas adjustment clause recovery	$	(93	)
Estimated impact of weather	(6		)
Conservation program revenue (offset by expenses)	3
Total decrease in natural gas revenues	$	(96	)

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Natural Gas Margin

(Millions of Dollars)	2016 vs. 2015
Estimated impact of weather	$	(6	)
Conservation program revenue (offset by expenses)	3
Other, net	1
Total decrease in natural gas margin	$	(2	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased $13.5 million, or 2.2 percent, for the six months ended June 30, 2016, compared with the same period in 2015. The increase was primarily due to interchange agreement billings with NSP-Wisconsin related to transmission projects placed in service, which were partially offset by the timing of plant outages and less discovery work along with lower nuclear outage and amortization costs.

Conservation Program Expenses — Conservation program expenses increased$11.4 million for the six months ended June 30, 2016, compared with the same period in 2015. The increase was primarily attributable to higher electric and natural gas recovery rates. Higher conservation program expenses are generally offset by higher revenues.

Depreciation and Amortization— Depreciation and amortization expense increased$58.9 million, or 25.1 percent, for the six months ended June 30, 2016, compared with the same period in 2015. The increase was primarily attributable to capital investments, including Pleasant Valley and Border Wind Farms which were placed into service in late 2015, and the effect of prior regulatory commission actions (e.g. theoretical reserves and DOE settlements).

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased$14.0 million, or 11.5 percent, for the six months ended June 30, 2016, compared with the same period in 2015. The increase was due to higher property taxes primarily in Minnesota.

Interest Charges — Interest charges increased$9.3 million, or 9.2 percent, for the six months ended June 30, 2016, compared with the same period in 2015. The increase was related to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased$39.5 million for the six months ended June 30, 2016, compared with the same period in 2015. The increase in income tax expense was primarily due to higher pre-tax earnings in 2016 partially offset by an increase in wind production tax credits in 2016. The ETR was 32.2 percent for the six months ended June 30, 2016, compared with 34.3 percent for the same period in 2015. The lower ETR in 2016 is primarily due to increased wind production tax credits.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1. of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015, and Public Utility Regulation included in Item 2 of NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

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

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

Specific terms of the proposal include:

• The addition of 800 MW of wind and 400 MW of utility scale solar to the pre-2020 time-frame;

• The addition of 1000 MW of wind and 1000 MW of utility scale solar between 2020-2030;

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

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

• Replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site no later than 2026; and

• Operation of the Monticello and PI nuclear plants through their current license periods in the early 2030’s.

In January 2016, NSP-Minnesota filed supplemental economic and technical information in support of its revised Plan. Additionally, NSP-Minnesota addressed forecasted cost increases at PI (through end of licensed life) and committed to provide additional information if the MPUC wishes to further explore alternatives to operating PI through its current license periods. In July 2016, the DOC submitted its comments, which:

• Concluded NSP-Minnesota’s revised Plan is the most cost-effective after analyzing alternative retirement scenarios for Sherco Units 1 and 2 and a possible retirement of the King plant;

• Recommended a separate detailed analysis of early PI retirement;

• Recommended no additional solar beyond the community solar gardens program for the first five years; and

• Recommended adding up to 1,000 MW of wind by 2019.

The MPUC is expected to make a decision on the Plan in late 2016.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. See Note 12 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 for further discussion regarding the nuclear generating plants. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1. of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015, and Nuclear Power Operations included in Item 2 of NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated herein by reference.

Summary of Recent Federal Regulatory Developments

The Pipeline and Hazardous Materials Safety Administration

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

NSP-Minnesota recently commented on the proposed rules and continues to analyze the proposed rule changes as they relate to costs, current operations and financial results.  PHMSA has indicated that they intend for the rules to go into effect in late 2016. 

NSP-Minnesota has been taking actions that were intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.  NSP-Minnesota can generally recover costs to comply with the transmission and distribution integrity management programs through the GUIC rider.

FERC

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

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FERC Order, New ROE Policy — The FERC has adopted a new two-step ROE methodology for electric utilities. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. Two complaints against the MISO TOs, including NSP-Minnesota and NSP-Wisconsin, are pending FERC action after issuance of initial decisions by ALJs in December 2015 and June 2016, respectively. FERC is not expected to issue orders in any of the litigated ROE complaint proceedings until later in 2016 or 2017. See Note 5 to the consolidated financial statements for discussion of the MISO ROE Complaints.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, the MISO TOs, including NSP-Minnesota and NSP-Wisconsin filed separate changes to their transmission formula rates to modify the treatment of ADIT to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings were intended to ensure that NSP-Minnesota and NSP-Wisconsin are in compliance with IRS rules and may continue to use accelerated tax depreciation. In December 2015, the FERC partially accepted the proposed NSP-Minnesota and NSP-Wisconsin transmission formula rate changes, but rejected the changes regarding the treatment of ADIT in the formula rate true-up. NSP-Minnesota and NSP-Wisconsin sought clarification or rehearing of the FERC order partially rejecting the NSP System filing. FERC action on the NSP-Minnesota and NSP-Wisconsin request for clarification remains pending.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of June 30, 2016, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

Effective January 2016, NSP-Minnesota implemented the general ledger modules of a new enterprise resource planning (ERP) system to improve certain financial and related transaction processes. During 2016 and 2017, NSP-Minnesota will continue implementing additional modules and expects to begin conversion of existing work management systems to this new ERP system. In connection with this ongoing implementation, NSP-Minnesota has updated and will continue updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures.  NSP-Minnesota does not expect the implementation of the additional modules to materially affect its internal control over financial reporting.

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Note 5 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

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Item 1A — RISK FACTORS

NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31,2015, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

Item 6 — EXHIBITS

* Indicates incorporation by reference

+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern States Power Co. (a Minnesota corporation) as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 000-31387)).
4.01*	Supplemental Trust Indenture dated as of May 1, 2016 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $350,000,000 principal amount of 3.600 percent First Mortgage Bonds, Series due May 15, 2046. (Exhibit 4.01 to Form 8-K of NSP-Minnesota dated May 31, 2016 (file no. 001-31387)).
10.01*+	Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to Form 10-Q of Xcel Energy dated Aug. 4, 2016 (file no. 001-03034)).
10.02*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.02 to Form 8-K of Xcel Energy, dated June 20, 2016 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Consolidated Financial Statements, and (vi) document and entity information.

35

SIGNATURES

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

		Northern States Power Company (a Minnesota corporation)
Aug. 4, 2016	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

36

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Aug. 4, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Aug. 4, 2016

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Northern States Power Company, a Minnesota corporation (NSP-Minnesota) on Form 10-Q for the quarter ended June 30, 2016, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of NSP-Minnesota certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of NSP-Minnesota as of the dates and for the periods expressed in the Form 10-Q.

Date: Aug. 4, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

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

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

1

EX-99.01

Exhibit 99.01

NSP-Minnesota Cautionary Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• Social attitudes regarding the utility and power industries;

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

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

• Risks associated with implementations of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in SEC filings, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2015, or in other publicly disseminated written documents.

NSP-Minnesota undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 04, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO
Entity Central Index Key	0001123852
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000,000
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating revenues
Electric, non-affiliates	$ 903,344	$ 882,042	$ 1,812,091	$ 1,763,321
Electric, affiliates	113,127	117,830	238,023	242,705
Natural gas	64,371	75,239	258,501	354,706
Other	7,258	6,863	14,118	13,724
Total operating revenues	1,088,100	1,081,974	2,322,733	2,374,456
Operating expenses
Electric fuel and purchased power	347,092	384,479	713,258	783,199
Cost of natural gas sold and transported	24,280	37,419	144,503	238,608
Cost of sales — other	4,855	4,467	9,287	8,794
Operating and maintenance expenses	318,540	311,512	639,036	625,562
Conservation program expenses	20,229	14,877	43,498	32,089
Depreciation and amortization	147,444	116,245	293,241	234,320
Taxes (other than income taxes)	65,985	58,487	136,337	122,319
Loss on Monticello life cycle management/extended power uprate project	0	0	0	124,226
Total operating expenses	928,425	927,486	1,979,160	2,169,117
Operating income	159,675	154,488	343,573	205,339
Other (expense) income, net	(587)	(276)	2,273	1,685
Allowance for funds used during construction — equity	7,380	5,684	13,028	11,614
Interest charges and financing costs
Interest charges — includes other financing costs of $1,761, $1,637, $3,503, and $3,246, respectively	56,136	49,094	110,151	100,856
Allowance for funds used during construction — debt	(3,278)	(2,840)	(5,984)	(5,754)
Total interest charges and financing costs	52,858	46,254	104,167	95,102
Income before income taxes	113,610	113,642	254,707	123,536
Income taxes	35,434	39,461	81,902	42,431
Net income	$ 78,176	$ 74,181	$ 172,805	$ 81,105

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Interest charges and financing costs
Other financing costs	$ 1,761	$ 1,637	$ 3,503	$ 3,246

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Comprehensive income:
Net income	$ 78,176	$ 74,181	$ 172,805	$ 81,105
Pension and retiree medical benefits:
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $15, $(2), $26 and ($10), respectively	19	(6)	38	(12)
Derivative instruments:
Net fair value increase, net of tax of $5, $6, $4 and $3, respectively	7	9	6	2
Reclassification of losses to net income, net of tax of $151, $148, $305 and $293, respectively	221	214	444	423
Total derivative instruments, net of tax	228	223	450	425
Marketable securities:
Net fair value increase, net of tax of $0, $1, $0 and $2, respectively	0	1	0	2
Other comprehensive income	247	218	488	415
Comprehensive income	$ 78,423	$ 74,399	$ 173,293	$ 81,520

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, tax	$ 15	$ (2)	$ 26	$ (10)
Derivative instruments:
Net fair value (decrease) increase, tax	5	6	4	3
Reclassification of losses to net income, tax	151	148	305	293
Marketable securities:
Net fair value (decrease) increase, tax	$ 0	$ 1	$ 0	$ 2

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating activities
Net income	$ 172,805	$ 81,105
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	296,285	237,103
Nuclear fuel amortization	58,267	49,454
Deferred income taxes	47,057	62,445
Amortization of Investment Tax Credits	(840)	(866)
Allowance for equity funds used during construction	(13,028)	(11,614)
Loss on Monticello life cycle management/extended power uprate project	0	124,226
Net realized and unrealized hedging and derivative transactions	2,725	6,442
Changes in operating assets and liabilities:
Accounts receivable	(15,345)	78,369
Accrued unbilled revenues	14,731	40,527
Inventories	30,727	5,774
Other current assets	42,890	37,783
Accounts payable	(5,344)	(35,275)
Net regulatory assets and liabilities	70,287	15,320
Other current liabilities	(35,304)	(2,478)
Pension and other employee benefit obligations	(45,988)	(29,920)
Change in other noncurrent assets	(4,460)	(33)
Change in other noncurrent liabilities	(6,419)	(17,436)
Net cash provided by operating activities	609,046	640,926
Investing activities
Utility capital/construction expenditures	(514,526)	(610,731)
Allowance for equity funds used during construction	13,028	11,614
Proceeds from insurance recoveries	0	27,237
Purchases of investment securities	(279,566)	(640,100)
Proceeds from the sale of investment securities	262,321	636,669
Investments in utility money pool arrangement	(237,000)	(39,900)
Repayments from utility money pool arrangement	97,000	39,900
Other, net	(1,242)	(1,151)
Net cash used in investing activities	(659,985)	(576,462)
Financing activities
Repayments of short-term borrowings, net	(223,000)	(25,000)
Borrowings under utility money pool arrangement	424,000	144,500
Repayments under utility money pool arrangement	(424,000)	(144,500)
Proceeds from (Repayments of) Long-term Debt	343,103	(46)
Capital contributions from parent	89,874	125,935
Dividends paid to parent	(155,726)	(133,671)
Net cash provided by (used in) financing activities	54,251	(32,782)
Net change in cash and cash equivalents	3,312	31,682
Cash and cash equivalents at beginning of period	42,605	40,597
Cash and cash equivalents at end of period	45,917	72,279
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(100,217)	(93,318)
Cash received for income taxes, net	4,286	59,175
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 116,698	$ 85,735

