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 March 31, 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 May 13, 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	26
Item 4 —	Controls and Procedures	30
PART II —	OTHER INFORMATION
Item 1 —	Legal Proceedings	31
Item 1A —	Risk Factors	31
Item 4 —	Mine Safety Disclosures	31
Item 5 —	Other Information	31
Item 6 —	Exhibits	32
SIGNATURES		33
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).

2

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016			2015
Operating revenues
Electric, non-affiliates	$	908,747		$	881,279
Electric, affiliates	124,896			124,875
Natural gas	194,130			279,467
Other	6,860			6,861
Total operating revenues	1,234,633			1,292,482
Operating expenses
Electric fuel and purchased power	366,166			398,720
Cost of natural gas sold and transported	120,223			201,189
Cost of sales — other	4,432			4,327
Operating and maintenance expenses	320,496			314,050
Conservation program expenses	23,269			17,212
Depreciation and amortization	145,797			118,075
Taxes (other than income taxes)	70,352			63,832
Loss on Monticello life cycle management/extended power uprate project	—			124,226
Total operating expenses	1,050,735			1,241,631
Operating income	183,898			50,851
Other income, net	2,860			1,962
Allowance for funds used during construction — equity	5,648			5,930
Interest charges and financing costs
Interest charges — includes other financing costs of $1,742 and $1,610, respectively	54,015			51,763
Allowance for funds used during construction — debt	(2,706		)	(2,914		)
Total interest charges and financing costs	51,309			48,849
Income before income taxes	141,097			9,894
Income taxes	46,468			2,970
Net income	$	94,629		$	6,924

See Notes to Consolidated Financial Statements

3

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016			2015
Net income	$	94,629		$	6,924
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $15 and ($4), respectively	19			(6		)
Derivative instruments:
Net fair value decrease, net of tax of $(1) and $(4), respectively	(1		)	(6		)
Reclassification of losses to net income, net of tax of $154 and $143, respectively	223			208
	222			202
Marketable securities:
Net fair value increase, net of tax of $0 and $0, respectively	—			1
Other comprehensive income	241			197
Comprehensive income	$	94,870		$	7,121

See Notes to Consolidated Financial Statements

4

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016			2015
Operating activities
Net income	$	94,629		$	6,924
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	147,310			119,459
Nuclear fuel amortization	25,750			28,465
Deferred income taxes	47,018			9,565
Amortization of investment tax credits	(420		)	(433		)
Allowance for equity funds used during construction	(5,648		)	(5,930		)
Loss on Monticello life cycle management/extended power uprate project	—			124,226
Net realized and unrealized hedging and derivative transactions	1,890			6,385
Changes in operating assets and liabilities:
Accounts receivable	(45,382		)	10,584
Accrued unbilled revenues	40,322			57,484
Inventories	35,378			27,059
Other current assets	(14,146		)	14,042
Accounts payable	(4,057		)	(8,405		)
Net regulatory assets and liabilities	51,517			37,558
Other current liabilities	(12,118		)	42,288
Pension and other employee benefit obligations	(48,074		)	(32,330		)
Change in other noncurrent assets	(43		)	(115		)
Change in other noncurrent liabilities	(1,112		)	(21,480		)
Net cash provided by operating activities	312,814			415,346
Investing activities
Utility capital/construction expenditures	(259,570		)	(322,660		)
Allowance for equity funds used during construction	5,648			5,930
Proceeds from insurance recoveries	—			24,241
Purchases of investments in external decommissioning fund	(109,373		)	(387,826		)
Proceeds from the sale of investments in external decommissioning fund	104,280			386,111
Investments in utility money pool arrangement	—			(15,000		)
Repayments from utility money pool arrangement	—			15,000
Other, net	(2,084		)	(2,244		)
Net cash used in investing activities	(261,099		)	(296,448		)
Financing activities
Repayments of short-term borrowings, net	(150,000		)	(66,000		)
Borrowings under utility money pool arrangement	310,000			31,000
Repayments under utility money pool arrangement	(217,000		)	(31,000		)
Repayments of long-term debt	—			(33		)
Capital contributions from parent	89,874			75,835
Dividends paid to parent	(73,498		)	(77,802		)
Net cash used in financing activities	(40,624		)	(68,000		)
Net change in cash and cash equivalents	11,091			50,898
Cash and cash equivalents at beginning of period	42,605			40,597
Cash and cash equivalents at end of period	$	53,696		$	91,495
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(69,643	)	$	(64,798	)
Cash (paid) received for income taxes, net	(7,558		)	23,769
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	56,605		$	108,900

See Notes to Consolidated Financial Statements

5

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	March 31, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	53,696		$	42,605
Accounts receivable, net	332,976			292,806
Accounts receivable from affiliates	23,188			32,850
Accrued unbilled revenues	186,780			227,102
Inventories	308,578			343,916
Regulatory assets	178,943			187,793
Derivative instruments	12,638			18,941
Deferred income taxes	34,561			15,577
Prepayments and other	102,220			89,559
Total current assets	1,233,580			1,251,149
Property, plant and equipment, net	12,828,607			12,807,338
Other assets
Nuclear decommissioning fund and other investments	1,769,992			1,758,208
Regulatory assets	1,199,305			1,159,217
Derivative instruments	28,038			22,334
Other	1,428			1,385
Total other assets	2,998,763			2,941,144
Total assets	$	17,060,950		$	16,999,631
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	11		$	11
Short-term debt	73,000			223,000
Borrowings under utility money pool arrangement	93,000			—
Accounts payable	298,918			350,660
Accounts payable to affiliates	54,889			59,785
Regulatory liabilities	50,435			43,920
Taxes accrued	282,379			225,361
Accrued interest	47,122			66,979
Dividends payable to parent	82,228			73,498
Derivative instruments	18,239			17,211
Customer Deposits	78,477			94,388
Other	142,440			177,795
Total current liabilities	1,221,138			1,332,608
Deferred credits and other liabilities
Deferred income taxes	2,637,057			2,572,087
Deferred investment tax credits	25,418			25,838
Regulatory liabilities	506,044			491,887
Asset retirement obligations	2,359,476			2,331,092
Derivative instruments	129,383			128,213
Pension and employee benefit obligations	290,885			339,663
Other	139,409			114,768
Total deferred credits and other liabilities	6,087,672			6,003,548
Commitments and contingencies
Capitalization
Long-term debt	4,497,432			4,496,410
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at March 31, 2016 and Dec. 31, 2015, respectively	10			10
Additional paid in capital	3,398,810			3,323,810
Retained earnings	1,876,728			1,864,326
Accumulated other comprehensive loss	(20,840		)	(21,081		)
Total common stockholder’s equity	5,254,708			5,167,065
Total liabilities and equity	$	17,060,950		$	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 March 31, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2016 and 2015; and its cash flows for the three months endedMarch 31, 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 March 31, 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.

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.

7

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 is currently evaluating the impact of adopting ASU 2016-09 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 are 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)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	352,249		$	313,556
Less allowance for bad debts	(19,273		)	(20,750		)
	$	332,976		$	292,806

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	208,090	$	200,888
Fuel	88,287		104,499
Natural gas	12,201		38,529
	$	308,578	$	343,916

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	16,298,761		$	16,256,887
Natural gas plant	1,249,933			1,248,408
Common and other property	622,749			624,409
Construction work in progress	650,693			545,535
Total property, plant and equipment	18,822,136			18,675,239
Less accumulated depreciation	(6,354,488		)	(6,251,498		)
Nuclear fuel	2,450,363			2,447,251
Less accumulated amortization	(2,089,404		)	(2,063,654		)
	$	12,828,607		$	12,807,338

8

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 the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 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); 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 March 31, 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 March 31, 2016, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

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

(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	20.5	$	20.1
Unrecognized tax benefit — Temporary tax positions	37.0		35.3
Total unrecognized tax benefit	$	57.5	$	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)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(16.3	)	$	(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 and state audits resume. As the IRS Appeals and audit 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 March 31, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 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, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

9

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

NSP-Minnesota – 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

NSP-Minnesota also proposed a five-year alternative plan that would extend the rate plan two additional years. In addition, NSP-Minnesota has requested the MPUC encourage parties to engage in a formal mediation type procedure as outlined by Minnesota’s rate case statute which may streamline the settlement process.

In December 2015, the MPUC approved interim rates for 2016. The MPUC deferred making a decision on incremental interim rates for 2017 and indicated that NSP-Minnesota could bring back its request in the fourth quarter of 2016.

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

(Millions of Dollars)	2016			2017			2018			Total
2014 multi-year rate case items:
Excess depreciation reserve	$	26.0		$	51.0		$	—		$	77.0
Department of Energy (DOE) settlement	25.7			—			—			25.7
Monticello life cycle management (LCM)/extended power uprate (EPU)	11.2			(1.6		)	(1.5		)	8.1
	62.9			49.4			(1.5		)	110.8
Additional items:
Capital investments	128.7			12.8			44.6			186.1
Property taxes	30.2			7.6			5.2			43.0
NOL carryforwards	(6.3		)	(24.5		)	(6.5		)	(37.3		)
Other costs	(20.9		)	6.8			8.6			(5.5		)
	131.7			2.7			51.9			186.3
Total rate request	$	194.6		$	52.1		$	50.4		$	297.1

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

• Intervenors’ direct testimony — June 14, 2016;

• Rebuttal testimony — Aug. 9, 2016;

• Surrebuttal testimony — Sept. 16, 2016;

• Settlement conference — Sept. 26, 2016;

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

• Administrative law judge (ALJ) report — Feb. 21, 2017; and

• MPUC order — June 1, 2017.

10

2016 Transmission Cost Recovery (TCR) Filing — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. This filing included an option to keep approximately $59.1 million of revenue requirements associated with two

CapX2020 projects completed in 2015 within the TCR rider or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. In November 2015, NSP-Minnesota submitted an update to its TCR filing in which it confirmed that it was requesting the MPUC approve keeping the two CapX2020 projects in the TCR rider, increasing the revenue requirements to $78.3 million, until the conclusion of the 2016 Minnesota electric rate case.

In April 2016, NSP-Minnesota received comments from the Minnesota Department of Commerce (DOC) requesting additional support for the costs incurred for the CapX2020 La Crosse-Madison project and the CapX2020 Big Stone-Brookings project, as well as the updated financial impact for the actual non-prorated accumulated deferred income tax (ADIT) as opposed to the forecasted prorated ADIT used in the cost recovery calculations. An MPUC decision is expected later in 2016.

