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, 2018

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, smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

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

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

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

Class	Outstanding at April 27, 2018
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	31
PART II —	OTHER INFORMATION
Item 1 —	Legal Proceedings	31
Item 1A —	Risk Factors	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).

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
	2018			2017
Operating revenues
Electric, non-affiliates	$	945,291		$	955,341
Electric, affiliates	116,972			123,689
Natural gas	241,432			221,183
Other	7,056			6,927
Total operating revenues	1,310,751			1,307,140
Operating expenses
Electric fuel and purchased power	407,772			396,121
Cost of natural gas sold and transported	155,266			142,745
Cost of sales — other	4,181			4,178
Operating and maintenance expenses	292,295			308,626
Conservation program expenses	30,810			32,499
Depreciation and amortization	181,478			172,179
Taxes (other than income taxes)	67,545			68,324
Total operating expenses	1,139,347			1,124,672
Operating income	171,404			182,468
Other income (expense), net	216			(1,534		)
Allowance for funds used during construction — equity	6,748			6,283
Interest charges and financing costs
Interest charges — includes other financing costs of  $1,815 and $1,786, respectively	57,352			57,264
Allowance for funds used during construction — debt	(3,435		)	(3,228		)
Total interest charges and financing costs	53,917			54,036
Income before income taxes	124,451			133,181
Income taxes	12,711			39,015
Net income	$	111,740		$	94,166

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
	2018			2017
Net income	$	111,740		$	94,166
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $23 and $25, respectively	53			35
Derivative instruments:
Net fair value increase (decrease), net of tax of $2 and $0, respectively	5			—
Reclassification of losses to net income, net of tax of $65 and $139, respectively	167			203
	172			203
Marketable securities:
Reclassification of gains to net income, net of tax of $(51) and $0, respectively	(128		)	—
Other comprehensive income	97			238
Comprehensive income	$	111,837		$	94,404

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,
	2018			2017
Operating activities
Net income	$	111,740		$	94,166
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	183,058			173,726
Nuclear fuel amortization	30,785			30,852
Deferred income taxes	9,474			52,411
Amortization of investment tax credits	(409		)	(414		)
Allowance for equity funds used during construction	(6,748		)	(6,283		)
Net realized and unrealized hedging and derivative transactions	(1,006		)	1,744
Other, net	(1,245		)	—
Changes in operating assets and liabilities:
Accounts receivable	(34,677		)	(25,483		)
Accrued unbilled revenues	76,058			69,893
Inventories	45,261			32,678
Other current assets	39,247			(6,397		)
Accounts payable	(47,971		)	(22,007		)
Net regulatory assets and liabilities	74,143			1,513
Other current liabilities	34,793			(16,016		)
Pension and other employee benefit obligations	(60,804		)	(58,004		)
Change in other noncurrent assets	750			849
Change in other noncurrent liabilities	(18,304		)	(11,593		)
Net cash provided by operating activities	434,145			311,635
Investing activities
Utility capital/construction expenditures	(214,092		)	(277,125		)
Allowance for equity funds used during construction	6,748			6,283
Purchases investment securities	(184,565		)	(172,751		)
Proceeds from the sale of investment securities	179,472			167,658
Investments in utility money pool arrangement	(159,000		)	(87,000		)
Repayments from utility money pool arrangement	111,000			87,000
Other, net	(2,605		)	(4,565		)
Net cash used in investing activities	(263,042		)	(280,500		)
Financing activities
Repayments of short-term borrowings, net	(20,000		)	(46,000		)
Borrowings under utility money pool arrangement	69,000			25,000
Repayments under utility money pool arrangement	(154,000		)	(25,000		)
Repayments of long-term debt, including reacquisition premiums	(5		)	(10		)
Capital contributions from parent	49,622			89,487
Dividends paid to parent	(98,687		)	(89,428		)
Net cash used in financing activities	(154,070		)	(45,951		)
Net change in cash and cash equivalents	17,033			(14,816		)
Cash and cash equivalents at beginning of period	43,781			47,595
Cash and cash equivalents at end of period	$	60,814		$	32,779
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(63,767	)	$	(68,511	)
Cash received for income taxes, net	48,205			10,080
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	35,823		$	48,551