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 45,917	$ 42,605
Accounts receivable, net	304,837	292,806
Accounts receivable from affiliates	28,044	32,850
Investments Receivable in Utility Money Pool Arrangement	140,000	0
Accrued unbilled revenues	212,371	227,102
Inventories	313,270	343,916
Regulatory assets	182,052	187,793
Derivative instruments	30,015	18,941
Deferred income taxes	72,661	15,577
Prepayments and other	39,932	89,559
Total current assets	1,369,099	1,251,149
Property, plant and equipment, net	12,928,362	12,807,338
Other assets
Nuclear decommissioning fund and other investments	1,799,298	1,758,208
Regulatory assets	1,191,984	1,159,217
Derivative instruments	22,946	22,334
Other	5,845	1,385
Total other assets	3,020,073	2,941,144
Total assets	17,317,534	16,999,631
Current liabilities
Current portion of long-term debt	10	11
Short-term debt	0	223,000
Accounts payable	360,691	350,660
Accounts payable to affiliates	49,929	59,785
Regulatory liabilities	76,957	43,920
Taxes accrued	193,372	225,361
Accrued interest	67,975	66,979
Dividends payable to parent	80,484	73,498
Derivative instruments	17,087	17,211
Customer Deposits, Current	122,235	94,388
Other	133,554	177,795
Total current liabilities	1,102,294	1,332,608
Deferred credits and other liabilities
Deferred income taxes	2,684,664	2,572,087
Deferred investment tax credits	24,998	25,838
Regulatory liabilities	468,757	491,887
Asset retirement obligations	2,388,208	2,331,092
Derivative instruments	120,654	128,213
Pension and employee benefit obligations	292,938	339,663
Other	134,044	114,768
Total deferred credits and other liabilities	6,114,263	6,003,548
Commitments and contingencies
Capitalization
Long-term debt	4,841,577	4,496,410
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively	10	10
Additional paid in capital	3,405,564	3,323,810
Retained earnings	1,874,419	1,864,326
Accumulated other comprehensive loss	(20,593)	(21,081)
Total common stockholder’s equity	5,259,400	5,167,065
Total liabilities and equity	$ 17,317,534	$ 16,999,631

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
Capitalization
Common stock, shares authorized (in shares)	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	1,000,000	1,000,000

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Management's Opinion

6 Months Ended

Jun. 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-Minnesota and its subsidiaries as of June 30, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2016 and 2015; and its cash flows for the six months endedJune 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 June 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-Minnesota 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-Minnesota 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-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 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-Minnesota 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.

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Accounting Pronouncements

6 Months Ended

Jun. 30, 2016

Accounting Policies [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-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, 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-Minnesota implemented the new guidance as required on Jan. 1, 2016, and as a result, $36.9 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 $37.7 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 (NAV) methodology in the fair value hierarchy. NSP-Minnesota implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.

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Selected Balance Sheet Data

6 Months Ended

Jun. 30, 2016

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	322,275		$	313,556
Less allowance for bad debts	(17,438		)	(20,750		)
	$	304,837		$	292,806

(Thousands of Dollars)	June 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	213,237	$	200,888
Fuel	83,974		104,499
Natural gas	16,059		38,529
	$	313,270	$	343,916

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	16,394,295		$	16,256,887
Natural gas plant	1,264,860			1,248,408
Common and other property	639,731			624,409
Construction work in progress	785,838			545,535
Total property, plant and equipment	19,084,724			18,675,239
Less accumulated depreciation	(6,495,449		)	(6,251,498		)
Nuclear fuel	2,461,008			2,447,251
Less accumulated amortization	(2,121,921		)	(2,063,654		)
	$	12,928,362		$	12,807,338

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Income Taxes

6 Months Ended

Jun. 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-Minnesota’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 Tax Loss Carryback Claims — In 2012, 2013, 2014 and 2015, NSP-Minnesota identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, NSP-Minnesota recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.

Federal Audit — NSP-Minnesota 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 the 2009 carryback claim. As of June 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 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). During the second quarter of 2016 the IRS audit team 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 expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of June 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2016, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In June 2016, Minnesota began an audit of years 2010 through 2014. As of June 30, 2016 Minnesota 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)	June 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	20.8	$	20.1
Unrecognized tax benefit — Temporary tax positions	37.5		35.3
Total unrecognized tax benefit	$	58.3	$	55.4

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

(Millions of Dollars)	June 30, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(16.9	)	$	(15.2	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Minnesota audit progresses, and other state audits resume. As the IRS Appeals and IRS and Minnesota audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $32 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 June 30, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2016 or Dec. 31, 2015.

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Rate Matters

6 Months Ended

Jun. 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-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 and in Note 5 to NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. The request is detailed in the table below:

Request (Millions of Dollars)	2016			2017			2018
Rate request	$	194.6		$	52.1		$	50.4
Increase percentage	6.4		%	1.7		%	1.7		%
Interim request	$	163.7		$	44.9		N/A
Rate base	$	7,800		$	7,700		$	7,700

In December 2015, the MPUC approved interim rates for 2016.

Intervenor Testimony:

In June 2016, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) subsequently filed revised testimony recommending an increase of approximately $45.6 million in 2016, a step increase of $53.8 million for 2017, and a step decrease of $5.0 million for 2018, based on a recommended ROE of 9.06 percent and an equity ratio of 52.50 percent.

Based on NSP-Minnesota’s interpretation of the DOC’s testimony, certain recommended adjustments of approximately $72.7 million would not be expected to impact earnings, assuming MPUC approval. The following table summarizes NSP-Minnesota’s estimate of the DOC’s recommendations:

(Millions of Dollars)	2016			2017 Step			2018 Step			Total
Filed rate request	$	194.6		$	52.1		$	50.4		$	297.1
DOC recommended adjustments:
ROE	(65.0		)	0.3			1.0			(63.7		)
Sales forecast	(39.4		)	—			—			(39.4		)
Property tax	(5.2		)	(0.3		)	(0.1		)	(5.6		)
Depreciation life	(8.0		)	0.4			(2.2		)	(9.8		)
Purchased demand timing changes	—			—			(19.4		)	(19.4		)
Nuclear capital costs	(3.6		)	0.8			(11.2		)	(14.0		)
Tax related items	(12.2		)	18.4			(6.9		)	(0.7		)
Operating and maintenance (O&M)	(15.5		)	(17.8		)	(16.7		)	(50.0		)
Other, net	(0.1		)	(0.1		)	0.1			(0.1		)
Total DOC Adjustments	(149.0		)	1.7			(55.4		)	(202.7		)
Total DOC recommended rate increase	$	45.6		$	53.8		$	(5.0	)	$	94.4
Estimated non-earnings DOC adjustments:
Depreciation life	8.0			(0.4		)	2.2			9.8
Sales forecast	37.4			—			—			37.4
Property tax	5.2			0.3			0.1			5.6
Purchased demand timing changes	—			—			19.4			19.4
Other	0.5			—			—			0.5
Total estimated non-earnings adjustments	51.1			(0.1		)	21.7			72.7
Total pre-tax earnings impact	$	96.7		$	53.7		$	16.7		$	167.1

The DOC also presented several nuclear recommendations related to capital recovery for spent fuel storage investments and Prairie Island life cycle management (LCM) projects.

• The use of certificate of need estimates as a recovery cap, and/or provisionally exclude recovery of amounts in excess of the cap unless the costs are deemed reasonable by the DOC’s nuclear consultant and/or the MPUC.

• No recovery of a portion of capital costs associated with Monticello fuel storage Cask 16, representing the amount beyond the originally anticipated project cost, or approximately $15 million. The additional costs incurred were for testing of cask lid welds to demonstrate compliance with Nuclear Regulatory Commission (NRC) requirements.

Settlement Agreement

In August 2016, NSP-Minnesota reached a settlement in principal with several of the parties, which resolves all revenue requirement issues in dispute. The terms and conditions of the agreement are still subject to final documentation. The settlement agreement requires the approval of the MPUC.

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

• Rebuttal testimony — Aug. 9, 2016;

• Surrebuttal testimony — Sept. 16, 2016;

• Settlement conference — Sept. 26, 2016;

• Evidentiary hearing — Oct. 4-7, 2016;

• Administrative Law Judge report — Feb. 21, 2017; and

• MPUC order — June 1, 2017.

A current liability representing NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of June 30, 2016.

NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider —In July 2016, the MPUC verbally approved NSP-Minnesota’s request to recover approximately $15 million in natural gas infrastructure costs through the GUIC Rider, based on NSP-Minnesota’s proposed capital structure and a ROE of 9.64 percent, as proposed by the DOC. Recovery was approved for the 15-month period from January 2016 to March 2017.

Annual Automatic Adjustment (AAA) of Charges — In June 2016, the DOC recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. As it pertains to NSP-Minnesota, the DOC’s recommendation could impact replacement power cost recovery for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction during the 2015 AAA fiscal year. NSP-Minnesota expects a MPUC decision in mid-2017.

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello 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 approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014.  As a result of these determinations, 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.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

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

In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent. A FERC order is expected to be issued in late 2016 or in 2017.

In February 2015, a second complaint was filed seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent, prior to any adder.  The FERC set the second complaint for hearings, and established a refund effective date of Feb. 12, 2015. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of either 8.82 percent or 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, with refunds for the 15 month period beginning Feb. 12, 2015. A FERC decision is expected in 2017.

FERC approved of a 50 basis point ROE adder for RTO membership, effective Jan. 6, 2015, subject to the outcome of the ROE complaint. Under FERC policy, the total ROE including the RTO membership adder cannot exceed the top of the DCF range.

NSP-Minnesota has recorded a current liability representing the best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of June 30, 2016. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $8 million and $10 million, annually, for the NSP System.

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Commitments and Contingencies

6 Months Ended

Jun. 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, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2015, 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-Minnesota’s financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, NSP-Minnesota purchases power from independent power producing entities for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

NSP-Minnesota had approximately 1,069 MW of capacity under long-term PPAs as of June 30, 2016 and Dec. 31, 2015, with entities that have been determined to be variable interest entities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2028.