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/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 June 2014 the FERC adopted a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

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 no earlier than late 2016 or 2017.

Certain MISO TOs separately requested FERC approval of a 50 basis point ROE adder for RTO membership, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. Certain intervenors sought rehearing of this order, which the FERC denied in 2015.

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 Minnesota Department of Commerce (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. An ALJ initial decision is expected in June 2016 with a FERC decision expected no earlier than late 2016 or 2017.

NSP-Minnesota has recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of March 31, 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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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.

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 March 31, 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)	March 31, 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 July 2016 to allow NSP-Minnesota time to further investigate site conditions.

As of March 31, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $2.2 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 PRPs. 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

Air

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the United States Environmental Protection Agency (EPA) amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Minnesota identified the NSP-Minnesota facilities that will have to reduce sulfur dioxide (SO₂), nitrous oxide (NOx) and particulate matter (PM) emissions under BART and set emissions limits for those facilities.

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In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO₂. The MPCA supplemented its SIP in 2012, determining that the Cross-State Air Pollution Rule (CSAPR) meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, the EPA approved the SIP for electric generating units and also approved the source-specific emission limits for Sherco Units 1 and 2. The combustion controls were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million. NSP-Minnesota has included these costs for recovery in rate proceedings.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit). In January 2016, the Eighth Circuit issued their opinion which upheld the EPA’s approval of the SIP. In March 2016, after granting a rehearing request, the Eighth Circuit issued a revised opinion that included additional explanation and continued to uphold the EPA’s approval of the SIP.

Reasonably Attributable Visibility Impairment (RAVI) —RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the United States Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.

In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota (Minnesota District Court) by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club.

In May 2015, NSP-Minnesota, the EPA and the six environmental advocacy organizations filed a settlement agreement in the Minnesota District Court.  The agreement anticipates a federal rulemaking that would impose stricter SO₂ emission limits on Sherco Units 1, 2 and 3, without making a RAVI attribution finding or a RAVI BART determination.  The emission limits for Units 1 and 2 reflect the success of a recently completed control project. The Unit 3 emission limits will be met through changes in the operation of the existing scrubber.  The Minnesota District Court issued an order staying the litigation for the time needed to complete the actions required by the settlement agreement.  The plaintiffs agreed to withdraw their complaint with prejudice when those actions are completed.  Plaintiffs also agreed not to request a RAVI certification for Sherco Units 1, 2 and/or 3 in the future.

In March 2016, the EPA adopted a final rule which set the agreed-upon SO₂ emission limits.  As a result, the Minnesota District Court dismissed the litigation with prejudice in March 2016. NSP-Minnesota does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

Implementation of the National Ambient Air Quality Standard (NAAQS) for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where NSP-Minnesota operates power plants.  However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the Clean Air Act and under a consent decree 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 system costs 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.

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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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	250		$	250
Amount outstanding at period end	93			—
Average amount outstanding	39			5
Maximum amount outstanding	225			69
Weighted average interest rate, computed on a daily basis	0.71		%	0.53		%
Weighted average interest rate at period end	0.71			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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	500		$	500
Amount outstanding at period end	73			223
Average amount outstanding	224			96
Maximum amount outstanding	353			327
Weighted average interest rate, computed on a daily basis	0.66		%	0.43		%
Weighted average interest rate at period end	0.55			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 March 31, 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 to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

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At March 31, 2016, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	91	$	409

^(a)  This credit facility expires in October 2019.

^(b)  Includes outstanding commercial paper and 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 March 31, 2016 and Dec. 31, 2015.

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.

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 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.

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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, generally referred to as financial transmission rights (FTRs), purchased from MISO, PJM Interconnection, LLC, Electric Reliability Council of Texas, Southwest Power Pool, Inc. and New York Independent System Operator. FTRs purchased from an 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 overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid 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 – including expected plant operating schedules and retail and wholesale demand, 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

The Nuclear Regulatory Commission (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 Prairie Island (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. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, 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. 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 $322.7 million and $328.8 million at March 31, 2016 and Dec. 31, 2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $100.3 million and $100.2 million at March 31, 2016 and Dec. 31, 2015, respectively.

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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 March 31, 2016 and Dec. 31, 2015:

	March 31, 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	$	11,899	$	11,899	$	—	$	—	$	—	$	11,899
Commingled funds	390,345		—		—		—		395,709		395,709
International equity funds	264,340		—		—		—		242,312		242,312
Private equity investments	108,882		—		—		—		158,915		158,915
Real estate	73,577		—		—		—		100,576		100,576
Debt securities:
Government securities	24,320		—		23,213		—		—		23,213
U.S. corporate bonds	76,952		—		70,723		—		—		70,723
International corporate bonds	18,117		—		17,343		—		—		17,343
Municipal bonds	47,088		—		49,902		—		—		49,902
Asset-backed securities	2,841		—		2,836		—		—		2,836
Mortgage-backed securities	11,065		—		11,407		—		—		11,407
Equity securities:
Common stock	481,968		649,015		—		—		—		649,015
Total	$	1,511,394	$	660,914	$	175,424	$	—	$	897,512	$	1,733,850

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $36.1 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.

	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.

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For the three months ended March 31, 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 March 31, 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	$	—	$	—	$	3,144	$	20,069		$	23,213
U.S. corporate bonds	—		18,909		56,102		(4,288		)	70,723
International corporate bonds	—		2,795		11,505		3,043			17,343
Municipal bonds	151		266		16,323		33,162			49,902
Asset-backed securities	—		—		2,836		—			2,836
Mortgage-backed securities	—		—		—		11,407			11,407
Debt securities	$	151	$	21,970	$	89,910	$	63,393		$	175,424

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 March 31, 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, which is made up of management personnel not directly involved in the activities governed by this policy.

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 March 31, 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 months ended March 31, 2016 and 2015.

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At March 31, 2016, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of 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 March 31, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	23,336	43,611
Million British thermal units of natural gas	9,523	7,971
Gallons of vehicle fuel	58	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 months ended March 31, 2016 and 2015 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended March 31, 2016
	Pre-Tax Fair Value 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	$	—		$	—		$	346	(a)	$	—		$	—
Vehicle fuel and other commodity	(2		)	—			31		(b)	—			—
Total	$	(2	)	$	—		$	377		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	992		(c)
Electric commodity	—			(1,558		)	—			10,712		(d)	—
Natural gas commodity	—			(631		)	—			3,460		(e)	(1,595		)	(e)
Total	$	—		$	(2,189	)	$	—		$	14,172		$	(603	)

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	Three Months Ended March 31, 2015
	Pre-Tax Fair Value 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	$	—		$	—		$	337	(a)	$	—			$	—
Vehicle fuel and other commodity	(10		)	—			14		(b)	—				—
Total	$	(10	)	$	—		$	351		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—			$	3,691	(c)
Electric commodity	—			(8,706		)	—			(5,193		)	(d)	—
Natural gas commodity	—			(38		)	—			(2,751		)	(e)	3,008		(e)
Total	$	—		$	(8,744	)	$	—		$	(7,944	)		$	6,699

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to operating and maintenance (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 months ended March 31, 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 continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-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 when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At March 31, 2016, seven of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $23.9 million or 34 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. One of the 10 most significant counterparties, comprising $0.8 million or 1 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 of these significant counterparties, comprising $8.9 million or 13 percent of this credit exposure, had credit quality less than investment grade, based on NSP-Minnesota's internal analysis. Eight of these significant counterparties are RTOs, 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 March 31, 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.

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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 March 31, 2016 and Dec. 31, 2015.

Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2016:

	March 31, 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	$	162	$	14,775	$	453	$	15,390	$	(7,936	)	$	7,454
Electric commodity	—		—		4,761		4,761		(55		)	4,706
Total current derivative assets	$	162	$	14,775	$	5,214	$	20,151	$	(7,991	)	12,160
PPAs (a)												478
Current derivative instruments												$	12,638
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	250	$	35,198	$	—	$	35,448	$	(8,893	)	$	26,555
Total noncurrent derivative assets	$	250	$	35,198	$	—	$	35,448	$	(8,893	)	26,555
PPAs (a)												1,483
Noncurrent derivative instruments												$	28,038

	March 31, 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	$	—	$	84	$	—	$	84	$	—		$	84
Other derivative instruments:
Commodity trading	176		12,496		35		12,707		(8,665		)	4,042
Electric commodity	—		—		55		55		(55		)	—
Total current derivative liabilities	$	176	$	12,580	$	90	$	12,846	$	(8,720	)	4,126
PPAs (a)												14,113
Current derivative instruments												$	18,239
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	215	$	27,000	$	—	$	27,215	$	(12,497	)	$	14,718
Total noncurrent derivative liabilities	$	215	$	27,000	$	—	$	27,215	$	(12,497	)	14,718
PPAs (a)												114,665
Noncurrent derivative instruments												$	129,383

^(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 March 31, 2016. At March 31, 2016, 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.

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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.

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The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	12,970		$	40,271
Purchases	—			864
Settlements	(5,038		)	(11,552		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(24		)	60
Losses recognized as regulatory assets and liabilities	(2,784		)	(18,671		)
Balance at March 31	$	5,124		$	10,972

^(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 months ended March 31, 2016 and 2015.

Fair Value of Long-Term Debt

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

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,497,443	$	5,149,155	$	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 March 31, 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 Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	3,336		$	3,332
Other nonoperating income	164			33
Insurance policy expense	(640		)	(1,403		)
Other income, net	$	2,860		$	1,962

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.

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• 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 March 31, 2016
Operating revenues (a)(b)	$	1,033,643	$	194,130	$	6,860	$	—		$	1,234,633
Intersegment revenues	145		162		—		(307		)	—
Total revenues	$	1,033,788	$	194,292	$	6,860	$	(307	)	$	1,234,633
Net income	$	71,321	$	23,142	$	166	$	—		$	94,629

(Thousands of Dollars)	Regulated Electric				Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2015
Operating revenues (a)(b)	$	1,006,154			$	279,467	$	6,861		$	—		$	1,292,482
Intersegment revenues	133				410		—			(543		)	—
Total revenues	$	1,006,287			$	279,877	$	6,861		$	(543	)	$	1,292,482
Net income (loss)	$	(29,599	)	(c)	$	40,272	$	(3,749	)	$	—		$	6,924

^(a)  Operating revenues include $125 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 2016 and 2015.