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, 2018			Dec. 31, 2017
Assets
Current assets
Cash and cash equivalents	$	60,814		$	43,781
Accounts receivable, net	380,488			345,110
Accounts receivable from affiliates	18,770			48,494
Investments in utility money pool arrangement	48,000			—
Accrued unbilled revenues	201,658			277,716
Inventories	292,491			337,712
Regulatory assets	283,438			276,392
Derivative instruments	14,564			25,230
Prepaid taxes	33,205			79,145
Prepayments and other	51,077			43,682
Total current assets	1,384,505			1,477,262
Property, plant and equipment, net	13,028,405			13,033,612
Other assets
Nuclear decommissioning fund and other investments	2,198,254			2,192,344
Regulatory assets	1,165,925			1,190,429
Derivative instruments	29,902			28,102
Other	15,393			4,142
Total other assets	3,409,474			3,415,017
Total assets	$	17,822,384		$	17,925,891
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	7		$	7
Short-term debt	—			20,000
Borrowings under utility money pool arrangement	—			85,000
Accounts payable	308,039			368,342
Accounts payable to affiliates	54,787			80,070
Regulatory liabilities	84,405			83,403
Taxes accrued	295,569			229,335
Accrued interest	52,517			65,896
Dividends payable to parent	84,558			98,687
Derivative instruments	19,045			17,697
Customer deposits	99,293			95,369
Other	145,054			152,965
Total current liabilities	1,143,274			1,296,771
Deferred credits and other liabilities
Deferred income taxes	1,617,720			1,612,341
Deferred investment tax credits	22,119			22,528
Regulatory liabilities	2,013,845			1,978,527
Asset retirement obligations	2,109,092			2,083,874
Derivative instruments	98,692			102,742
Pension and employee benefit obligations	269,870			331,087
Other	90,907			89,440
Total deferred credits and other liabilities	6,222,245			6,220,539
Commitments and contingencies
Capitalization
Long-term debt	4,934,017			4,933,011
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at March 31, 2018 and Dec. 31, 2017, respectively	10			10
Additional paid in capital	3,600,234			3,580,234
Retained earnings	1,947,044			1,919,863
Accumulated other comprehensive loss	(24,440		)	(24,537		)
Total common stockholder’s equity	5,522,848			5,475,570
Total liabilities and equity	$	17,822,384		$	17,925,891

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, 2018 and Dec. 31, 2017; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2018 and 2017; and its cash flows for the three months endedMarch 31, 2018 and 2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2018 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, 2017 balance sheet information has been derived from the audited 2017 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2017. 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, 2017, filed with the SEC on Feb. 26, 2018. 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, 2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Leases —In February 2016, the Financial Accounting Standards Board (FASB) issued Leases, Topic 842 (Accounting Standards Update (ASU) No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. NSP-Minnesota has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered into prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. NSP-Minnesota expects that similar agreements entered into after Dec. 31, 2018 will generally qualify as leases under the new standard.

Recently Adopted

Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. NSP-Minnesota implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on NSP-Minnesota’s consolidated financial statements. For related disclosures, see Note 13.

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 eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. NSP-Minnesota implemented the guidance on Jan. 1, 2018. As a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, historically classified as available-for-sale, continue to be deferred to a regulatory asset, and the overall adoption impacts were not material.

7

Presentation of Net Periodic Benefit Cost —In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment, and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. NSP-Minnesota implemented the new guidance on Jan. 1, 2018, and as a result, $3.4 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for the three months ended March 31, 2017. Under a practical expedient permitted by the standard, NSP-Minnesota used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	401,941		$	366,388
Less allowance for bad debts	(21,453		)	(21,278		)
	$	380,488		$	345,110

(Thousands of Dollars)	March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	208,571	$	209,236
Fuel	78,668		94,483
Natural gas	5,252		33,993
	$	292,491	$	337,712

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	17,132,020		$	17,024,925
Natural gas plant	1,383,329			1,370,330
Common and other property	726,591			724,066
Construction work in progress	547,219			530,126
Total property, plant and equipment	19,789,159			19,649,447
Less accumulated depreciation	(7,136,022		)	(7,018,249		)
Nuclear fuel	2,701,050			2,697,412
Less accumulated amortization	(2,325,782		)	(2,294,998		)
	$	13,028,405		$	13,033,612

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, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

8

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:

	Three Months ended March 31
		2018		2017
Federal statutory rate		21.0	%	35.0	%
State tax, net of federal tax effect		7.1		5.8
Increases (decreases) in tax from:
Wind production tax credits		(17.0	)	(10.7	)
Regulatory differences - ARAM (a)		(8.7	)	(0.2	)
Regulatory differences - ARAM deferral (b)		8.5		—
Regulatory differences - other utility plant items		0.1		0.1
Other tax credits, net of federal income tax expense		(1.5	)	(1.0	)
Other, net		0.7		0.3
Effective income tax rate		10.2	%	29.3	%

^(a)   The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

^(b) As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

Federal Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	December 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback and in 2015 the IRS forwarded the issue to the Office of Appeals (“Appeals”). In 2017 Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. As of March 31, 2018, the case has been forwarded to the Joint Committee on Taxation.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of March 31, 2018, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is uncertain.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2018, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In 2016, the state of Minnesota began an audit of years 2010 through 2014. As of March 31, 2018, Minnesota had not proposed any material adjustments.