Guarantees

Under NSP-Minnesota’s railcar lease agreement, accounted for as an operating lease, NSP-Minnesota guarantees the lessor proceeds from sale of the leased assets at the end of the lease term will at least equal the guaranteed residual value. The guarantee issued by NSP-Minnesota limits its exposure to a maximum amount stated in the guarantee; however, NSP-Minnesota expects sale proceeds to exceed the guaranteed amount. This lease agreement expires in 2019.

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

(Millions of Dollars)	June 30, 2016		Dec. 31, 2015
Guarantee issued and outstanding	$	4.8	$	4.8

Environmental Loss Contingency Disclosure [Text Block]

Environmental Contingencies

Fargo, N.D. Manufactured Gas Plant (MGP) Site — In May 2015, underground pipes, tars and impacted soils were discovered in Fargo, N.D., which may be related to a former MGP site operated by NSP-Minnesota or a prior company. NSP-Minnesota has removed the impacted soils and other materials from the project area. NSP-Minnesota is undertaking further investigation of the location of the historic MGP site and nearby properties. In October 2015, NSP-Minnesota initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until November 2016 to allow NSP-Minnesota time to further investigate site conditions.

As of June 30, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $1.6 million and $2.7 million, respectively, related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as potentially responsible parties. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer the portion of investigation and response costs allocable to the North Dakota jurisdiction.

Environmental Requirements

Water and Waste

Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In April 2015, the United States Environmental Protection Agency (EPA) published a final rule regulating the management and disposal of coal combustion byproducts (coal ash) as a nonhazardous waste. Under the final rule, NSP-Minnesota’s costs to manage and dispose of coal ash has not significantly increased.

In 2015, industry and environmental non-governmental organizations sought judicial review of the final rule. In June 2016, the D.C Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. Oral arguments are expected to be heard in the second half of 2016 and a final decision is anticipated in early 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on NSP-Minnesota.

Air

Implementation of the National Ambient Air Quality Standard (NAAQS) for Sulfur Dioxide (SO₂) — The EPA adopted a more stringent NAAQS for SO₂ in 2010. The EPA is requiring states to evaluate areas in three phases. If an area is designated as nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due in 18 months, designed to achieve the NAAQS within five years. It is anticipated the areas near NSP-Minnesota’s power plants will be evaluated in the next designation phase, ending December 2017. NSP-Minnesota’s King and Sherco plants already utilize scrubbers to control SO₂ emissions. NSP-Minnesota cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plans are developed. NSP-Minnesota believes that, should SO₂ control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

Legal Matters and Contingencies

Legal Contingencies

NSP-Minnesota 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-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

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Borrowings and Other Financing Instruments

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	25			5
Maximum amount outstanding	117			69
Weighted average interest rate, computed on a daily basis	0.66		%	0.53		%
Weighted average interest rate at period end	N/A			N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	500		$	500
Amount outstanding at period end	—			223
Average amount outstanding	64			96
Maximum amount outstanding	231			327
Weighted average interest rate, computed on a daily basis	0.59		%	0.43		%
Weighted average interest rate at period end	N/A			0.72

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2016 and Dec. 31, 2015, there were $18 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program, NSP-Minnesota 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 June 30, 2016, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	18	$	482

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

^(b)  Includes outstanding letters of credit.

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

Amended Credit Agreements - In June 2016, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $500 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-Minnesota has the right to request an extension of the revolving credit facility termination date for two additional one-year periods, subject to majority bank group approval.

Long-Term Borrowings

In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046.

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Fair Value of Financial Assets and Liabilities

6 Months Ended

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

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

Specific valuation methods include the following:

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

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using a net asset value (NAV) methodology, which takes into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities— Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

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.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, referred to as financial transmission rights (FTRs). FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by transmission load and transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity. Unplanned plant outages, scheduled plant maintenance, changes in the costs of fuels used in generation, weather and changes in demand for electricity can each impact the operating schedules of the power plants and the value of an FTR. NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model fair value measurements for FTRs have been assigned a Level 3. Monthly settlements for non-trading FTRs are included in fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs, given the purpose and legal restrictions on the use of nuclear decommissioning fund assets. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $336.5 million and $328.8 million at June 30, 2016 and Dec. 31, 2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $95.2 million and $100.2 million at June 30, 2016 and Dec. 31, 2015, respectively.

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at June 30, 2016 and Dec. 31, 2015:

	June 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	15,749	$	15,749	$	—	$	—	$	—	$	15,749
Commingled funds	389,700		—		—		—		411,788		411,788
International equity funds	259,090		—		—		—		236,087		236,087
Private equity investments	119,370		—		—		—		166,054		166,054
Real estate	72,956		—		—		—		102,144		102,144
Debt securities:
Government securities	35,199		—		35,828		—		—		35,828
U.S. corporate bonds	96,110		—		91,350		—		—		91,350
International corporate bonds	19,959		—		19,394		—		—		19,394
Municipal bonds	11,966		—		12,826		—		—		12,826
Asset-backed securities	2,844		—		2,881		—		—		2,881
Mortgage-backed securities	10,708		—		11,180		—		—		11,180
Equity securities:
Common stock	479,865		649,521		—		—		—		649,521
Total	$	1,513,516	$	665,270	$	173,459	$	—	$	916,073	$	1,754,802

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $44.5 million of rabbi trust assets and miscellaneous investments.

^(b)  Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

	Dec. 31, 2015
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	27,484	$	27,484	$	—	$	—	$	—	$	27,484
Commingled funds	392,838		—		—		—		410,634		410,634
International equity funds	259,114		—		—		—		231,122		231,122
Private equity investments	105,965		—		—		—		157,528		157,528
Real estate	61,816		—		—		—		84,750		84,750
Debt securities:
Government securities	24,444		—		21,356		—		—		21,356
U.S. corporate bonds	73,061		—		65,276		—		—		65,276
International corporate bonds	13,726		—		12,801		—		—		12,801
Municipal bonds	49,255		—		51,589		—		—		51,589
Asset-backed securities	2,837		—		2,830		—		—		2,830
Mortgage-backed securities	11,444		—		11,621		—		—		11,621
Equity securities:
Common stock	473,615		647,159		—		—		—		647,159
Total	$	1,495,599	$	674,643	$	165,473	$	—	$	884,034	$	1,724,150

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $34.1 million of miscellaneous investments.

^(b)  Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

For the six months ended June 30, 2016 and 2015 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2016:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	—	$	10,659	$	982	$	24,187	$	35,828
U.S. corporate bonds	261		26,988		59,368		4,733		91,350
International corporate bonds	—		3,966		12,368		3,060		19,394
Municipal bonds	—		212		4,248		8,366		12,826
Asset-backed securities	—		—		2,881		—		2,881
Mortgage-backed securities	—		—		—		11,180		11,180
Debt securities	$	261	$	41,825	$	79,847	$	51,526	$	173,459

Rabbi Trusts

In June 2016, NSP-Minnesota established a rabbi trust to provide funding for future distributions of its nonqualified pension plan. The following table presents the cost and fair value of the assets held in rabbi trust at June 30, 2016:

	June 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	7,448	$	7,448	$	—	$	—	$	7,448
Mutual funds	1,593		1,778		—		—		1,778
Total	$	9,041	$	9,226	$	—	$	—	$	9,226

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

An immaterial amount of mutual funds were held in rabbi trusts at Dec. 31, 2015.

Derivative Instruments Fair Value Measurements

NSP-Minnesota 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, utility commodity prices and vehicle fuel prices.

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

At June 30, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.8 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 any unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

Commodity Derivatives — NSP-Minnesota enters 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 energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives.

At June 30, 2016, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2016 and 2015.

At June 30, 2016, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	June 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	71,297	43,611
Million British thermal units of natural gas	42,991	7,971
Gallons of vehicle fuel	39	77

^(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.

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2016 and 2015 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	346	(a)	$	—		$	—
Vehicle fuel and other commodity	12		—			26		(b)	—			—
Total	$	12	$	—		$	372		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	269	(c)
Electric commodity	—		(1,193		)	—			13,572		(d)	—
Natural gas commodity	—		379			—			—			—
Total	$	—	$	(814	)	$	—		$	13,572		$	269

	Six Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	692	(a)	$	—		$	—
Vehicle fuel and other commodity	10		—			57		(b)	—			—
Total	$	10	$	—		$	749		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	1,261		(c)
Electric commodity	—		(2,752		)	—			24,284		(d)	—
Natural gas commodity	—		(253		)	—			3,460		(e)	(1,595		)	(e)
Total	$	—	$	(3,005	)	$	—		$	27,744		$	(334	)

	Three Months Ended June 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	346	(a)	$	—			$	—
Vehicle fuel and other commodity	15		—			16		(b)	—				—
Total	$	15	$	—		$	362		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	4,210	(c)
Electric commodity	—		(3,517		)	—			(6,327		)	(d)	—
Natural gas commodity	—		56			—			—			(e)	—		(e)
Total	$	—	$	(3,461	)	$	—		$	(6,327	)		$	4,210

	Six Months Ended June 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	686	(a)	$	—			$	—
Vehicle fuel and other commodity	5		—			30		(b)	—				—
Total	$	5	$	—		$	716		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	7,902	(c)
Electric commodity	—		(12,223		)	—			(11,520		)	(d)	—
Natural gas commodity	—		18			—			(2,751		)	(e)	3,008		(e)
Total	$	—	$	(12,205	)	$	—		$	(14,271	)		$	10,910

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to O&M expenses.

^(c)  Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

^(d)  Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

^(e)  Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and six months ended June 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-Minnesota 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-Minnesota’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-Minnesota 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.