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

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	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			10,804			981			954
Expected return on plan assets	(15,236		)	(15,708		)	(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			728
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		$	728

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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12. Other Comprehensive Income

Changes in accumulated other comprehensive income (loss), net of tax, for the three months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 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 loss before reclassifications	(1		)	—		—			(1		)
Losses reclassified from net accumulated other comprehensive loss	223			—		19			242
Net current period other comprehensive income	222			—		19			241
Accumulated other comprehensive (loss) income at March 31	$	(18,868	)	$	105	$	(2,077	)	$	(20,840	)

	Three Months Ended March 31, 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 (loss) income before reclassifications	(6		)	1		—			(5		)
Losses (gains) reclassified from net accumulated other comprehensive loss	208			—		(6		)	202
Net current period other comprehensive income (loss)	202			1		(6		)	197
Accumulated other comprehensive (loss) income at March 31	$	(19,707	)	$	106	$	(1,016	)	$	(20,617	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		(a)	$	337		(a)
Vehicle fuel derivatives	31			(b)	14			(b)
Total, pre-tax	377				351
Tax benefit	(154		)		(143		)
Total, net of tax	223				208
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	83			(c)	39			(c)
Prior service credit	(49		)	(c)	(49		)	(c)
Total, pre-tax	34				(10		)
Tax (benefit) expense	(15		)		4
Total, net of tax	19				(6		)
Total amounts reclassified, net of tax	$	242			$	202

^(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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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).

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), 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 $94.6 million for the first quarter of 2016, compared with approximately $6.9 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 electric non-fuel riders were partially offset by higher depreciation, higher property taxes and unfavorable weather. The negative impact of weather was partially mitigated by an electric weather decoupling mechanism, approved in the 2014 Minnesota Multi-Year Electric Rate Case. 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:

	Three Months Ended March 31
(Millions of Dollars)	2016			2015
Electric revenues	$	1,034		$	1,006
Electric fuel and purchased power	(366		)	(399		)
Electric margin	$	668		$	607

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The following tables summarize the components of the changes in electric revenues and electric margin:

Electric Revenues

(Millions of Dollars)	2016 vs. 2015
Retail rate increases (a)	$	34
Non-fuel riders	9
Transmission revenue	6
Weather decoupling - Minnesota	4
Conservation program revenue (offset by expenses)	4
Fuel and purchased power cost recovery	(27		)
Estimated impact of weather	(8		)
Other, net	6
Total increase in electric revenues	$	28

Electric Margin

(Millions of Dollars)	2016 vs. 2015
Retail rate increases (a)	$	34
Non-fuel riders	9
Interchange revenues from NSP-Wisconsin	8
Weather decoupling - Minnesota	4
Conservation program revenue (offset by expenses)	4
Estimated impact of weather	(8		)
Other, net	10
Total increase in electric margin	$	61

^(a)  Increase is primarily related to the Minnesota Electric Rate Case (interim, subject to 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:

	Three Months Ended March 31
(Millions of Dollars)	2016			2015
Natural gas revenues	$	194		$	279
Cost of natural gas sold and transported	(120		)	(201		)
Natural gas margin	$	74		$	78

The following tables summarize the components of the changes in natural gas revenues and natural gas margin:

Natural Gas Revenues

(Millions of Dollars)	2016 vs. 2015
Purchased natural gas adjustment clause recovery	$	(79	)
Estimated impact of weather	(6		)
Conservation program revenue (offset by expenses)	2
Other, net	(2		)
Total decrease in natural gas revenues	$	(85	)

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Natural Gas Margin

(Millions of Dollars)	2016 vs. 2015
Estimated impact of weather	$	(6	)
Conservation program revenue (offset by expenses)	2
Total decrease in natural gas margin	$	(4	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased $6.4 million, or 2.1 percent, for the first quarter of 2016. The increase was primarily due to interchange agreement billings with NSP-Wisconsin related to the timing of transmission projects and higher gas survey costs, 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$6.1 million for the first quarter of 2016. The increase was primarily attributable to higher electric and gas recovery rates. Higher conservation program expenses are generally offset by higher revenues.

Depreciation and Amortization— Depreciation and amortization expense increased$27.7 million, or 23.5 percent, for the first quarter of 2016. The increase was primarily attributable to capital investments, including Pleasant Valley and Border Wind Farms which were placed into service in late 2015.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased$6.5 million, or 10.2 percent, for the first quarter of 2016. The increase was due to higher property taxes primarily in Minnesota.

Interest Charges — Interest charges increased$2.3 million, or 4.4 percent, for the first quarter of 2016. The increase was primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased$43.5 million for the first quarter of 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 effective tax rate (ETR) was 32.9 percent for the first quarter of 2016, compared with 30.0 percent for the same period in 2015. The lower ETR for 2015 is primarily due to lower pretax earnings.

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, 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.

In October 2015, NSP-Minnesota proposed revisions to the Plan. The revised proposal addressed stakeholder recommendations as well as the then final 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. 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;

• 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 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.

28

NSP-Minnesota believes this will provide substantial opportunities for the ownership of renewable generation and replacement thermal generation. In January 2016, NSP-Minnesota filed supplemental economic and technical information in support of its revised Plan. While the CPP was subsequently stayed, the filing demonstrated anticipated compliance with the CPP while maintaining reasonable costs for customers. Additionally, NSP-Minnesota responded to MPUC inquiries regarding 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. The MPUC has authorized the DOC to engage an expert to aid in its analysis of PI information provided, the results of which are expected to influence NSP-Minnesota’s proposed resource portfolio in its next resource plan. Comments and reply comments on the Plan are due July 8, 2016 and Aug. 12, 2016, respectively. The MPUC is expected to make a decision on the resource plan in late 2016.

North Dakota Energy Resource Considerations — In February 2014, the NDPSC approved a settlement agreement between NSP-Minnesota and NDPSC Advocacy Staff in resolution of the 2013 North Dakota electric rate case.  Among other things, the settlement agreement included a commitment to develop a generation cost allocation mechanism for serving North Dakota customers in a way that reflects North Dakota energy policy.  In September 2015, NSP-Minnesota and NDPSC Advocacy Staff partially satisfied this commitment through joint filing of a Negotiated Agreement (NA).  On Feb. 22, 2016, NSP-Minnesota filed a Revised Negotiated Agreement (RNA) in order to clarify certain provisions of the NA with respect to potential actions by future commissions and staff and as a result of future new federal regulations. On March 9, 2016, the NDPSC approved the RNA, with key terms including:

• Acceleration of NSP-Minnesota’s previous settlement commitment to locate thermal generation in North Dakota from 2036 to by the end of 2025;

• Exclusion of select wind and small solar PPAs from NSP-Minnesota’s North Dakota fuel cost rider;

• Continued recovery in North Dakota of six existing biomass PPAs, subject, in part, to refund if NSP-Minnesota fails to achieve its generation commitment by the end of 2025;

• Extension of the current rate moratorium through 2017;

• A rebuttable presumption of prudence for continued use of the 12-coincident peak system allocator through 2025; and,

• Development of a framework to address future generation resources to be filed with the NDPSC by Jan. 1, 2017.

NSP-Minnesota’s Petition for an Advance Determination of Prudence — In February 2016, the NDPSC discussed NSP-Minnesota’s Petition for an Advance Determination of Prudence (ADP) for 345 MW of capacity and associated energy to be added to the NSP System through a 20-year PPA with Mankato Energy Center, LLC, an affiliate of Calpine Corporation. In March 2016, the NDPSC voted to dismiss NSP-Minnesota's ADP application without prejudice due to concerns that the resource would not be necessary by the 2019 expected in-service date. The North Dakota portion of the PPA is approximately $1.2 million per year.

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.

Nuclear Regulatory Performance— The NRC has a Reactor Oversight Process that classifies U.S. nuclear reactors into various categories (referred to as Columns, from 1 to 5).  Issues are evaluated as either green, white, yellow, or red based on their safety significance, with green representing the least safety concern and red representing the most concern. 

At March 31, 2016, Monticello and PI Unit 1 were in Column 1 (licensee response) with all green performance indicators and no greater than green findings or violations. Plants in Column 1 are subject to only a pre-defined set of basic NRC inspections.

Based on a December 2015 shutdown, PI Unit 2 moved from Column 1 to Column 2 (regulatory response) due to a white performance indicator related to the level of unplanned rapid shutdowns of the nuclear reactor, of which only a certain level is allowed per year to remain at the green performance level. Plants in Column 2 are subject to special NRC inspections to review and validate that performance issues or inspection findings have been properly addressed. PI Unit 2 returned to service in late February 2016 after addressing the issues leading to shutdown and will be eligible to return to Column 1 once the performance indicator returns to green, subject to an NRC inspection to close the issue. Depending on the unit’s operation in 2016, PI Unit 2 could return to green performance and Column 1 later in 2016.

29

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, 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. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In March, 2015, FERC upheld the new ROE methodology and denied rehearing. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. Two complaints against the MISO Transmission Owners, including NSP-Minnesota and NSP-Wisconsin, are pending FERC action. FERC is not expected to issue orders in any of the litigated ROE complaint proceedings until 2016 or 2017. See Note 5 to the consolidated financial statements for discussion of the MISO ROE Complaints.

Formula Rate Treatment of ADIT - In 2015, the MISO Transmission Owners, including NSP-Minnesota and NSP-Wisconsin filed separate changes to their transmission formula rates to modify the treatment of ADIT to comply with 2015 IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings are 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.

SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) -SPP and MISO were involved in a long-running dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagreed over MISO’s authority to transmit power between the traditional MISO region in the Midwest and the Entergy system. Several cases were filed with the FERC by MISO and SPP between 2011 and 2014. In June 2014, the FERC set the issues for settlement judge and hearing procedures.

In January 2016, the FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provide a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period (February 2014 to January 2016) and $16 million annually prospectively starting Feb. 1, 2016, subject to a true-up. In January 2016, SPP filed a proposal regarding distribution of the MISO revenues to SPP members. In March 2016, the FERC issued an order rejecting one component of the SPP filing, accepting the remainder of the SPP tariff proposal subject to refund, and setting the filing for settlement judge or hearing procedures. Separate settlement discussions are ongoing regarding the April 2014 MISO tariff change filing to recover SPP JOA charges in MISO rates. NSP-Minnesota and NSP-Wisconsin expect to be able to recover any resulting MISO charges in retail rates.