NSP-Minnesota’s most significant concentrations of credit risk are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At June 30, 2016, five of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $20.1 million or 58 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $6.6 million or 19 percent of this credit exposure, were not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. The remaining two most significant counterparties, comprising $7.1 million or 21 percent of this credit exposure, had credit quality less than investment grade, based on ratings from internal analysis. Nine of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings. At June 30, 2016 and Dec. 31, 2015, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2016 and Dec. 31, 2015.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2016:

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	3,428	$	9,669	$	—	$	13,097	$	(8,067	)	$	5,030
Electric commodity	—		—		24,130		24,130		(642		)	23,488
Natural gas commodity	—		879		—		879		—			879
Total current derivative assets	$	3,428	$	10,548	$	24,130	$	38,106	$	(8,709	)	29,397
PPAs (a)												618
Current derivative instruments												$	30,015
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	997	$	28,051	$	—	$	29,048	$	(6,986	)	$	22,062
Total noncurrent derivative assets	$	997	$	28,051	$	—	$	29,048	$	(6,986	)	22,062
PPAs (a)												884
Noncurrent derivative instruments												$	22,946

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	45	$	—	$	45	$	—		$	45
Other derivative instruments:
Commodity trading	3,238		8,319		—		11,557		(8,625		)	2,932
Electric commodity	—		—		642		642		(642		)	—
Total current derivative liabilities	$	3,238	$	8,364	$	642	$	12,244	$	(9,267	)	2,977
PPAs (a)												14,110
Current derivative instruments												$	17,087
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	$	9,710
Total noncurrent derivative liabilities	$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	9,710
PPAs (a)												110,944
Noncurrent derivative instruments												$	120,654

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.7 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	88	$	10,269	$	1,250	$	11,607	$	(5,542	)	$	6,065
Electric commodity	—		—		12,441		12,441		(167		)	12,274
Natural gas commodity	—		128		—		128		(6		)	122
Total current derivative assets	$	88	$	10,397	$	13,691	$	24,176	$	(5,715	)	18,461
PPAs (a)												480
Current derivative instruments												$	18,941
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	27,399	$	—	$	27,399	$	(6,555	)	$	20,844
Total noncurrent derivative assets	$	—	$	27,399	$	—	$	27,399	$	(6,555	)	20,844
PPAs (a)												1,490
Noncurrent derivative instruments												$	22,334

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	113	$	—	$	113	$	—		$	113
Other derivative instruments:
Commodity trading	118		7,541		554		8,213		(6,580		)	1,633
Electric commodity	—		—		167		167		(167		)	—
Natural gas commodity	—		1,362		—		1,362		(6		)	1,356
Total current derivative liabilities	$	118	$	9,016	$	721	$	9,855	$	(6,753	)	3,102
PPAs (a)												14,109
Current derivative instruments												$	17,211
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	19,865	$	—	$	19,865	$	(9,780	)	$	10,085
Total noncurrent derivative liabilities	$	—	$	19,865	$	—	$	19,865	$	(9,780	)	10,085
PPAs (a)												118,128
Noncurrent derivative instruments												$	128,213

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at April 1	$	5,124		$	10,972
Purchases	27,870			40,162
Settlements	(6,981		)	(7,294		)
Net transactions recorded during the period:
Gains recognized in earnings (a)	22			1,220
Losses recognized as regulatory assets and liabilities	(2,547		)	(9,697		)
Balance at June 30	$	23,488		$	35,363
	Six Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	12,969		$	40,271
Purchases	27,870			41,025
Settlements	(12,039		)	(18,845		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(2		)	1,280
Losses recognized as regulatory assets and liabilities	(5,310		)	(28,368		)
Balance at June 30	$	23,488		$	35,363

^(a)  These amounts relate to commodity derivatives held at the end of the period.

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 2016 and 2015.

Fair Value of Long-Term Debt

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

	June 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,841,587	$	5,730,663	$	4,496,421	$	4,917,080

^(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-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 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.

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Other (Expense) Income, Net

6 Months Ended

Jun. 30, 2016

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

Other (Expense) Income, Net

Other income, net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2016			2015			2016			2015
Interest income	$	129		$	92		$	3,465		$	3,424
Other nonoperating income	107			60			271			92
Insurance policy expense	(823		)	(428		)	(1,463		)	(1,831		)
Other (expense) income, net	$	(587	)	$	(276	)	$	2,273		$	1,685

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Segment Information

6 Months Ended

Jun. 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-Minnesota’s chief operating decision maker. NSP-Minnesota 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-Minnesota has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

• NSP-Minnesota’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.

• NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota and North Dakota.

• 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 appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

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

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2016
Operating revenues (a)(b)	$	1,016,471	$	64,371	$	7,258		$	—		$	1,088,100
Intersegment revenues	262		86		—			(348		)	—
Total revenues	$	1,016,733	$	64,457	$	7,258		$	(348	)	$	1,088,100
Net income (loss)	$	78,781	$	458	$	(1,063	)	$	—		$	78,176

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2015
Operating revenues (a)(b)	$	999,872	$	75,239		$	6,863		$	—		$	1,081,974
Intersegment revenues	253		106			—			(359		)	—
Total revenues	$	1,000,125	$	75,345		$	6,863		$	(359	)	$	1,081,974
Net income (loss)	$	90,697	$	(16,422	)	$	(94	)	$	—		$	74,181

^(a)  Operating revenues include $113 million and $118 million of affiliate electric revenue for the three months ended June 30, 2016 and 2015, respectively.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2016 and 2015.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2016
Operating revenues (a)(b)	$	2,050,114	$	258,501	$	14,118		$	—		$	2,322,733
Intersegment revenues	407		248		—			(655		)	—
Total revenues	$	2,050,521	$	258,749	$	14,118		$	(655	)	$	2,322,733
Net income (loss)	$	150,102	$	23,600	$	(897	)	$	—		$	172,805

(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2015
Operating revenues (a)(b)	$	2,006,026		$	354,706	$	13,724		$	—		$	2,374,456
Intersegment revenues	386			516		—			(902		)	—
Total revenues	$	2,006,412		$	355,222	$	13,724		$	(902	)	$	2,374,456
Net income (loss)	$	61,098	(c)	$	23,850	$	(3,843	)	$	—		$	81,105

^(a)  Operating revenues include $238 million and $243 million of affiliate electric revenue for the six months ended June 30, 2016 and 2015, respectively.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2016 and 2015.

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

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Benefit Plans and Other Postretirement Benefits

6 Months Ended

Jun. 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 June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,077		$	7,889		$	31		$	40
Interest cost	11,358			10,803			981			953
Expected return on plan assets	(15,236		)	(15,707		)	(43		)	(30		)
Amortization of prior service cost (credit)	234			234			(759		)	(759		)
Amortization of net loss	9,194			11,548			401			523
Net periodic benefit cost	12,627			14,767			611			727
Costs not recognized due to the effects of regulation	(5,296		)	(7,843		)	—			—
Net benefit cost recognized for financial reporting	$	7,331		$	6,924		$	611		$	727

	Six Months Ended June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	14,154		$	15,778		$	62		$	80
Interest cost	22,716			21,607			1,962			1,907
Expected return on plan assets	(30,472		)	(31,415		)	(86		)	(60		)
Amortization of prior service cost (credit)	468			468			(1,518		)	(1,518		)
Amortization of net loss	18,388			23,096			802			1,046
Net periodic benefit cost	25,254			29,534			1,222			1,455
Costs not recognized due to the effects of regulation	(10,592		)	(15,685		)	—			—
Net benefit cost recognized for financial reporting	$	14,662		$	13,849		$	1,222		$	1,455

In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $49.4 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2016.

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Other Comprehensive Income

6 Months Ended

Jun. 30, 2016

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive (loss) income, net of tax, for the three and six months ended June 30, 2016 and 2015 were as follows:

	Three Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at April 1	$	(18,868	)	$	105	$	(2,077	)	$	(20,840	)
Other comprehensive income before reclassifications	7			—		—			7
Losses reclassified from net accumulated other comprehensive loss	221			—		19			240
Net current period other comprehensive income	228			—		19			247
Accumulated other comprehensive (loss) income at June 30	$	(18,640	)	$	105	$	(2,058	)	$	(20,593	)

	Three Months Ended June 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at April 1	$	(19,707	)	$	106	$	(1,016	)	$	(20,617	)
Other comprehensive income before reclassifications	9			1		—			10
Losses (gains) reclassified from net accumulated other comprehensive loss	214			—		(6		)	208
Net current period other comprehensive income (loss)	223			1		(6		)	218
Accumulated other comprehensive (loss) income at June 30	$	(19,484	)	$	107	$	(1,022	)	$	(20,399	)

	Six Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,090	)	$	105	$	(2,096	)	$	(21,081	)
Other comprehensive income before reclassifications	6			—		—			6
Losses reclassified from net accumulated other comprehensive loss	444			—		38			482
Net current period other comprehensive income	450			—		38			488
Accumulated other comprehensive (loss) income at June 30	$	(18,640	)	$	105	$	(2,058	)	$	(20,593	)

	Six Months Ended June 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,909	)	$	105	$	(1,010	)	$	(20,814	)
Other comprehensive income before reclassifications	2			2		—			4
Losses (gains) reclassified from net accumulated other comprehensive loss	423			—		(12		)	411
Net current period other comprehensive income (loss)	425			2		(12		)	415
Accumulated other comprehensive (loss) income at June 30	$	(19,484	)	$	107	$	(1,022	)	$	(20,399	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		(a)	$	346		(a)
Vehicle fuel derivatives	26			(b)	16			(b)
Total, pre-tax	372				362
Tax benefit	(151		)		(148		)
Total, net of tax	221				214
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	83			(c)	40			(c)
Prior service credit	(49		)	(c)	(48		)	(c)
Total, pre-tax	34				(8		)
Tax (benefit) expense	(15		)		2
Total, net of tax	19				(6		)
Total amounts reclassified, net of tax	$	240			$	208

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	692		(a)	$	686		(a)
Vehicle fuel derivatives	57			(b)	30			(b)
Total, pre-tax	749				716
Tax benefit	(305		)		(293		)
Total, net of tax	444				423
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	166			(c)	77			(c)
Prior service credit	(98		)	(c)	(99		)	(c)
Total, pre-tax	68				(22		)
Tax (benefit) expense	(30		)		10
Total, net of tax	38				(12		)
Total amounts reclassified, net of tax	$	482			$	411

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

^(c)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.

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Selected Balance Sheet Data (Tables)

6 Months Ended

Jun. 30, 2016

Balance Sheet Related Disclosures [Abstract]

Accounts receivable, net

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	322,275		$	313,556
Less allowance for bad debts	(17,438		)	(20,750		)
	$	304,837		$	292,806

Inventories

(Thousands of Dollars)	June 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	213,237	$	200,888
Fuel	83,974		104,499
Natural gas	16,059		38,529
	$	313,270	$	343,916

Property, plant and equipment, net

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	16,394,295		$	16,256,887
Natural gas plant	1,264,860			1,248,408
Common and other property	639,731			624,409
Construction work in progress	785,838			545,535
Total property, plant and equipment	19,084,724			18,675,239
Less accumulated depreciation	(6,495,449		)	(6,251,498		)
Nuclear fuel	2,461,008			2,447,251
Less accumulated amortization	(2,121,921		)	(2,063,654		)
	$	12,928,362		$	12,807,338

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Income Taxes (Tables)

6 Months Ended

Jun. 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)	June 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	20.8	$	20.1
Unrecognized tax benefit — Temporary tax positions	37.5		35.3
Total unrecognized tax benefit	$	58.3	$	55.4

Tax Benefits Associated with NOL and Tax Credit Carryforwards

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

(Millions of Dollars)	June 30, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(16.9	)	$	(15.2	)

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Rate Matters (Tables)

6 Months Ended

Jun. 30, 2016

Public Utilities, General Disclosures [Abstract]

NSP-Minnesota 2016 Electric Rate Case - Intervenor Testimony [Table Text Block]

(Millions of Dollars)	2016			2017 Step			2018 Step			Total
Filed rate request	$	194.6		$	52.1		$	50.4		$	297.1
DOC recommended adjustments:
ROE	(65.0		)	0.3			1.0			(63.7		)
Sales forecast	(39.4		)	—			—			(39.4		)
Property tax	(5.2		)	(0.3		)	(0.1		)	(5.6		)
Depreciation life	(8.0		)	0.4			(2.2		)	(9.8		)
Purchased demand timing changes	—			—			(19.4		)	(19.4		)
Nuclear capital costs	(3.6		)	0.8			(11.2		)	(14.0		)
Tax related items	(12.2		)	18.4			(6.9		)	(0.7		)
Operating and maintenance (O&M)	(15.5		)	(17.8		)	(16.7		)	(50.0		)
Other, net	(0.1		)	(0.1		)	0.1			(0.1		)
Total DOC Adjustments	(149.0		)	1.7			(55.4		)	(202.7		)
Total DOC recommended rate increase	$	45.6		$	53.8		$	(5.0	)	$	94.4
Estimated non-earnings DOC adjustments:
Depreciation life	8.0			(0.4		)	2.2			9.8
Sales forecast	37.4			—			—			37.4
Property tax	5.2			0.3			0.1			5.6
Purchased demand timing changes	—			—			19.4			19.4
Other	0.5			—			—			0.5
Total estimated non-earnings adjustments	51.1			(0.1		)	21.7			72.7
Total pre-tax earnings impact	$	96.7		$	53.7		$	16.7		$	167.1

NSP-Minnesota's 2016 Multi-Year Electric Rate Case - Rate Request [Table Text Block]

The request is detailed in the table below:

Request (Millions of Dollars)	2016			2017			2018
Rate request	$	194.6		$	52.1		$	50.4
Increase percentage	6.4		%	1.7		%	1.7		%
Interim request	$	163.7		$	44.9		N/A
Rate base	$	7,800		$	7,700		$	7,700

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Commitments and Contingencies Schedule of Guarantor Obligations (Tables)

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Guarantees Issued and Outstanding

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

(Millions of Dollars)	June 30, 2016		Dec. 31, 2015
Guarantee issued and outstanding	$	4.8	$	4.8

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Borrowings and Other Financing Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At June 30, 2016, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	18	$	482

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

^(b)  Includes outstanding letters of credit.