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 March 31, 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.

30

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 believe the implementation of the general ledger modules, which occurred during the period ended March 31, 2016, materially affected its internal control over financial reporting. NSP-Minnesota also does not expect the implementation of the additional modules to materially affect its internal control over financial reporting.

No other 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.

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.

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Item 6 — EXHIBITS

* Indicates incorporation by reference

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)).
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 March 31, 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.

32

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)
May 13, 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)

33

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: May 13, 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: May 13, 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 March 31, 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: May 13, 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.

1

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 13, 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	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating revenues
Electric, non-affiliates	$ 908,747	$ 881,279
Electric, affiliates	124,896	124,875
Natural gas	194,130	279,467
Other	6,860	6,861
Total operating revenues	1,234,633	1,292,482
Operating expenses
Electric fuel and purchased power	366,166	398,720
Cost of natural gas sold and transported	120,223	201,189
Cost of sales — other	4,432	4,327
Operating and maintenance expenses	320,496	314,050
Conservation program expenses	23,269	17,212
Depreciation and amortization	145,797	118,075
Taxes (other than income taxes)	70,352	63,832
Loss on Monticello life cycle management/extended power uprate project	0	124,226
Total operating expenses	1,050,735	1,241,631
Operating income	183,898	50,851
Other income, net	2,860	1,962
Allowance for funds used during construction — equity	5,648	5,930
Interest charges and financing costs
Interest charges — includes other financing costs of $1,742 and $1,610, respectively	54,015	51,763
Allowance for funds used during construction — debt	(2,706)	(2,914)
Total interest charges and financing costs	51,309	48,849
Income before income taxes	141,097	9,894
Income taxes	46,468	2,970
Net income	$ 94,629	$ 6,924	[1]

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

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Interest charges and financing costs
Other financing costs	$ 1,742	$ 1,610

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Comprehensive income:
Net income	$ 94,629	$ 6,924	[1]
Pension and retiree medical benefits:
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $15 and ($4), respectively	19	(6)
Derivative instruments:
Net fair value decrease, net of tax of $(1) and $(4), respectively	(1)	(6)
Reclassification of losses to net income, net of tax of $154 and $143, respectively	223	208
Total derivative instruments, net of tax	222	202
Marketable securities:
Net fair value increase, net of tax of $0 and $0, respectively	0	1
Other comprehensive income	241	197
Comprehensive income	$ 94,870	$ 7,121

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

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, tax	$ 15	$ (4)
Derivative instruments:
Net fair value (decrease) increase, tax	(1)	(4)
Reclassification of losses to net income, tax	154	143
Marketable securities:
Net fair value (decrease) increase, tax	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating activities
Net income	$ 94,629	$ 6,924	[1]
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	147,310	119,459
Nuclear fuel amortization	25,750	28,465
Deferred income taxes	47,018	9,565
Amortization of Investment Tax Credits	(420)	(433)
Allowance for equity funds used during construction	(5,648)	(5,930)
Loss on Monticello life cycle management/extended power uprate project	0	124,226
Net realized and unrealized hedging and derivative transactions	1,890	6,385
Changes in operating assets and liabilities:
Accounts receivable	(45,382)	10,584
Accrued unbilled revenues	40,322	57,484
Inventories	35,378	27,059
Other current assets	(14,146)	14,042
Accounts payable	(4,057)	(8,405)
Net regulatory assets and liabilities	51,517	37,558
Other current liabilities	(12,118)	42,288
Pension and other employee benefit obligations	(48,074)	(32,330)
Change in other noncurrent assets	(43)	(115)
Change in other noncurrent liabilities	(1,112)	(21,480)
Net cash provided by operating activities	312,814	415,346
Investing activities
Utility capital/construction expenditures	(259,570)	(322,660)
Allowance for equity funds used during construction	5,648	5,930
Proceeds from insurance recoveries	0	24,241
Purchases of investments in external decommissioning fund	(109,373)	(387,826)
Proceeds from the sale of investments in external decommissioning fund	104,280	386,111
Investments in utility money pool arrangement	0	(15,000)
Repayments from utility money pool arrangement	0	15,000
Other, net	(2,084)	(2,244)
Net cash used in investing activities	(261,099)	(296,448)
Financing activities
Repayments of short-term borrowings, net	(150,000)	(66,000)
Borrowings under utility money pool arrangement	310,000	31,000
Repayments under utility money pool arrangement	(217,000)	(31,000)
Repayments of Long-term Debt	0	(33)
Capital contributions from parent	89,874	75,835
Dividends paid to parent	(73,498)	(77,802)
Net cash used in financing activities	(40,624)	(68,000)
Net change in cash and cash equivalents	11,091	50,898
Cash and cash equivalents at beginning of period	42,605	40,597
Cash and cash equivalents at end of period	53,696	91,495
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(69,643)	(64,798)
Cash (paid) received for income taxes, net	(7,558)	23,769
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 56,605	$ 108,900

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

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 53,696	$ 42,605
Accounts receivable, net	332,976	292,806
Accounts receivable from affiliates	23,188	32,850
Accrued unbilled revenues	186,780	227,102
Inventories	308,578	343,916
Regulatory assets	178,943	187,793
Derivative instruments	12,638	18,941
Deferred income taxes	34,561	15,577
Prepayments and other	102,220	89,559
Total current assets	1,233,580	1,251,149
Property, plant and equipment, net	12,828,607	12,807,338
Other assets
Nuclear decommissioning fund and other investments	1,769,992	1,758,208
Regulatory assets	1,199,305	1,159,217
Derivative instruments	28,038	22,334
Other	1,428	1,385
Total other assets	2,998,763	2,941,144
Total assets	17,060,950	16,999,631
Current liabilities
Current portion of long-term debt	11	11
Short-term debt	73,000	223,000
Borrowings under utility money pool arrangement	93,000	0
Accounts payable	298,918	350,660
Accounts payable to affiliates	54,889	59,785
Regulatory liabilities	50,435	43,920
Taxes accrued	282,379	225,361
Accrued interest	47,122	66,979
Dividends payable to parent	82,228	73,498
Derivative instruments	18,239	17,211
Customer Deposits, Current	78,477	94,388
Other	142,440	177,795
Total current liabilities	1,221,138	1,332,608
Deferred credits and other liabilities
Deferred income taxes	2,637,057	2,572,087
Deferred investment tax credits	25,418	25,838
Regulatory liabilities	506,044	491,887
Asset retirement obligations	2,359,476	2,331,092
Derivative instruments	129,383	128,213
Pension and employee benefit obligations	290,885	339,663
Other	139,409	114,768
Total deferred credits and other liabilities	$ 6,087,672	$ 6,003,548
Commitments and contingencies
Capitalization
Long-term debt	$ 4,497,432	$ 4,496,410
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at March 31, 2016 and Dec. 31, 2015, respectively	10	10
Additional paid in capital	3,398,810	3,323,810
Retained earnings	1,876,728	1,864,326
Accumulated other comprehensive loss	(20,840)	(21,081)
Total common stockholder’s equity	5,254,708	5,167,065
Total liabilities and equity	$ 17,060,950	$ 16,999,631

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
Capitalization, Long-term Debt and Equity [Abstract]
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

3 Months Ended

Mar. 31, 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 March 31, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2016 and 2015; and its cash flows for the three months endedMarch 31, 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 March 31, 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

3 Months Ended

Mar. 31, 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

3 Months Ended

Mar. 31, 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 is currently evaluating the impact of adopting ASU 2016-09 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 are 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

3 Months Ended

Mar. 31, 2016

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	352,249		$	313,556
Less allowance for bad debts	(19,273		)	(20,750		)
	$	332,976		$	292,806

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	208,090	$	200,888
Fuel	88,287		104,499
Natural gas	12,201		38,529
	$	308,578	$	343,916

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	16,298,761		$	16,256,887
Natural gas plant	1,249,933			1,248,408
Common and other property	622,749			624,409
Construction work in progress	650,693			545,535
Total property, plant and equipment	18,822,136			18,675,239
Less accumulated depreciation	(6,354,488		)	(6,251,498		)
Nuclear fuel	2,450,363			2,447,251
Less accumulated amortization	(2,089,404		)	(2,063,654		)
	$	12,828,607		$	12,807,338

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Income Taxes

3 Months Ended

Mar. 31, 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 the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 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); 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 March 31, 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 March 31, 2016, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

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

(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	20.5	$	20.1
Unrecognized tax benefit — Temporary tax positions	37.0		35.3
Total unrecognized tax benefit	$	57.5	$	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)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(16.3	)	$	(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 and state audits resume. As the IRS Appeals and audit 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 March 31, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2016 or Dec. 31, 2015.

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Rate Matters

3 Months Ended

Mar. 31, 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, 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)

NSP-Minnesota – 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

NSP-Minnesota also proposed a five-year alternative plan that would extend the rate plan two additional years. In addition, NSP-Minnesota has requested the MPUC encourage parties to engage in a formal mediation type procedure as outlined by Minnesota’s rate case statute which may streamline the settlement process.

In December 2015, the MPUC approved interim rates for 2016. The MPUC deferred making a decision on incremental interim rates for 2017 and indicated that NSP-Minnesota could bring back its request in the fourth quarter of 2016.

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

(Millions of Dollars)	2016			2017			2018			Total
2014 multi-year rate case items:
Excess depreciation reserve	$	26.0		$	51.0		$	—		$	77.0
Department of Energy (DOE) settlement	25.7			—			—			25.7
Monticello life cycle management (LCM)/extended power uprate (EPU)	11.2			(1.6		)	(1.5		)	8.1
	62.9			49.4			(1.5		)	110.8
Additional items:
Capital investments	128.7			12.8			44.6			186.1
Property taxes	30.2			7.6			5.2			43.0
NOL carryforwards	(6.3		)	(24.5		)	(6.5		)	(37.3		)
Other costs	(20.9		)	6.8			8.6			(5.5		)
	131.7			2.7			51.9			186.3
Total rate request	$	194.6		$	52.1		$	50.4		$	297.1

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

• Intervenors’ direct testimony — June 14, 2016;

• Rebuttal testimony — Aug. 9, 2016;

• Surrebuttal testimony — Sept. 16, 2016;

• Settlement conference — Sept. 26, 2016;

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

• Administrative law judge (ALJ) report — Feb. 21, 2017; and

• MPUC order — June 1, 2017.