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	25			5
Maximum amount outstanding	117			69
Weighted average interest rate, computed on a daily basis	0.66		%	0.53		%
Weighted average interest rate at period end	N/A			N/A

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for NSP-Minnesota was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	500		$	500
Amount outstanding at period end	—			223
Average amount outstanding	64			96
Maximum amount outstanding	231			327
Weighted average interest rate, computed on a daily basis	0.59		%	0.43		%
Weighted average interest rate at period end	N/A			0.72

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Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Cost and Fair Value of Nuclear Decommissioning Fund Investments

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at June 30, 2016 and Dec. 31, 2015:

	June 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	15,749	$	15,749	$	—	$	—	$	—	$	15,749
Commingled funds	389,700		—		—		—		411,788		411,788
International equity funds	259,090		—		—		—		236,087		236,087
Private equity investments	119,370		—		—		—		166,054		166,054
Real estate	72,956		—		—		—		102,144		102,144
Debt securities:
Government securities	35,199		—		35,828		—		—		35,828
U.S. corporate bonds	96,110		—		91,350		—		—		91,350
International corporate bonds	19,959		—		19,394		—		—		19,394
Municipal bonds	11,966		—		12,826		—		—		12,826
Asset-backed securities	2,844		—		2,881		—		—		2,881
Mortgage-backed securities	10,708		—		11,180		—		—		11,180
Equity securities:
Common stock	479,865		649,521		—		—		—		649,521
Total	$	1,513,516	$	665,270	$	173,459	$	—	$	916,073	$	1,754,802

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $44.5 million of rabbi trust assets and miscellaneous investments.

^(b)  Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

	Dec. 31, 2015
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	27,484	$	27,484	$	—	$	—	$	—	$	27,484
Commingled funds	392,838		—		—		—		410,634		410,634
International equity funds	259,114		—		—		—		231,122		231,122
Private equity investments	105,965		—		—		—		157,528		157,528
Real estate	61,816		—		—		—		84,750		84,750
Debt securities:
Government securities	24,444		—		21,356		—		—		21,356
U.S. corporate bonds	73,061		—		65,276		—		—		65,276
International corporate bonds	13,726		—		12,801		—		—		12,801
Municipal bonds	49,255		—		51,589		—		—		51,589
Asset-backed securities	2,837		—		2,830		—		—		2,830
Mortgage-backed securities	11,444		—		11,621		—		—		11,621
Equity securities:
Common stock	473,615		647,159		—		—		—		647,159
Total	$	1,495,599	$	674,643	$	165,473	$	—	$	884,034	$	1,724,150

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $34.1 million of miscellaneous investments.

^(b)  Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2016:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	—	$	10,659	$	982	$	24,187	$	35,828
U.S. corporate bonds	261		26,988		59,368		4,733		91,350
International corporate bonds	—		3,966		12,368		3,060		19,394
Municipal bonds	—		212		4,248		8,366		12,826
Asset-backed securities	—		—		2,881		—		2,881
Mortgage-backed securities	—		—		—		11,180		11,180
Debt securities	$	261	$	41,825	$	79,847	$	51,526	$	173,459

Gross Notional Amounts of Commodity Forwards, Options, and FTRs

The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	June 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	71,297	43,611
Million British thermal units of natural gas	42,991	7,971
Gallons of vehicle fuel	39	77

^(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 Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2016 and 2015 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	346	(a)	$	—		$	—
Vehicle fuel and other commodity	12		—			26		(b)	—			—
Total	$	12	$	—		$	372		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	269	(c)
Electric commodity	—		(1,193		)	—			13,572		(d)	—
Natural gas commodity	—		379			—			—			—
Total	$	—	$	(814	)	$	—		$	13,572		$	269

	Six Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	692	(a)	$	—		$	—
Vehicle fuel and other commodity	10		—			57		(b)	—			—
Total	$	10	$	—		$	749		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	1,261		(c)
Electric commodity	—		(2,752		)	—			24,284		(d)	—
Natural gas commodity	—		(253		)	—			3,460		(e)	(1,595		)	(e)
Total	$	—	$	(3,005	)	$	—		$	27,744		$	(334	)

	Three Months Ended June 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	346	(a)	$	—			$	—
Vehicle fuel and other commodity	15		—			16		(b)	—				—
Total	$	15	$	—		$	362		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	4,210	(c)
Electric commodity	—		(3,517		)	—			(6,327		)	(d)	—
Natural gas commodity	—		56			—			—			(e)	—		(e)
Total	$	—	$	(3,461	)	$	—		$	(6,327	)		$	4,210

	Six Months Ended June 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	686	(a)	$	—			$	—
Vehicle fuel and other commodity	5		—			30		(b)	—				—
Total	$	5	$	—		$	716		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	7,902	(c)
Electric commodity	—		(12,223		)	—			(11,520		)	(d)	—
Natural gas commodity	—		18			—			(2,751		)	(e)	3,008		(e)
Total	$	—	$	(12,205	)	$	—		$	(14,271	)		$	10,910

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to O&M expenses.

^(c)  Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

^(d)  Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

^(e)  Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

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

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2016:

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	3,428	$	9,669	$	—	$	13,097	$	(8,067	)	$	5,030
Electric commodity	—		—		24,130		24,130		(642		)	23,488
Natural gas commodity	—		879		—		879		—			879
Total current derivative assets	$	3,428	$	10,548	$	24,130	$	38,106	$	(8,709	)	29,397
PPAs (a)												618
Current derivative instruments												$	30,015
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	997	$	28,051	$	—	$	29,048	$	(6,986	)	$	22,062
Total noncurrent derivative assets	$	997	$	28,051	$	—	$	29,048	$	(6,986	)	22,062
PPAs (a)												884
Noncurrent derivative instruments												$	22,946

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	45	$	—	$	45	$	—		$	45
Other derivative instruments:
Commodity trading	3,238		8,319		—		11,557		(8,625		)	2,932
Electric commodity	—		—		642		642		(642		)	—
Total current derivative liabilities	$	3,238	$	8,364	$	642	$	12,244	$	(9,267	)	2,977
PPAs (a)												14,110
Current derivative instruments												$	17,087
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	$	9,710
Total noncurrent derivative liabilities	$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	9,710
PPAs (a)												110,944
Noncurrent derivative instruments												$	120,654

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.7 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	88	$	10,269	$	1,250	$	11,607	$	(5,542	)	$	6,065
Electric commodity	—		—		12,441		12,441		(167		)	12,274
Natural gas commodity	—		128		—		128		(6		)	122
Total current derivative assets	$	88	$	10,397	$	13,691	$	24,176	$	(5,715	)	18,461
PPAs (a)												480
Current derivative instruments												$	18,941
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	27,399	$	—	$	27,399	$	(6,555	)	$	20,844
Total noncurrent derivative assets	$	—	$	27,399	$	—	$	27,399	$	(6,555	)	20,844
PPAs (a)												1,490
Noncurrent derivative instruments												$	22,334

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	113	$	—	$	113	$	—		$	113
Other derivative instruments:
Commodity trading	118		7,541		554		8,213		(6,580		)	1,633
Electric commodity	—		—		167		167		(167		)	—
Natural gas commodity	—		1,362		—		1,362		(6		)	1,356
Total current derivative liabilities	$	118	$	9,016	$	721	$	9,855	$	(6,753	)	3,102
PPAs (a)												14,109
Current derivative instruments												$	17,211
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	19,865	$	—	$	19,865	$	(9,780	)	$	10,085
Total noncurrent derivative liabilities	$	—	$	19,865	$	—	$	19,865	$	(9,780	)	10,085
PPAs (a)												118,128
Noncurrent derivative instruments												$	128,213

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Changes in Level 3 Commodity Derivatives

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at April 1	$	5,124		$	10,972
Purchases	27,870			40,162
Settlements	(6,981		)	(7,294		)
Net transactions recorded during the period:
Gains recognized in earnings (a)	22			1,220
Losses recognized as regulatory assets and liabilities	(2,547		)	(9,697		)
Balance at June 30	$	23,488		$	35,363
	Six Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	12,969		$	40,271
Purchases	27,870			41,025
Settlements	(12,039		)	(18,845		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(2		)	1,280
Losses recognized as regulatory assets and liabilities	(5,310		)	(28,368		)
Balance at June 30	$	23,488		$	35,363

^(a)  These amounts relate to commodity derivatives held at the end of the period.

Carrying Amount and Fair Value of Long-term Debt

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

	June 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,841,587	$	5,730,663	$	4,496,421	$	4,917,080

^(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.

Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block]

In June 2016, NSP-Minnesota established a rabbi trust to provide funding for future distributions of its nonqualified pension plan. The following table presents the cost and fair value of the assets held in rabbi trust at June 30, 2016:

	June 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	7,448	$	7,448	$	—	$	—	$	7,448
Mutual funds	1,593		1,778		—		—		1,778
Total	$	9,041	$	9,226	$	—	$	—	$	9,226

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

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Other (Expense) Income, Net (Tables)

6 Months Ended

Jun. 30, 2016

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

Other income, net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2016			2015			2016			2015
Interest income	$	129		$	92		$	3,465		$	3,424
Other nonoperating income	107			60			271			92
Insurance policy expense	(823		)	(428		)	(1,463		)	(1,831		)
Other (expense) income, net	$	(587	)	$	(276	)	$	2,273		$	1,685

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Segment Information (Tables)

6 Months Ended

Jun. 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 June 30, 2016
Operating revenues (a)(b)	$	1,016,471	$	64,371	$	7,258		$	—		$	1,088,100
Intersegment revenues	262		86		—			(348		)	—
Total revenues	$	1,016,733	$	64,457	$	7,258		$	(348	)	$	1,088,100
Net income (loss)	$	78,781	$	458	$	(1,063	)	$	—		$	78,176

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2015
Operating revenues (a)(b)	$	999,872	$	75,239		$	6,863		$	—		$	1,081,974
Intersegment revenues	253		106			—			(359		)	—
Total revenues	$	1,000,125	$	75,345		$	6,863		$	(359	)	$	1,081,974
Net income (loss)	$	90,697	$	(16,422	)	$	(94	)	$	—		$	74,181

^(a)  Operating revenues include $113 million and $118 million of affiliate electric revenue for the three months ended June 30, 2016 and 2015, respectively.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2016 and 2015.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2016
Operating revenues (a)(b)	$	2,050,114	$	258,501	$	14,118		$	—		$	2,322,733
Intersegment revenues	407		248		—			(655		)	—
Total revenues	$	2,050,521	$	258,749	$	14,118		$	(655	)	$	2,322,733
Net income (loss)	$	150,102	$	23,600	$	(897	)	$	—		$	172,805

(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2015
Operating revenues (a)(b)	$	2,006,026		$	354,706	$	13,724		$	—		$	2,374,456
Intersegment revenues	386			516		—			(902		)	—
Total revenues	$	2,006,412		$	355,222	$	13,724		$	(902	)	$	2,374,456
Net income (loss)	$	61,098	(c)	$	23,850	$	(3,843	)	$	—		$	81,105

^(a)  Operating revenues include $238 million and $243 million of affiliate electric revenue for the six months ended June 30, 2016 and 2015, respectively.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2016 and 2015.

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

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Benefit Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,077		$	7,889		$	31		$	40
Interest cost	11,358			10,803			981			953
Expected return on plan assets	(15,236		)	(15,707		)	(43		)	(30		)
Amortization of prior service cost (credit)	234			234			(759		)	(759		)
Amortization of net loss	9,194			11,548			401			523
Net periodic benefit cost	12,627			14,767			611			727
Costs not recognized due to the effects of regulation	(5,296		)	(7,843		)	—			—
Net benefit cost recognized for financial reporting	$	7,331		$	6,924		$	611		$	727

	Six Months Ended June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	14,154		$	15,778		$	62		$	80
Interest cost	22,716			21,607			1,962			1,907
Expected return on plan assets	(30,472		)	(31,415		)	(86		)	(60		)
Amortization of prior service cost (credit)	468			468			(1,518		)	(1,518		)
Amortization of net loss	18,388			23,096			802			1,046
Net periodic benefit cost	25,254			29,534			1,222			1,455
Costs not recognized due to the effects of regulation	(10,592		)	(15,685		)	—			—
Net benefit cost recognized for financial reporting	$	14,662		$	13,849		$	1,222		$	1,455

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Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2016

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax

Changes in accumulated other comprehensive (loss) income, net of tax, for the three and six months ended June 30, 2016 and 2015 were as follows:

	Three Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at April 1	$	(18,868	)	$	105	$	(2,077	)	$	(20,840	)
Other comprehensive income before reclassifications	7			—		—			7
Losses reclassified from net accumulated other comprehensive loss	221			—		19			240
Net current period other comprehensive income	228			—		19			247
Accumulated other comprehensive (loss) income at June 30	$	(18,640	)	$	105	$	(2,058	)	$	(20,593	)

	Three Months Ended June 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at April 1	$	(19,707	)	$	106	$	(1,016	)	$	(20,617	)
Other comprehensive income before reclassifications	9			1		—			10
Losses (gains) reclassified from net accumulated other comprehensive loss	214			—		(6		)	208
Net current period other comprehensive income (loss)	223			1		(6		)	218
Accumulated other comprehensive (loss) income at June 30	$	(19,484	)	$	107	$	(1,022	)	$	(20,399	)

	Six Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,090	)	$	105	$	(2,096	)	$	(21,081	)
Other comprehensive income before reclassifications	6			—		—			6
Losses reclassified from net accumulated other comprehensive loss	444			—		38			482
Net current period other comprehensive income	450			—		38			488
Accumulated other comprehensive (loss) income at June 30	$	(18,640	)	$	105	$	(2,058	)	$	(20,593	)

	Six Months Ended June 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,909	)	$	105	$	(1,010	)	$	(20,814	)
Other comprehensive income before reclassifications	2			2		—			4
Losses (gains) reclassified from net accumulated other comprehensive loss	423			—		(12		)	411
Net current period other comprehensive income (loss)	425			2		(12		)	415
Accumulated other comprehensive (loss) income at June 30	$	(19,484	)	$	107	$	(1,022	)	$	(20,399	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		(a)	$	346		(a)
Vehicle fuel derivatives	26			(b)	16			(b)
Total, pre-tax	372				362
Tax benefit	(151		)		(148		)
Total, net of tax	221				214
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	83			(c)	40			(c)
Prior service credit	(49		)	(c)	(48		)	(c)
Total, pre-tax	34				(8		)
Tax (benefit) expense	(15		)		2
Total, net of tax	19				(6		)
Total amounts reclassified, net of tax	$	240			$	208

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	692		(a)	$	686		(a)
Vehicle fuel derivatives	57			(b)	30			(b)
Total, pre-tax	749				716
Tax benefit	(305		)		(293		)
Total, net of tax	444				423
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	166			(c)	77			(c)
Prior service credit	(98		)	(c)	(99		)	(c)
Total, pre-tax	68				(22		)
Tax (benefit) expense	(30		)		10
Total, net of tax	38				(12		)
Total amounts reclassified, net of tax	$	482			$	411

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

^(c)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.

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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	$ 36.9	$ 37.7
Other Noncurrent Assets
Debt Instrument [Line Items]
Reclassification of deferred debt issuance costs, net		$ (37.7)

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Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$ 322,275	$ 313,556
Less allowance for bad debts	(17,438)	(20,750)
Accounts receivable, net	$ 304,837	$ 292,806

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Selected Balance Sheet Data, Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 313,270	$ 343,916
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	213,237	200,888
Fuel
Public Utilities, Inventory [Line Items]
Inventories	83,974	104,499
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 16,059	$ 38,529

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Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 19,084,724	$ 18,675,239
Less accumulated depreciation	(6,495,449)	(6,251,498)
Property, plant and equipment, net	12,928,362	12,807,338
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,394,295	16,256,887
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,264,860	1,248,408
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	639,731	624,409
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	785,838	545,535
Nuclear fuel
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,461,008	2,447,251
Less accumulated depreciation	$ (2,121,921)	$ (2,063,654)

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Income Taxes (Details) - USD ($)	1 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Examination [Line Items]
Number Of Years Of Tax Loss Carryback Period				2 years
Tax Adjustments, Settlements, and Unusual Provisions				$ 5,000,000	$ 17,000,000	$ 12,000,000	$ 15,000,000
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions	$ 20,800,000	$ 20,800,000		20,100,000
Unrecognized tax benefit — Temporary tax positions	37,500,000	37,500,000		35,300,000
Total unrecognized tax benefit	58,300,000	58,300,000		55,400,000
NOL and tax credit carryforwards	(16,900,000)	(16,900,000)		(15,200,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	32,000,000	32,000,000
Amounts accrued for penalties related to unrecognized tax benefits	$ 0	$ 0		$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Earliest year subject to examination		2009
Year(s) under examination			2012 and 2013				2010 and 2011
Year of carryback claim under examination							2009
Potential Tax Adjustments		$ 14,000,000
State Jurisdiction (Minnesota)
Tax Audits [Abstract]
Earliest year subject to examination		2009
Year(s) under examination	2010 through 2014