2016 Transmission Cost Recovery (TCR) Filing — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. This filing included an option to keep approximately $59.1 million of revenue requirements associated with two

CapX2020 projects completed in 2015 within the TCR rider or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. In November 2015, NSP-Minnesota submitted an update to its TCR filing in which it confirmed that it was requesting the MPUC approve keeping the two CapX2020 projects in the TCR rider, increasing the revenue requirements to $78.3 million, until the conclusion of the 2016 Minnesota electric rate case.

In April 2016, NSP-Minnesota received comments from the Minnesota Department of Commerce (DOC) requesting additional support for the costs incurred for the CapX2020 La Crosse-Madison project and the CapX2020 Big Stone-Brookings project, as well as the updated financial impact for the actual non-prorated accumulated deferred income tax (ADIT) as opposed to the forecasted prorated ADIT used in the cost recovery calculations. An MPUC decision is expected later in 2016.

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/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 June 2014 the FERC adopted a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

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 no earlier than late 2016 or 2017.

Certain MISO TOs separately requested FERC approval of a 50 basis point ROE adder for RTO membership, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. Certain intervenors sought rehearing of this order, which the FERC denied in 2015.

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 Minnesota Department of Commerce (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. An ALJ initial decision is expected in June 2016 with a FERC decision expected no earlier than late 2016 or 2017.

NSP-Minnesota has recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of March 31, 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

3 Months Ended

Mar. 31, 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 March 31, 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)	March 31, 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 July 2016 to allow NSP-Minnesota time to further investigate site conditions.

As of March 31, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $2.2 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 PRPs. 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

Air

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the United States Environmental Protection Agency (EPA) amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Minnesota identified the NSP-Minnesota facilities that will have to reduce sulfur dioxide (SO₂), nitrous oxide (NOx) and particulate matter (PM) emissions under BART and set emissions limits for those facilities.

In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO₂. The MPCA supplemented its SIP in 2012, determining that the Cross-State Air Pollution Rule (CSAPR) meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, the EPA approved the SIP for electric generating units and also approved the source-specific emission limits for Sherco Units 1 and 2. The combustion controls were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million. NSP-Minnesota has included these costs for recovery in rate proceedings.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit). In January 2016, the Eighth Circuit issued their opinion which upheld the EPA’s approval of the SIP. In March 2016, after granting a rehearing request, the Eighth Circuit issued a revised opinion that included additional explanation and continued to uphold the EPA’s approval of the SIP.

Reasonably Attributable Visibility Impairment (RAVI) —RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the United States Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.

In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota (Minnesota District Court) by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club.

In May 2015, NSP-Minnesota, the EPA and the six environmental advocacy organizations filed a settlement agreement in the Minnesota District Court.  The agreement anticipates a federal rulemaking that would impose stricter SO₂ emission limits on Sherco Units 1, 2 and 3, without making a RAVI attribution finding or a RAVI BART determination.  The emission limits for Units 1 and 2 reflect the success of a recently completed control project. The Unit 3 emission limits will be met through changes in the operation of the existing scrubber.  The Minnesota District Court issued an order staying the litigation for the time needed to complete the actions required by the settlement agreement.  The plaintiffs agreed to withdraw their complaint with prejudice when those actions are completed.  Plaintiffs also agreed not to request a RAVI certification for Sherco Units 1, 2 and/or 3 in the future.

In March 2016, the EPA adopted a final rule which set the agreed-upon SO₂ emission limits.  As a result, the Minnesota District Court dismissed the litigation with prejudice in March 2016. NSP-Minnesota does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

Implementation of the National Ambient Air Quality Standard (NAAQS) for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where NSP-Minnesota operates power plants.  However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the Clean Air Act and under a consent decree 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 system costs 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

3 Months Ended

Mar. 31, 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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	250		$	250
Amount outstanding at period end	93			—
Average amount outstanding	39			5
Maximum amount outstanding	225			69
Weighted average interest rate, computed on a daily basis	0.71		%	0.53		%
Weighted average interest rate at period end	0.71			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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	500		$	500
Amount outstanding at period end	73			223
Average amount outstanding	224			96
Maximum amount outstanding	353			327
Weighted average interest rate, computed on a daily basis	0.66		%	0.43		%
Weighted average interest rate at period end	0.55			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 March 31, 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 to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2016, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	91	$	409

^(a)  This credit facility expires in October 2019.

^(b)  Includes outstanding commercial paper and 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 March 31, 2016 and Dec. 31, 2015.

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Fair Value of Financial Assets and Liabilities

3 Months Ended

Mar. 31, 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 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, generally referred to as financial transmission rights (FTRs), purchased from MISO, PJM Interconnection, LLC, Electric Reliability Council of Texas, Southwest Power Pool, Inc. and New York Independent System Operator. FTRs purchased from an 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 overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid 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 – including expected plant operating schedules and retail and wholesale demand, 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

The Nuclear Regulatory Commission (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 Prairie Island (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. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, 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. 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 $322.7 million and $328.8 million at March 31, 2016 and Dec. 31, 2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $100.3 million and $100.2 million at March 31, 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 March 31, 2016 and Dec. 31, 2015:

	March 31, 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	$	11,899	$	11,899	$	—	$	—	$	—	$	11,899
Commingled funds	390,345		—		—		—		395,709		395,709
International equity funds	264,340		—		—		—		242,312		242,312
Private equity investments	108,882		—		—		—		158,915		158,915
Real estate	73,577		—		—		—		100,576		100,576
Debt securities:
Government securities	24,320		—		23,213		—		—		23,213
U.S. corporate bonds	76,952		—		70,723		—		—		70,723
International corporate bonds	18,117		—		17,343		—		—		17,343
Municipal bonds	47,088		—		49,902		—		—		49,902
Asset-backed securities	2,841		—		2,836		—		—		2,836
Mortgage-backed securities	11,065		—		11,407		—		—		11,407
Equity securities:
Common stock	481,968		649,015		—		—		—		649,015
Total	$	1,511,394	$	660,914	$	175,424	$	—	$	897,512	$	1,733,850

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $36.1 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.

	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 three months ended March 31, 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 March 31, 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	$	—	$	—	$	3,144	$	20,069		$	23,213
U.S. corporate bonds	—		18,909		56,102		(4,288		)	70,723
International corporate bonds	—		2,795		11,505		3,043			17,343
Municipal bonds	151		266		16,323		33,162			49,902
Asset-backed securities	—		—		2,836		—			2,836
Mortgage-backed securities	—		—		—		11,407			11,407
Debt securities	$	151	$	21,970	$	89,910	$	63,393		$	175,424

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 March 31, 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, which is made up of management personnel not directly involved in the activities governed by this policy.

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 March 31, 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 months ended March 31, 2016 and 2015.

At March 31, 2016, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of 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 March 31, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	23,336	43,611
Million British thermal units of natural gas	9,523	7,971
Gallons of vehicle fuel	58	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 months ended March 31, 2016 and 2015 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended March 31, 2016
	Pre-Tax Fair Value 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	$	—		$	—		$	346	(a)	$	—		$	—
Vehicle fuel and other commodity	(2		)	—			31		(b)	—			—
Total	$	(2	)	$	—		$	377		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	992		(c)
Electric commodity	—			(1,558		)	—			10,712		(d)	—
Natural gas commodity	—			(631		)	—			3,460		(e)	(1,595		)	(e)
Total	$	—		$	(2,189	)	$	—		$	14,172		$	(603	)

	Three Months Ended March 31, 2015
	Pre-Tax Fair Value 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	$	—		$	—		$	337	(a)	$	—			$	—
Vehicle fuel and other commodity	(10		)	—			14		(b)	—				—
Total	$	(10	)	$	—		$	351		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—			$	3,691	(c)
Electric commodity	—			(8,706		)	—			(5,193		)	(d)	—
Natural gas commodity	—			(38		)	—			(2,751		)	(e)	3,008		(e)
Total	$	—		$	(8,744	)	$	—		$	(7,944	)		$	6,699

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to operating and maintenance (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 months ended March 31, 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 continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-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 when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At March 31, 2016, seven of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $23.9 million or 34 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. One of the 10 most significant counterparties, comprising $0.8 million or 1 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 of these significant counterparties, comprising $8.9 million or 13 percent of this credit exposure, had credit quality less than investment grade, based on NSP-Minnesota's internal analysis. Eight of these significant counterparties are RTOs, 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 March 31, 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 March 31, 2016 and Dec. 31, 2015.

Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2016:

	March 31, 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	$	162	$	14,775	$	453	$	15,390	$	(7,936	)	$	7,454
Electric commodity	—		—		4,761		4,761		(55		)	4,706
Total current derivative assets	$	162	$	14,775	$	5,214	$	20,151	$	(7,991	)	12,160
PPAs (a)												478
Current derivative instruments												$	12,638
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	250	$	35,198	$	—	$	35,448	$	(8,893	)	$	26,555
Total noncurrent derivative assets	$	250	$	35,198	$	—	$	35,448	$	(8,893	)	26,555
PPAs (a)												1,483
Noncurrent derivative instruments												$	28,038

	March 31, 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	$	—	$	84	$	—	$	84	$	—		$	84
Other derivative instruments:
Commodity trading	176		12,496		35		12,707		(8,665		)	4,042
Electric commodity	—		—		55		55		(55		)	—
Total current derivative liabilities	$	176	$	12,580	$	90	$	12,846	$	(8,720	)	4,126
PPAs (a)												14,113
Current derivative instruments												$	18,239
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	215	$	27,000	$	—	$	27,215	$	(12,497	)	$	14,718
Total noncurrent derivative liabilities	$	215	$	27,000	$	—	$	27,215	$	(12,497	)	14,718
PPAs (a)												114,665
Noncurrent derivative instruments												$	129,383

^(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 March 31, 2016. At March 31, 2016, 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 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 months ended March 31, 2016 and 2015:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	12,970		$	40,271
Purchases	—			864
Settlements	(5,038		)	(11,552		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(24		)	60
Losses recognized as regulatory assets and liabilities	(2,784		)	(18,671		)
Balance at March 31	$	5,124		$	10,972

^(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 months ended March 31, 2016 and 2015.