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Rate Matters (Details) $ in Thousands			1 Months Ended							3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jan. 06, 2015	Jul. 31, 2016 USD ($)	Jun. 30, 2016 USD ($)	Dec. 31, 2015	Nov. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015	Nov. 30, 2013	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Dec. 31, 2015 MW	Dec. 31, 2013 USD ($)	Dec. 31, 2008 USD ($)
Rate Matters [Abstract]
Loss on Monticello life cycle management/extended power uprate project										$ 0	$ 0		$ 0	$ 124,226
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Number Of Years Rate Case Is Applicable For						3 years
Public Utilities, Requested Return on Equity, Percentage						10.00%
Public Utilities, Requested Equity Capital Structure, Percentage						52.50%
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 297,100
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 194,600
Public Utilities, Requested Rate Increase (Decrease), Percentage						6.40%
Public Utilities, Requested Rate Base, Amount						$ 7,800,000
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 52,100
Public Utilities, Requested Rate Increase (Decrease), Percentage						1.70%
Public Utilities, Requested Interim Rate Increase (Decrease), Amount						$ 44,900
Public Utilities, Requested Rate Base, Amount						7,700,000
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 50,400
Public Utilities, Requested Rate Increase (Decrease), Percentage						1.70%
Public Utilities, Requested Rate Base, Amount						$ 7,700,000
NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation
Rate Matters [Abstract]
Nuclear Project Expenditures, Amount																$ 665,000
Total Capitalized Nuclear Project Costs																$ 748,000
Initial Estimated Nuclear Project Expenditures																	$ 320,000
Loss on Monticello life cycle management/extended power uprate project												$ 129,000
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
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 | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016
Rate Matters [Abstract]
Public Utilities, Approved Interim Rate Increase (Decrease), Amount						$ 163,700
NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Nuclear Project Prudency Investigation
Rate Matters [Abstract]
Public Utilities, Amount Of Recoverable Investment, With Return							$ 415,000
Public Utilities, Amount Of Recoverable Investment, Without A Return							$ 333,000
Public Utilities, Percentage Of Investment Considered Used And Useful							50.00%
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties				$ 94,400
Public Utilities, Return on Equity Recommended by Third Parties				9.06%
Public Utilities, Equity Capital Structure Recommended by Third Parties				52.50%
Public Utilities, Decrease to Requested Return on Equity				$ (63,700)
Public Utilities, Decrease Related to Sales Forecast				(39,400)
Public Utilities, Decrease Related to Property Taxes				(5,600)
Public Utilities, Decrease Related to Depreciation Life				(9,800)
Public Utilities, Increase Related to Depreciation Life				9,800
Public Utilities, Decrease Related to Purchased Demand Timing				(19,400)
Public Utilities, Decrease Related to Nuclear Capital Costs				(14,000)
Public Utilities, Decrease Related to Tax Related Items				(700)
Public Utilities, Decrease Related to Operating and Maintenance Costs				(50,000)
Public Utilities, Decrease Related to Other, Net				(100)
Public Utilities, Total Decreases Recommended by Third Parties				(202,700)
Public Utilities, Increase Related to Sales Forecast				37,400
Public Utilities, Increase Related To Property Taxes				5,600
Public Utilities, Increase Related to Purchased Demand Timing				19,400
Public Utilities, Increase Related To Other				500
Public Utilities, Increase from Non-Earnings Adjustments, Recommended by Third Parties				72,700
Public Utilities, Earnings Impact, Pre-tax				167,100
Public Utilities, Portion of Capital Costs on which Third Parties Recommend No Recovery				15,000
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016
Rate Matters [Abstract]
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties				45,600
Public Utilities, Decrease to Requested Return on Equity				(65,000)
Public Utilities, Decrease Related to Sales Forecast				(39,400)
Public Utilities, Decrease Related to Property Taxes				(5,200)
Public Utilities, Decrease Related to Depreciation Life				(8,000)
Public Utilities, Increase Related to Depreciation Life				8,000
Public Utilities, Decrease Related to Purchased Demand Timing				0
Public Utilities, Decrease Related to Nuclear Capital Costs				(3,600)
Public Utilities, Decrease Related to Tax Related Items				(12,200)
Public Utilities, Decrease Related to Operating and Maintenance Costs				(15,500)
Public Utilities, Decrease Related to Other, Net				(100)
Public Utilities, Total Decreases Recommended by Third Parties				(149,000)
Public Utilities, Increase Related to Sales Forecast				37,400
Public Utilities, Increase Related To Property Taxes				5,200
Public Utilities, Increase Related to Purchased Demand Timing				0
Public Utilities, Increase Related To Other				500
Public Utilities, Increase from Non-Earnings Adjustments, Recommended by Third Parties				51,100
Public Utilities, Earnings Impact, Pre-tax				96,700
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017
Rate Matters [Abstract]
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties				53,800
Public Utilities, Increase to Requested Return on Equity				300
Public Utilities, Decrease Related to Sales Forecast				0
Public Utilities, Decrease Related to Property Taxes				(300)
Public Utilities, Decrease Related to Depreciation Life				(400)
Public Utilities, Increase Related to Depreciation Life				400
Public Utilities, Decrease Related to Purchased Demand Timing				0
Public Utilities, Increase Related to Nuclear Capital Costs				800
Public Utilities, Increase Related to Tax Related Items				18,400
Public Utilities, Decrease Related to Operating and Maintenance Costs				(17,800)
Public Utilities, Decrease Related to Other, Net				(100)
Public Utilities, Total Increases Recommended by Third Parties				1,700
Public Utilities, Increase Related to Sales Forecast				0
Public Utilities, Increase Related To Property Taxes				300
Public Utilities, Increase Related to Purchased Demand Timing				0
Public Utilities, Increase Related To Other				0
Public Utilities, Decrease from Non-Earnings Adjustments, Recommended by Third Parties				(100)
Public Utilities, Earnings Impact, Pre-tax				53,700
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018
Rate Matters [Abstract]
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties				(5,000)
Public Utilities, Increase to Requested Return on Equity				1,000
Public Utilities, Decrease Related to Sales Forecast				0
Public Utilities, Decrease Related to Property Taxes				(100)
Public Utilities, Decrease Related to Depreciation Life				(2,200)
Public Utilities, Increase Related to Depreciation Life				2,200
Public Utilities, Decrease Related to Purchased Demand Timing				(19,400)
Public Utilities, Decrease Related to Nuclear Capital Costs				(11,200)
Public Utilities, Decrease Related to Tax Related Items				(6,900)
Public Utilities, Decrease Related to Operating and Maintenance Costs				(16,700)
Public Utilities, Increase Related To Other, Net				100
Public Utilities, Total Decreases Recommended by Third Parties				(55,400)
Public Utilities, Increase Related to Sales Forecast				0
Public Utilities, Increase Related To Property Taxes				100
Public Utilities, Increase Related to Purchased Demand Timing				19,400
Public Utilities, Increase Related To Other				0
Public Utilities, Increase from Non-Earnings Adjustments, Recommended by Third Parties				21,700
Public Utilities, Earnings Impact, Pre-tax				$ 16,700
NSP-Minnesota | Administrative Law Judge | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties	9.70%				10.32%
Public Utilities, Length of Refund Period, Recommended by Third Parties	15 months
NSP-Minnesota | MPUC, NDPSC, SDPUC, and DOC | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Upper Bound, Percentage													8.82%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Lower Bound, Percentage													8.81%
NSP-Minnesota | FERC Staff | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties													8.78%
NSP-Minnesota | MISO TOs | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties													10.92%
NSP-Minnesota | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, ROE Basis Point Adder Requested By Third Parties		50
Minimum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation
Rate Matters [Abstract]
Public Utilities, Facility Generating Capacity, in MW | MW															600
Minimum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology													$ 8,000
Maximum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation
Rate Matters [Abstract]
Public Utilities, Facility Generating Capacity, in MW | MW															671
Maximum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology													$ 10,000
Subsequent Event [Member] | NSP-Minnesota | Minnesota Public Utilities Commission | Gas Utility Infrastructure Cost Rider 2016
Rate Matters [Abstract]
Public Utilities, Approved Rider Revenue, Amount			$ 15,000
Public Utilities, Approved Return on Equity, Percentage			9.64%
Public Utilities, Length of Recovery Period, In Months			15 months

XML

Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,069	1,069
Purchase Power Agreement Duration, Maximum	2028	2028

XML

Commitments and Contingencies Commitments and Contingencies, Guarantees and Indemnifications (Details) - Payment or Performance Guarantee - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Guarantor Obligations [Line Items]
Lease Guarantee Expiration (year)	2019	2019
Guarantees issued and outstanding	$ 4.8	$ 4.8

XML

Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment	3
Number of months in which the state would have to submit an implementation plan for the respective nonattainment areas	18 months
Number of years for the state to achieve the designated attainment standard	5 years
Fargo MGP Site
Environmental Requirements [Abstract]
Accrual for Environmental Loss Contingencies, Gross	$ 1.6	$ 2.7

XML

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 223,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000,000	250,000,000
Amount outstanding at period end	0	0
Average amount outstanding	25,000,000	5,000,000
Maximum amount outstanding	$ 117,000,000	$ 69,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.66%	0.53%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 500,000,000	$ 500,000,000
Amount outstanding at period end	0	223,000,000
Average amount outstanding	64,000,000	96,000,000
Maximum amount outstanding	$ 231,000,000	$ 327,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.59%	0.43%
Weighted average interest rate at period end (percentage)		0.72%

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term debt	$ 0	$ 223,000
Letter of Credit
Line of Credit Facility [Line Items]
Short-term debt	$ 18,000	$ 18,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

XML

Borrowings and Other Financing Instruments, Credit Facility (Details) - USD ($)		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term debt		$ 0	$ 223,000,000
Credit Facility
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date		Jun. 30, 2021
Credit Facility	[1]	$ 500,000,000
Drawn	[2]	18,000,000
Available		482,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0

[1] This credit facility expires in June 2021.

[2] Includes outstanding letters of credit.

XML

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) - Credit Facility	6 Months Ended
	Jun. 30, 2016 USD ($)
Line of Credit Facility [Line Items]
Borrowing limit	$ 500,000,000	[1]
Debt Instrument, Maturity Date	Jun. 30, 2021
NSP-Minnesota
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	2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	1 year
NSP-Minnesota | 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-Minnesota | 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.

XML

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - NSP-Minnesota - Bonds [Member] - Series Due May 15, 2046 [Member]	1 Months Ended
	May 31, 2016 USD ($)
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 350,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.60%
Debt Instrument, Maturity Date	May 15, 2046

XML

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities (Details)	6 Months Ended
	Jun. 30, 2016
Minimum | Commingled and international equity funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption (in days)	1 day
Minimum | Real Estate Funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption (in days)	45 days
Maximum | Commingled and international equity funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption (in days)	90 days
Maximum | Real Estate Funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption (in days)	90 days

XML

Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2016		Dec. 31, 2015
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Gross Unrealized Gain	$ 336,500		$ 328,800
Available-for-sale Securities, Gross Unrealized Loss	95,200		100,200
Investments [Abstract]
Miscellaneous investments	44,500		34,100
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	15,749		27,484
Available-for-sale Securities [Abstract]
Available-for-sale Securities	1,513,516		1,495,599
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	389,700		392,838
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	259,090		259,114
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	119,370		105,965
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	72,956		61,816
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	35,199		24,444
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	96,110		73,061
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	19,959		13,726
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	11,966		49,255
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Asset-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	2,844		2,837
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Mortgage-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	10,708		11,444
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	479,865		473,615
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	15,749		27,484
Alternative Investments, Fair Value Disclosure	916,073	[1]	884,034	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities	1,754,802	[3]	1,724,150	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	411,788	[1]	410,634	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities	411,788		410,634
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International equity funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	236,087	[1]	231,122	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities	236,087		231,122
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	166,054	[1]	157,528	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities	166,054		157,528
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	102,144	[1]	84,750	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities	102,144		84,750
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	35,828		21,356
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	91,350		65,276
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International corporate bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	19,394		12,801
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Municipal bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	12,826		51,589
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Asset-backed Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	2,881		2,830
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Mortgage-backed Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	11,180		11,621
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Common stock
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investments, Fair Value Disclosure	0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	649,521		647,159
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	15,749		27,484
Available-for-sale Securities [Abstract]
Available-for-sale Securities	665,270		674,643
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Asset-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Mortgage-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	649,521		647,159
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Available-for-sale Securities [Abstract]
Available-for-sale Securities	173,459		165,473
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	35,828		21,356
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	91,350		65,276
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	19,394		12,801
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	12,826		51,589
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Asset-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	2,881		2,830
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Mortgage-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	11,180		11,621
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Asset-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Mortgage-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	$ 0		$ 0

[1] Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

[2] Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

[3] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $44.5 million of rabbi trust assets and miscellaneous investments.

[4] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $34.1 million of miscellaneous investments.

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Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Thousands	Jun. 30, 2016 USD ($)
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	$ 261
Due in 1 to 5 Years	41,825
Due in 5 to 10 Years	79,847
Due after 10 Years	51,526
Total	173,459
Government securities
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	10,659
Due in 5 to 10 Years	982
Due after 10 Years	24,187
Total	35,828
U.S. corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	261
Due in 1 to 5 Years	26,988
Due in 5 to 10 Years	59,368
Due after 10 Years	4,733
Total	91,350
International corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	3,966
Due in 5 to 10 Years	12,368
Due after 10 Years	3,060
Total	19,394
Municipal bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	212
Due in 5 to 10 Years	4,248
Due after 10 Years	8,366
Total	12,826
Asset-backed Securities
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	0
Due in 5 to 10 Years	2,881
Due after 10 Years	0
Total	2,881
Mortgage-backed Securities
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	0
Due in 5 to 10 Years	0
Due after 10 Years	11,180
Total	$ 11,180

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions		Jun. 30, 2016 USD ($) MMBTU gal MWh Counterparty	Dec. 31, 2015 MMBTU gal MWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		10
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		9
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		2
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 7.1
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		21.00%
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		3
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 6.6
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		19.00%
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 20.1
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		58.00%
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 | $		$ (0.8)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1],[2]	71,297	43,611
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	42,991	7,971
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	39	77

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

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

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		3 Months Ended			6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016		Jun. 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
Designated as Hedging Instrument | Cash Flow Hedges
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 accumulated other comprehensive loss		12,000	15,000		10,000		5,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		372,000	362,000		749,000		716,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0		0		0
Pre-tax gains (losses) recognized during the period in income		0	0		0		0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
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 accumulated other comprehensive loss		0	0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[1]	346,000	346,000		692,000		686,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0		0		0
Pre-tax gains (losses) recognized during the period in income		0	0		0		0
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other 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 accumulated other comprehensive loss		12,000	15,000		10,000		5,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[2]	26,000	16,000		57,000		30,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0		0		0
Pre-tax gains (losses) recognized during the period in income		0	0		0		0
Other Derivative Instruments
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 accumulated other comprehensive loss		0	0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(814,000)	(3,461,000)		(3,005,000)		(12,205,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		13,572,000	(6,327,000)		27,744,000		(14,271,000)
Pre-tax gains (losses) recognized during the period in income		269,000	4,210,000		(334,000)		10,910,000
Other Derivative Instruments | Commodity Trading
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 accumulated other comprehensive loss		0	0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0		0		0
Pre-tax gains (losses) recognized during the period in income	[3]	269,000	4,210,000		1,261,000		7,902,000
Other Derivative Instruments | Electric 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 accumulated other comprehensive loss		0	0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(1,193,000)	(3,517,000)		(2,752,000)		(12,223,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[4]	13,572,000	(6,327,000)		24,284,000		(11,520,000)
Pre-tax gains (losses) recognized during the period in income		0	0		0		0
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 accumulated other comprehensive loss		0	0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		379,000	56,000		(253,000)		18,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0	[5]	3,460,000	[5]	(2,751,000)	[5]
Pre-tax gains (losses) recognized during the period in income		$ 0	$ 0	[5]	$ (1,595,000)	[5]	$ 3,008,000	[5]

[1] Amounts are recorded to interest charges.