Fair Value of Long-Term Debt

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

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,497,443	$	5,149,155	$	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 March 31, 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 Income, Net

3 Months Ended

Mar. 31, 2016

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	3,336		$	3,332
Other nonoperating income	164			33
Insurance policy expense	(640		)	(1,403		)
Other income, net	$	2,860		$	1,962

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Segment Information

3 Months Ended

Mar. 31, 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 March 31, 2016
Operating revenues (a)(b)	$	1,033,643	$	194,130	$	6,860	$	—		$	1,234,633
Intersegment revenues	145		162		—		(307		)	—
Total revenues	$	1,033,788	$	194,292	$	6,860	$	(307	)	$	1,234,633
Net income	$	71,321	$	23,142	$	166	$	—		$	94,629

(Thousands of Dollars)	Regulated Electric				Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2015
Operating revenues (a)(b)	$	1,006,154			$	279,467	$	6,861		$	—		$	1,292,482
Intersegment revenues	133				410		—			(543		)	—
Total revenues	$	1,006,287			$	279,877	$	6,861		$	(543	)	$	1,292,482
Net income (loss)	$	(29,599	)	(c)	$	40,272	$	(3,749	)	$	—		$	6,924

^(a)  Operating revenues include $125 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 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

3 Months Ended

Mar. 31, 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 March 31
	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			10,804			981			954
Expected return on plan assets	(15,236		)	(15,708		)	(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			728
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		$	728

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

3 Months Ended

Mar. 31, 2016

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive income (loss), net of tax, for the three months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 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 loss before reclassifications	(1		)	—		—			(1		)
Losses reclassified from net accumulated other comprehensive loss	223			—		19			242
Net current period other comprehensive income	222			—		19			241
Accumulated other comprehensive (loss) income at March 31	$	(18,868	)	$	105	$	(2,077	)	$	(20,840	)

	Three Months Ended March 31, 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 (loss) income before reclassifications	(6		)	1		—			(5		)
Losses (gains) reclassified from net accumulated other comprehensive loss	208			—		(6		)	202
Net current period other comprehensive income (loss)	202			1		(6		)	197
Accumulated other comprehensive (loss) income at March 31	$	(19,707	)	$	106	$	(1,016	)	$	(20,617	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		(a)	$	337		(a)
Vehicle fuel derivatives	31			(b)	14			(b)
Total, pre-tax	377				351
Tax benefit	(154		)		(143		)
Total, net of tax	223				208
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	83			(c)	39			(c)
Prior service credit	(49		)	(c)	(49		)	(c)
Total, pre-tax	34				(10		)
Tax (benefit) expense	(15		)		4
Total, net of tax	19				(6		)
Total amounts reclassified, net of tax	$	242			$	202

^(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)

3 Months Ended

Mar. 31, 2016

Balance Sheet Related Disclosures [Abstract]

Accounts receivable, net

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	352,249		$	313,556
Less allowance for bad debts	(19,273		)	(20,750		)
	$	332,976		$	292,806

Inventories

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	208,090	$	200,888
Fuel	88,287		104,499
Natural gas	12,201		38,529
	$	308,578	$	343,916

Property, plant and equipment, net

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	16,298,761		$	16,256,887
Natural gas plant	1,249,933			1,248,408
Common and other property	622,749			624,409
Construction work in progress	650,693			545,535
Total property, plant and equipment	18,822,136			18,675,239
Less accumulated depreciation	(6,354,488		)	(6,251,498		)
Nuclear fuel	2,450,363			2,447,251
Less accumulated amortization	(2,089,404		)	(2,063,654		)
	$	12,828,607		$	12,807,338

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 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)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	20.5	$	20.1
Unrecognized tax benefit — Temporary tax positions	37.0		35.3
Total unrecognized tax benefit	$	57.5	$	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)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(16.3	)	$	(15.2	)

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Rate Matters (Tables)

3 Months Ended

Mar. 31, 2016

Public Utilities, General Disclosures [Abstract]

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

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

(Millions of Dollars)	2016			2017			2018			Total
2014 multi-year rate case items:
Excess depreciation reserve	$	26.0		$	51.0		$	—		$	77.0
Department of Energy (DOE) settlement	25.7			—			—			25.7
Monticello life cycle management (LCM)/extended power uprate (EPU)	11.2			(1.6		)	(1.5		)	8.1
	62.9			49.4			(1.5		)	110.8
Additional items:
Capital investments	128.7			12.8			44.6			186.1
Property taxes	30.2			7.6			5.2			43.0
NOL carryforwards	(6.3		)	(24.5		)	(6.5		)	(37.3		)
Other costs	(20.9		)	6.8			8.6			(5.5		)
	131.7			2.7			51.9			186.3
Total rate request	$	194.6		$	52.1		$	50.4		$	297.1

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)

3 Months Ended

Mar. 31, 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)	March 31, 2016		Dec. 31, 2015
Guarantee issued and outstanding	$	4.8	$	4.8

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Borrowings and Other Financing Instruments (Tables)

3 Months Ended

Mar. 31, 2016

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At March 31, 2016, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	91	$	409

^(a)  This credit facility expires in October 2019.

^(b)  Includes outstanding commercial paper and 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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	250		$	250
Amount outstanding at period end	93			—
Average amount outstanding	39			5
Maximum amount outstanding	225			69
Weighted average interest rate, computed on a daily basis	0.71		%	0.53		%
Weighted average interest rate at period end	0.71			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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	500		$	500
Amount outstanding at period end	73			223
Average amount outstanding	224			96
Maximum amount outstanding	353			327
Weighted average interest rate, computed on a daily basis	0.66		%	0.43		%
Weighted average interest rate at period end	0.55			0.72

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Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2016 and Dec. 31, 2015:

	March 31, 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	$	11,899	$	11,899	$	—	$	—	$	—	$	11,899
Commingled funds	390,345		—		—		—		395,709		395,709
International equity funds	264,340		—		—		—		242,312		242,312
Private equity investments	108,882		—		—		—		158,915		158,915
Real estate	73,577		—		—		—		100,576		100,576
Debt securities:
Government securities	24,320		—		23,213		—		—		23,213
U.S. corporate bonds	76,952		—		70,723		—		—		70,723
International corporate bonds	18,117		—		17,343		—		—		17,343
Municipal bonds	47,088		—		49,902		—		—		49,902
Asset-backed securities	2,841		—		2,836		—		—		2,836
Mortgage-backed securities	11,065		—		11,407		—		—		11,407
Equity securities:
Common stock	481,968		649,015		—		—		—		649,015
Total	$	1,511,394	$	660,914	$	175,424	$	—	$	897,512	$	1,733,850

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $36.1 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.

	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 March 31, 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	$	—	$	—	$	3,144	$	20,069		$	23,213
U.S. corporate bonds	—		18,909		56,102		(4,288		)	70,723
International corporate bonds	—		2,795		11,505		3,043			17,343
Municipal bonds	151		266		16,323		33,162			49,902
Asset-backed securities	—		—		2,836		—			2,836
Mortgage-backed securities	—		—		—		11,407			11,407
Debt securities	$	151	$	21,970	$	89,910	$	63,393		$	175,424

Gross Notional Amounts of Commodity Forwards, Options, and FTRs

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

(Amounts in Thousands)(a)(b)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	23,336	43,611
Million British thermal units of natural gas	9,523	7,971
Gallons of vehicle fuel	58	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 months ended March 31, 2016 and 2015 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended March 31, 2016
	Pre-Tax Fair Value 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	$	—		$	—		$	346	(a)	$	—		$	—
Vehicle fuel and other commodity	(2		)	—			31		(b)	—			—
Total	$	(2	)	$	—		$	377		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	992		(c)
Electric commodity	—			(1,558		)	—			10,712		(d)	—
Natural gas commodity	—			(631		)	—			3,460		(e)	(1,595		)	(e)
Total	$	—		$	(2,189	)	$	—		$	14,172		$	(603	)

	Three Months Ended March 31, 2015
	Pre-Tax Fair Value 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	$	—		$	—		$	337	(a)	$	—			$	—
Vehicle fuel and other commodity	(10		)	—			14		(b)	—				—
Total	$	(10	)	$	—		$	351		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—			$	3,691	(c)
Electric commodity	—			(8,706		)	—			(5,193		)	(d)	—
Natural gas commodity	—			(38		)	—			(2,751		)	(e)	3,008		(e)
Total	$	—		$	(8,744	)	$	—		$	(7,944	)		$	6,699

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to operating and maintenance (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 tables present for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2016:

	March 31, 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	$	162	$	14,775	$	453	$	15,390	$	(7,936	)	$	7,454
Electric commodity	—		—		4,761		4,761		(55		)	4,706
Total current derivative assets	$	162	$	14,775	$	5,214	$	20,151	$	(7,991	)	12,160
PPAs (a)												478
Current derivative instruments												$	12,638
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	250	$	35,198	$	—	$	35,448	$	(8,893	)	$	26,555
Total noncurrent derivative assets	$	250	$	35,198	$	—	$	35,448	$	(8,893	)	26,555
PPAs (a)												1,483
Noncurrent derivative instruments												$	28,038

	March 31, 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	$	—	$	84	$	—	$	84	$	—		$	84
Other derivative instruments:
Commodity trading	176		12,496		35		12,707		(8,665		)	4,042
Electric commodity	—		—		55		55		(55		)	—
Total current derivative liabilities	$	176	$	12,580	$	90	$	12,846	$	(8,720	)	4,126
PPAs (a)												14,113
Current derivative instruments												$	18,239
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	215	$	27,000	$	—	$	27,215	$	(12,497	)	$	14,718
Total noncurrent derivative liabilities	$	215	$	27,000	$	—	$	27,215	$	(12,497	)	14,718
PPAs (a)												114,665
Noncurrent derivative instruments												$	129,383

^(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 March 31, 2016. At March 31, 2016, 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 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 months ended March 31, 2016 and 2015:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	12,970		$	40,271
Purchases	—			864
Settlements	(5,038		)	(11,552		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(24		)	60
Losses recognized as regulatory assets and liabilities	(2,784		)	(18,671		)
Balance at March 31	$	5,124		$	10,972

^(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 March 31, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,497,443	$	5,149,155	$	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.

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Other Income, Net (Tables)

3 Months Ended

Mar. 31, 2016

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	3,336		$	3,332
Other nonoperating income	164			33
Insurance policy expense	(640		)	(1,403		)
Other income, net	$	2,860		$	1,962

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Segment Information (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2016
Operating revenues (a)(b)	$	1,033,643	$	194,130	$	6,860	$	—		$	1,234,633
Intersegment revenues	145		162		—		(307		)	—
Total revenues	$	1,033,788	$	194,292	$	6,860	$	(307	)	$	1,234,633
Net income	$	71,321	$	23,142	$	166	$	—		$	94,629

(Thousands of Dollars)	Regulated Electric				Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2015
Operating revenues (a)(b)	$	1,006,154			$	279,467	$	6,861		$	—		$	1,292,482
Intersegment revenues	133				410		—			(543		)	—
Total revenues	$	1,006,287			$	279,877	$	6,861		$	(543	)	$	1,292,482
Net income (loss)	$	(29,599	)	(c)	$	40,272	$	(3,749	)	$	—		$	6,924

^(a)  Operating revenues include $125 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 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)

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	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			10,804			981			954
Expected return on plan assets	(15,236		)	(15,708		)	(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			728
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		$	728

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2016

Stockholders' Equity Note [Abstract]

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

Changes in accumulated other comprehensive income (loss), net of tax, for the three months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 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 loss before reclassifications	(1		)	—		—			(1		)
Losses reclassified from net accumulated other comprehensive loss	223			—		19			242
Net current period other comprehensive income	222			—		19			241
Accumulated other comprehensive (loss) income at March 31	$	(18,868	)	$	105	$	(2,077	)	$	(20,840	)

	Three Months Ended March 31, 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 (loss) income before reclassifications	(6		)	1		—			(5		)
Losses (gains) reclassified from net accumulated other comprehensive loss	208			—		(6		)	202
Net current period other comprehensive income (loss)	202			1		(6		)	197
Accumulated other comprehensive (loss) income at March 31	$	(19,707	)	$	106	$	(1,016	)	$	(20,617	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		(a)	$	337		(a)
Vehicle fuel derivatives	31			(b)	14			(b)
Total, pre-tax	377				351
Tax benefit	(154		)		(143		)
Total, net of tax	223				208
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	83			(c)	39			(c)
Prior service credit	(49		)	(c)	(49		)	(c)
Total, pre-tax	34				(10		)
Tax (benefit) expense	(15		)		4
Total, net of tax	19				(6		)
Total amounts reclassified, net of tax	$	242			$	202

^(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	Mar. 31, 2016	Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$ 352,249	$ 313,556
Less allowance for bad debts	(19,273)	(20,750)
Accounts receivable, net	$ 332,976	$ 292,806

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Selected Balance Sheet Data, Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 308,578	$ 343,916
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	208,090	200,888
Fuel
Public Utilities, Inventory [Line Items]
Inventories	88,287	104,499
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 12,201	$ 38,529

XML

Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 18,822,136	$ 18,675,239
Less accumulated depreciation	(6,354,488)	(6,251,498)
Property, plant and equipment, net	12,828,607	12,807,338
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,298,761	16,256,887
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,249,933	1,248,408
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	622,749	624,409
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	650,693	545,535
Nuclear fuel
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,450,363	2,447,251
Less accumulated depreciation	$ (2,089,404)	$ (2,063,654)

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Income Taxes (Details) - USD ($)	3 Months Ended	9 Months Ended		12 Months Ended
	Mar. 31, 2016	Sep. 30, 2015	Sep. 30, 2012	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	$ 20,500,000			20,100,000
Unrecognized tax benefit — Temporary tax positions	37,000,000			35,300,000
Total unrecognized tax benefit	57,500,000			55,400,000
NOL and tax credit carryforwards	(16,300,000)			(15,200,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	32,000,000
Amounts accrued for penalties related to unrecognized tax benefits	0			$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination		2012 and 2013	2010 and 2011
Year of carryback claim under examination			2009
Potential Tax Adjustments	$ 14,000,000
State Jurisdiction (Minnesota)
Tax Audits [Abstract]
Earliest year subject to examination	2009

XML

Rate Matters (Details) $ in Thousands		1 Months Ended							3 Months Ended		12 Months Ended
	Jan. 06, 2015	Dec. 31, 2015	Nov. 30, 2015 USD ($) project	Oct. 31, 2015 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015	Jun. 30, 2014	Nov. 30, 2013	Mar. 31, 2016 USD ($)	Mar. 31, 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	$ 124,226
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case [Member]
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
Public Utilities, Number Of Years Rate Case is Applicable For, Alternative Plan			5 years
Public Utilities, Number Of Additional Years Under Alternative Rate Plan			2 years
Public Utilities, Increase Related to Excess Depreciation Reserve			$ 77,000
Public Utilities, Increase Related to Settlement			25,700
Public Utilities, Increase Related to Nuclear Projects			8,100
Public Utilities, Total Increase Related to 2014 Multi-Year Rate Case Items			110,800
Public utilities, Requested Increase Related to Capital Investment			186,100
Public Utilities, Increase Related To Property Taxes			43,000
Public Utilities, Decrease Related To Net Operating Loss Carryforwards			(37,300)
Public Utilities, Decrease related to other, net			(5,500)
Public Utilities, Total Increase Related To Additional Items			$ 186,300
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Percentage			6.40%
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 194,600
Public Utilities, Requested Rate Base, Amount			7,800,000
Public Utilities, Increase Related to Excess Depreciation Reserve			26,000
Public Utilities, Increase Related to Settlement			25,700
Public Utilities, Increase Related to Nuclear Projects			11,200
Public Utilities, Total Increase Related to 2014 Multi-Year Rate Case Items			62,900
Public utilities, Requested Increase Related to Capital Investment			128,700
Public Utilities, Increase Related To Property Taxes			30,200
Public Utilities, Decrease Related To Net Operating Loss Carryforwards			(6,300)
Public Utilities, Decrease related to other, net			(20,900)
Public Utilities, Total Increase Related To Additional Items			$ 131,700
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Percentage			1.70%
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 52,100
Public Utilities, Requested Rate Base, Amount			7,700,000
Public Utilities, Increase Related to Excess Depreciation Reserve			51,000
Public Utilities, Increase Related to Settlement			0
Public Utilities, Decrease Related to Nuclear Projects			(1,600)
Public Utilities, Total Increase Related to 2014 Multi-Year Rate Case Items			49,400
Public utilities, Requested Increase Related to Capital Investment			12,800
Public Utilities, Increase Related To Property Taxes			7,600
Public Utilities, Decrease Related To Net Operating Loss Carryforwards			(24,500)
Public Utilities, Increase Related To Other, Net			6,800
Public Utilities, Total Increase Related To Additional Items			$ 2,700
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Percentage			1.70%
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 50,400
Public Utilities, Requested Rate Base, Amount			7,700,000
Public Utilities, Increase Related to Excess Depreciation Reserve			0
Public Utilities, Increase Related to Settlement			0
Public Utilities, Decrease Related to Nuclear Projects			(1,500)
Public Utilities, Total Decrease Related to 2014 Multi-Year Rate Case Items			(1,500)
Public utilities, Requested Increase Related to Capital Investment			44,600
Public Utilities, Increase Related To Property Taxes			5,200
Public Utilities, Decrease Related To Net Operating Loss Carryforwards			(6,500)
Public Utilities, Increase Related To Other, Net			8,600
Public Utilities, Total Increase Related To Additional Items			51,900
NSP-Minnesota | MPUC Proceeding - Transmission Cost Recovery Rider Filing 2016 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rider Revenue, Amount				$ 19,200
NSP-Minnesota | MPUC Proceeding - Transmission Cost Recovery Rider Filing 2016 - With Additional Transmission Investment [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rider Revenue, Amount			$ 78,300
Public Utilities, Additional Transmission Investment, Amount				$ 59,100
Public Utilities, Additional Transmission Investment, Number Of Projects			2	2
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 [Member]
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 [Member]
Rate Matters [Abstract]
Public Utilities, Interim Rate Increase (Decrease), Amount			$ 163,700
NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017 [Member]
Rate Matters [Abstract]
Public Utilities, Interim Rate Increase (Decrease), Amount			$ 44,900
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 | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint [Member]
Rate Matters [Abstract]
Public Utilities, Number Of Steps Required For Newly Adopted ROE Discounted Cash Flow Methodology							2
Public Utilities, ROE Basis Point Adder Requested By Third Parties	50
NSP-Minnesota | Administrative Law Judge | FERC Proceeding, MISO ROE Complaint [Member]
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties		10.32%
NSP-Minnesota | FERC Staff [Member] | FERC Proceeding, MISO ROE Complaint [Member]
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 [Member] | FERC Proceeding, MISO ROE Complaint [Member]
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 | MPUC, NDPSC, SDPUC, and DOC [Member] | FERC Proceeding, MISO ROE Complaint [Member]
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Lower Bound, Percentage									8.81%
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Upper Bound, Percentage									8.82%
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 [Member]
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 [Member]
Rate Matters [Abstract]
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology									$ 10,000

XML

Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	3 Months Ended	12 Months Ended
	Mar. 31, 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	3 Months Ended	12 Months Ended
	Mar. 31, 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	3 Months Ended
	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	May. 31, 2015 Parties	Dec. 31, 2014 USD ($)
Regional Haze Rules
Environmental Requirements [Abstract]
Amount spent on installation of emission controls				$ 46.9
Reasonably Attributable Visibility Impairment
Environmental Requirements [Abstract]
Number of environmental advocacy organizations who filed a settlement agreement | Parties			6
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	$ 2.2	$ 2.7

XML

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 73,000,000	$ 223,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000,000	250,000,000
Amount outstanding at period end	93,000,000	0
Average amount outstanding	39,000,000	5,000,000
Maximum amount outstanding	$ 225,000,000	$ 69,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.71%	0.53%
Weighted average interest rate at period end (percentage)	0.71%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 500,000,000	$ 500,000,000
Amount outstanding at period end	73,000,000	223,000,000
Average amount outstanding	224,000,000	96,000,000
Maximum amount outstanding	$ 353,000,000	$ 327,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.66%	0.43%
Weighted average interest rate at period end (percentage)	0.55%	0.72%

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term debt	$ 73,000	$ 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 ($)		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term debt		$ 73,000,000	$ 223,000,000
Credit Facility
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date		Oct. 31, 2019
Credit Facility	[1]	$ 500,000,000
Drawn	[2]	91,000,000
Available		409,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0

[1] This credit facility expires in October 2019.

[2] Includes outstanding commercial paper and letters of credit.