[2] Amounts are recorded to O&M expenses.

[3] Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

[4] Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

[5] Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

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Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Collateral posted on derivative instruments	$ 0	$ 0
Derivative instruments in a gross liability position	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Jun. 30, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		4,700		4,300
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(30,015)		(18,941)
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(22,946)		(22,334)
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(17,087)		(17,211)
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(120,654)		(128,213)
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(29,397)		(18,461)
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		8,709	[1]	5,715	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(5,030)		(6,065)
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		8,067	[1]	5,542	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(23,488)		(12,274)
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		642	[1]	167	[2]
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		(879)		(122)
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		0	[1]	6	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(22,062)		(20,844)
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		6,986	[1]	6,555	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(22,062)		(20,844)
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		6,986	[1]	6,555	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(45)		(113)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(2,977)		(3,102)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		9,267	[1]	6,753	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(2,932)		(1,633)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		8,625	[1]	6,580	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		642	[1]	167	[2]
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				(1,356)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[2]			6
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(9,710)		(10,085)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		11,162	[1]	9,780	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(9,710)		(10,085)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		11,162	[1]	9,780	[2]
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(3,428)		(88)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(3,428)		(88)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric 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 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 Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(997)		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(997)		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		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		(3,238)		(118)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(3,238)		(118)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		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 1 | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(1,086)		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(1,086)		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(10,548)		(10,397)
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(9,669)		(10,269)
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
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		(879)		(128)
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(28,051)		(27,399)
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(28,051)		(27,399)
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(45)		(113)
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		(8,364)		(9,016)
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(8,319)		(7,541)
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
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				(1,362)
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(19,786)		(19,865)
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(19,786)		(19,865)
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(24,130)		(13,691)
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		(1,250)
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(24,130)		(12,441)
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 Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		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		(642)		(721)
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		(554)
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(642)		(167)
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
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(618)	[3]	(480)	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(884)	[3]	(1,490)	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(14,110)	[3]	(14,109)	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(110,944)	[3]	(118,128)	[4]
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		(38,106)		(24,176)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(13,097)		(11,607)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(24,130)		(12,441)
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		(879)		(128)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(29,048)		(27,399)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(29,048)		(27,399)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(45)		(113)
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		(12,244)		(9,855)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(11,557)		(8,213)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(642)		(167)
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				(1,362)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(20,872)		(19,865)
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ (20,872)		$ (19,865)

[1] NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.7 million. 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] NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[3] In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

[4] In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 5,124,000	$ 10,972,000	$ 12,969,000	$ 40,271,000
Purchases		27,870,000	40,162,000	27,870,000	41,025,000
Settlements		(6,981,000)	(7,294,000)	(12,039,000)	(18,845,000)
(Losses) gains recognized in earnings	[1]	22,000	1,220,000	(2,000)	1,280,000
(Losses) recognized as regulatory assets and liabilities		(2,547,000)	(9,697,000)	(5,310,000)	(28,368,000)
Balance at end of period		23,488,000	35,363,000	23,488,000	35,363,000
Transfers into Level 3		0	0		0
Transfers out of Level 3		$ 0	$ 0	$ 0	$ 0

[1] These amounts relate to commodity derivatives held at the end of the period.

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion (a)	[1]	$ 4,841,587	$ 4,496,421
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion (a)	[1]	$ 5,730,663	$ 4,917,080

[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.

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Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Rabbi Trust (Details) - Fair Value Measured on a Recurring Basis $ in Thousands	Jun. 30, 2016 USD ($)
Cost | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	$ 7,448
Trading Securities	9,041
Cost | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	1,593
Fair Value | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	7,448
Trading Securities	9,226	[1]
Fair Value | Rabbi Trust [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	7,448
Trading Securities	9,226
Fair Value | Rabbi Trust [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0
Trading Securities	0
Fair Value | Rabbi Trust [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0
Trading Securities	0
Fair Value | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	1,778
Fair Value | Mutual Funds [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	1,778
Fair Value | Mutual Funds [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	0
Fair Value | Mutual Funds [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	$ 0

[1] (a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

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Other (Expense) Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Other Income and Expenses [Abstract]
Interest Income	$ 129	$ 92	$ 3,465	$ 3,424
Other nonoperating income	107	60	271	92
Insurance policy expense	(823)	(428)	(1,463)	(1,831)
Other (expense) income, net	$ (587)	$ (276)	$ 2,273	$ 1,685

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Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 1,088,100		$ 1,081,974		$ 2,322,733		$ 2,374,456
Net income (loss)	78,176		74,181		172,805		81,105
Affiliate electric revenue	113,127		117,830		238,023		242,705
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	1,016,733		1,000,125		2,050,521		2,006,412
Net income (loss)	78,781		90,697		150,102		61,098	[1]
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	64,457		75,345		258,749		355,222
Net income (loss)	458		(16,422)		23,600		23,850
All Other
Segment Reporting Information [Line Items]
Operating revenues	7,258		6,863		14,118		13,724
Net income (loss)	(1,063)		(94)		(897)		(3,843)
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,088,100	[2],[3]	1,081,974	[2],[3]	2,322,733	[4],[5]	2,374,456	[4],[5]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	1,016,471	[2]	999,872	[2]	2,050,114	[4]	2,006,026	[4]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	64,371	[3]	75,239	[3]	258,501	[5]	354,706	[5]
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	7,258		6,863		14,118		13,724
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(348)		(359)		(655)		(902)
Net income (loss)	0		0		0		0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	262		253		407		386
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	86		106		248		516
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0		$ 0		$ 0		$ 0

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

[2] Operating revenues include $113 million and $118 million of affiliate electric revenue for the three months ended June 30, 2016 and 2015, respectively.

[3] Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2016 and 2015.

[4] Operating revenues include $238 million and $243 million of affiliate electric revenue for the six months ended June 30, 2016 and 2015, respectively.

[5] Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2016 and 2015.

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2016 USD ($) Plan	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 7,077	$ 7,889	$ 14,154	$ 15,778
Interest cost		11,358	10,803	22,716	21,607
Expected return on plan assets		(15,236)	(15,707)	(30,472)	(31,415)
Amortization of prior service cost (credit)		234	234	468	468
Amortization of net loss		9,194	11,548	18,388	23,096
Net periodic benefit cost		12,627	14,767	25,254	29,534
Costs not recognized due to the effects of regulation		(5,296)	(7,843)	(10,592)	(15,685)
Net benefit cost recognized for financial reporting		7,331	6,924	14,662	13,849
Total contributions to the pension plans during the period	$ 49,400
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		31	40	62	80
Interest cost		981	953	1,962	1,907
Expected return on plan assets		(43)	(30)	(86)	(60)
Amortization of prior service cost (credit)		(759)	(759)	(1,518)	(1,518)
Amortization of net loss		401	523	802	1,046
Net periodic benefit cost		611	727	1,222	1,455
Costs not recognized due to the effects of regulation		0	0	0	0
Net benefit cost recognized for financial reporting		$ 611	$ 727	$ 1,222	$ 1,455
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

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period			$ 5,167,065
(Gains) losses reclassified from net accumulated other comprehensive loss	$ 240	$ 208	482	$ 411
Accumulated other comprehensive (loss) income at end of period	5,259,400		5,259,400
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(18,868)	(19,707)	(19,090)	(19,909)
Other comprehensive income (loss) before reclassifications	7	9	6	2
(Gains) losses reclassified from net accumulated other comprehensive loss	221	214	444	423
Net current period other comprehensive income (loss)	228	223	450	425
Accumulated other comprehensive (loss) income at end of period	(18,640)	(19,484)	(18,640)	(19,484)
Unrealized Gains and Losses on Marketable Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	105	106	105	105
Other comprehensive income (loss) before reclassifications	0	1	0	2
(Gains) losses reclassified from net accumulated other comprehensive loss	0	0	0	0
Net current period other comprehensive income (loss)	0	1	0	2
Accumulated other comprehensive (loss) income at end of period	105	107	105	107
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(2,077)	(1,016)	(2,096)	(1,010)
Other comprehensive income (loss) before reclassifications	0	0	0	0
(Gains) losses reclassified from net accumulated other comprehensive loss	19	(6)	38	(12)
Net current period other comprehensive income (loss)	19	(6)	38	(12)
Accumulated other comprehensive (loss) income at end of period	(2,058)	(1,022)	(2,058)	(1,022)
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(20,840)	(20,617)	(21,081)	(20,814)
Other comprehensive income (loss) before reclassifications	7	10	6	4
(Gains) losses reclassified from net accumulated other comprehensive loss	240	208	482	411
Net current period other comprehensive income (loss)	247	218	488	415
Accumulated other comprehensive (loss) income at end of period	$ (20,593)	$ (20,399)	$ (20,593)	$ (20,399)

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Other Comprehensive Income (Reclassification from AOCI) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	$ 318,540	$ 311,512	$ 639,036	$ 625,562
Total, pre-tax	(113,610)	(113,642)	(254,707)	(123,536)
Tax benefit	35,434	39,461	81,902	42,431
Total amounts reclassified, net of tax	240	208	482	411
Gains and Losses on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax	221	214	444	423
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	372	362	749	716
Tax benefit	(151)	(148)	(305)	(293)
Total, net of tax	221	214	444	423
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	346	346	692	686
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	26	16	57	30
Amortization of net loss | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	83	40	166	77
Prior service credit | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	(49)	(48)	(98)	(99)
Defined Benefit Pension and Postretirement Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax	19	(6)	38	(12)
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	34	(8)	68	(22)
Tax (benefit) expense	(15)	2	(30)	10
Total amounts reclassified, net of tax	$ 19	$ (6)	$ 38	$ (12)