XML

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities (Details)	3 Months Ended
	Mar. 31, 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	3 Months Ended		12 Months Ended
	Mar. 31, 2016		Dec. 31, 2015
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Gross Unrealized Gain	$ 322,700		$ 328,800
Available-for-sale Securities, Gross Unrealized Loss	100,300		100,200
Investments [Abstract]
Miscellaneous investments	36,100		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	11,899		27,484
Available-for-sale Securities [Abstract]
Available-for-sale Securities	1,511,394		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	390,345		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	264,340		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	108,882		105,965
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	73,577		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	24,320		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	76,952		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	18,117		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	47,088		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	2,841		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	11,065		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	481,968		473,615
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	11,899		27,484
Available-for-sale Securities [Abstract]
Available-for-sale Securities	1,733,850	[1]	1,724,150	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	395,709		410,634
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	242,312		231,122
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	158,915		157,528
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	100,576		84,750
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	23,213		21,356
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	70,723		65,276
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | International corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	17,343		12,801
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	49,902		51,589
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Asset-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	2,836		2,830
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Mortgage-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	11,407		11,621
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	649,015		647,159
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	11,899		27,484
Available-for-sale Securities [Abstract]
Available-for-sale Securities	660,914		674,643
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | Level 1 | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	649,015		647,159
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | 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	175,424		165,473
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | 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 Total | 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 Total | 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 Total | 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 Total | Level 2 | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	23,213		21,356
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Level 2 | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	70,723		65,276
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Level 2 | International corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	17,343		12,801
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Level 2 | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	49,902		51,589
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Level 2 | Asset-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	2,836		2,830
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Level 2 | Mortgage-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	11,407		11,621
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | 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 Total | Level 3 | 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 Total | Fair Value, Measurements, Net Asset Value (NAV)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[3]	0	[4]
Available-for-sale Securities [Abstract]
Available-for-sale Securities	897,512	[3]	884,034	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	395,709	[3]	410,634	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	242,312	[3]	231,122	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	158,915	[3]	157,528	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	100,576	[3]	84,750	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0	[3]	0	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0	[3]	0	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | International corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0	[3]	0	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0	[3]	0	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Asset-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0	[3]	0	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Mortgage-backed Securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	0	[3]	0	[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value Total | Fair Value, Measurements, Net Asset Value (NAV) | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	$ 0	[3]	$ 0	[4]

[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $36.1 million of miscellaneous investments.

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

[3] 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.

[4] 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.

XML

Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Thousands	Mar. 31, 2016 USD ($)
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	$ 151
Due in 1 to 5 Years	21,970
Due in 5 to 10 Years	89,910
Due after 10 Years	63,393
Total	175,424
Government 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	3,144
Due after 10 Years	20,069
Total	23,213
U.S. corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	18,909
Due in 5 to 10 Years	56,102
Due after 10 Years	(4,288)
Total	70,723
International corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	2,795
Due in 5 to 10 Years	11,505
Due after 10 Years	3,043
Total	17,343
Municipal bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	151
Due in 1 to 5 Years	266
Due in 5 to 10 Years	16,323
Due after 10 Years	33,162
Total	49,902
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	2,836
Due after 10 Years	0
Total	2,836
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	11,407
Total	$ 11,407

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions		Mar. 31, 2016 USD ($) MMBTU gal MWh Counterparty	Dec. 31, 2015 MMBTU gal MWh
Commodity Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months | $		$ (0.1)
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 | Counterparty		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 | Counterparty		8
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 | Counterparty		2
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 8.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		13.00%
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 | Counterparty		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 0.8
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		1.00%
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 | Counterparty		7
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 23.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		34.00%
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]	23,336	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]	9,523	7,971
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	58	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.

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges		$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions		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		(2,000)	(10,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		377,000	351,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income		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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[1]	346,000	337,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income		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		(2,000)	(10,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[2]	31,000	14,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income		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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(2,189,000)	(8,744,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		14,172,000	(7,944,000)
Pre-tax gains (losses) recognized during the period in income		(603,000)	6,699,000
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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income	[3]	992,000	3,691,000
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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(1,558,000)	(8,706,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[4]	10,712,000	(5,193,000)
Pre-tax gains (losses) recognized during the period in income		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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(631,000)	(38,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[5]	3,460,000	(2,751,000)
Pre-tax gains (losses) recognized during the period in income	[5]	$ (1,595,000)	$ 3,008,000

[1] Amounts are recorded to interest charges.

[2] Amounts are recorded to operating and maintenance (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.

XML

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Mar. 31, 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

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Mar. 31, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		$ 4,300		$ 4,300
Derivative Asset, Collateral, Obligation to Return Cash, Offset		0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		12,638		18,941
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		28,038		22,334
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		18,239		17,211
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		129,383		128,213
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		12,160		18,461
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		7,454		6,065
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		4,706		12,274
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				122
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		26,555		20,844
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		26,555		20,844
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		84		113
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		4,126		3,102
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		4,042		1,633
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
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
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		14,718		10,085
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		14,718		10,085
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		162		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		162		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
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		250		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		250		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		176		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		176		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		215		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		215		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14,775		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		14,775		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				128
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		35,198		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		35,198		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		84		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		12,580		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		12,496		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		27,000		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		27,000		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		5,214		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		453		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		4,761		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
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		90		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		35		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		55		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 Measured on a Recurring Basis | Fair Value Total | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		20,151		24,176
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15,390		11,607
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		4,761		12,441
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				128
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		35,448		27,399
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		35,448		27,399
Fair Value Measured on a Recurring Basis | Fair Value Total | 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		84		113
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		12,846		9,855
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		12,707		8,213
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		55		167
Fair Value Measured on a Recurring Basis | Fair Value Total | 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 | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		27,215		19,865
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		27,215		19,865
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(7,991)	[1]	(5,715)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(7,936)	[1]	(5,542)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(55)	[1]	(167)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[2]			(6)
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(8,893)	[1]	(6,555)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(8,893)	[1]	(6,555)	[2]
Fair Value Measured on a Recurring Basis | Netting | 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	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(8,720)	[1]	(6,753)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(8,665)	[1]	(6,580)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(55)	[1]	(167)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]			(6)
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(12,497)	[1]	(9,780)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(12,497)	[1]	(9,780)	[2]
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		478	[3]	480	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,483	[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		14,113	[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		$ 114,665	[3]	$ 118,128	[4]

[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 March 31, 2016. At March 31, 2016, 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.

[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.

XML

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 12,970,000	$ 40,271,000
Purchases		0	864,000
Settlements		(5,038,000)	(11,552,000)
(Losses) gains recognized in earnings	[1]	(24,000)	60,000
(Losses) recognized as regulatory assets and liabilities		(2,784,000)	(18,671,000)
Balance at end of period		5,124,000	10,972,000
Transfers into Level 3		0	0
Transfers out of Level 3		$ 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		Mar. 31, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion (a)	[1]	$ 4,497,443	$ 4,496,421
Fair Value Total
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion (a)	[1]	$ 5,149,155	$ 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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Other Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Other Income and Expenses [Abstract]
Interest Income	$ 3,336	$ 3,332
Other nonoperating income	164	33
Insurance policy expense	(640)	(1,403)
Other income, net	$ 2,860	$ 1,962

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Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues		$ 1,234,633	$ 1,292,482
Net income (loss)		94,629	6,924	[1]
Affiliate electric revenue		124,896	124,875
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues		1,033,788	1,006,287
Net income (loss)		71,321	(29,599)	[1]
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues		194,292	279,877
Net income (loss)		23,142	40,272
All Other
Segment Reporting Information [Line Items]
Operating revenues		6,860	6,861
Net income (loss)		166	(3,749)
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	[2],[3]	1,234,633	1,292,482
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	[2]	1,033,643	1,006,154
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	[3]	194,130	279,467
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues		6,860	6,861
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues		(307)	(543)
Net income (loss)		0	0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues		145	133
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues		162	410
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues		$ 0	$ 0

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

[2] Operating revenues include $125 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015.

[3] Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 2016 and 2015.

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Jan. 31, 2016 USD ($) Plan	Mar. 31, 2016 USD ($)	Mar. 31, 2015 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 7,077	$ 7,889
Interest cost		11,358	10,804
Expected return on plan assets		(15,236)	(15,708)
Amortization of prior service cost (credit)		234	234
Amortization of net loss		9,194	11,548
Net periodic benefit cost		12,627	14,767
Costs not recognized due to the effects of regulation		(5,296)	(7,843)
Net benefit cost (credit) recognized for financial reporting		7,331	6,924
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
Interest cost		981	954
Expected return on plan assets		(43)	(30)
Amortization of prior service cost (credit)		(759)	(759)
Amortization of net loss		401	523
Net periodic benefit cost		611	728
Costs not recognized due to the effects of regulation		0	0
Net benefit cost (credit) recognized for financial reporting		$ 611	$ 728
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
	Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	$ (21,081)	$ (20,814)
Other comprehensive income (loss) before reclassifications	(1)	(5)
(Gains) losses reclassified from net accumulated other comprehensive loss	242	202
Net current period other comprehensive income (loss)	241	197
Accumulated other comprehensive income (loss) at end of period	(20,840)	(20,617)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	320,496	314,050
Total, pre-tax	(141,097)	(9,894)
Tax benefit	46,468	2,970
Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, net of tax	242	202
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	(19,090)	(19,909)
Other comprehensive income (loss) before reclassifications	(1)	(6)
(Gains) losses reclassified from net accumulated other comprehensive loss	223	208
Net current period other comprehensive income (loss)	222	202
Accumulated other comprehensive income (loss) at end of period	(18,868)	(19,707)
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	377	351
Tax benefit	(154)	(143)
Total, net of tax	223	208
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	337
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	31	14
Unrealized Gains and Losses on Marketable Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	105	105
Other comprehensive income (loss) before reclassifications	0	1
(Gains) losses reclassified from net accumulated other comprehensive loss	0	0
Net current period other comprehensive income (loss)	0	1
Accumulated other comprehensive income (loss) at end of period	105	106
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	(2,096)	(1,010)
Other comprehensive income (loss) before reclassifications	0	0
(Gains) losses reclassified from net accumulated other comprehensive loss	19	(6)
Net current period other comprehensive income (loss)	19	(6)
Accumulated other comprehensive income (loss) at end of period	(2,077)	(1,016)
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net loss	83	39
Prior service credit	(49)	(49)
Total, pre-tax	34	(10)
Tax benefit	(15)	4
Total, net of tax	$ 19	$ (6)