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

9

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

(Millions of Dollars)	March 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	10.6	$	10.2
Unrecognized tax benefit — Temporary tax positions	7.9		7.9
Total unrecognized tax benefit	$	18.5	$	18.1

The unrecognized tax benefit amounts were reduced by the tax benefits associated with 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, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(14.6	)	$	(12.8	)

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 progresses and audit resumes, the Minnesota audit progresses, and other state audits resume. As the IRS Appeals and Minnesota audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $12 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	March 31, 2018			Dec. 31, 2017
Payable for interest related to unrecognized tax benefits at beginning of period	$	(0.9	)	$	(2.0	)
Interest income (expense) related to unrecognized tax benefits recorded during the period	(1.0		)	1.1
Payable for interest related to unrecognized tax benefits at end of period	$	(1.9	)	$	(0.9	)

No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2018 or Dec. 31, 2017.

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, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Tax Reform — Regulatory Proceedings

The Minnesota Public Utility Commission (MPUC) opened a TCJA docket and issued a request for information on the impacts of the TCJA in January 2018. In March 2018, the Minnesota Department of Commerce (DOC) recommended adjusting rates or implementing refunds for the current tax impacts and incorporating the deferred tax impacts in each utility’s next rate case.

In April 2018, NSP-Minnesota filed an update of the estimated impact of the TCJA, which reflected an overall reduction in 2018 revenue requirements of approximately $136 million for electric and $7 million for natural gas. The filing also proposed recommended options for delivering tax reform benefits to customers. The proposed electric options included: customer refunds and rider impacts of $68 million, deferral of $44 million to allow for a rate case stay-out for 2020, acceleration of depreciation for the King coal plant of $22 million and low income program funding of $2 million. The proposed natural gas options included customer refunds and rider impacts of $3 million, with the remaining TCJA benefits deferred to mitigate increased costs in the next natural gas rate case. A MPUC decision is expected later in 2018.

Dockets have also been opened in North Dakota and South Dakota. In February 2018, NSP-Minnesota proposed using the reduced revenue requirements from the TCJA to defer planned future rate filings in both jurisdictions.

10

Federal Energy Regulatory Commission (FERC) Formula Rates — The FERC has not yet issued guidance on how or when electric utilities should reflect the impacts of the TCJA in FERC jurisdictional wholesale rates. The FERC issued a Notice of Inquiry (NOI) in March 2018 seeking comments on how to reflect TCJA impacts in wholesale rates, in particular changes to accumulated deferred income taxes and bonus depreciation. Comments for the NOI are due in May 2018. However, FERC-approved formula rates for wholesale customers are generally adjusted on an annual basis for certain changes in rate base and actual operating expenses, including income taxes. As a result, these revenues would be subject to an automatic reduction for the effect of the TCJA corporate tax rate change through the annual true-up process, absent specific FERC action.

NSP-Minnesota was a party to a February 2018 FERC filing by certain transmission owner (TO) members of the Midcontinent Independent System Operator, Inc. (MISO) proposing to commence early reductions to transmission formula rates in 2018 for corporate tax rate impacts of the TCJA. In March 2018, the FERC issued orders granting MISO TO waiver requests so that 2018 rates will reflect the lower federal corporate tax rate.

Pending Regulatory Proceedings — MPUC

GUIC Rider — In February 2018, the MPUC approved a 2017 revenue requirement of approximately $20 million for GUIC investments. New rates went into effect in March 2018. In November 2017, NSP-Minnesota filed the 2018 GUIC rider with the MPUC requesting recovery of approximately $28 million from Minnesota gas utility customers. In March 2018, NSP-Minnesota filed a supplement to the 2018 GUIC rider filing to provide an updated capital forecast and address the impact of the TCJA. The net result decreased NSP-Minnesota’s 2018 GUIC revenue requirement to approximately $24 million. The MPUC is currently considering the 2018 petition.

Renewable Energy Standard (RES) Rider — In 2017, NSP-Minnesota filed the 2017 and 2018 RES rider petition with the MPUC, requesting approval of a 2017 over-recovery of approximately $10 million and a 2018 revenue requirement of approximately $11 million. The petition was based on a requested return on equity (ROE) of 10.0 percent and includes costs associated with the Courtenay wind farm and the 1,550 megawatt (MW) wind portfolio, which are offset by production tax credits (PTCs) and proceeds from renewable energy credit (REC) sales. The increase in revenue requirements in 2018 is due to new wind projects entering the construction phase. In February and March 2018, NSP-Minnesota filed supplements to the 2017 and 2018 RES rider petition to provide updated actual results and address TCJA impacts. NSP-Minnesota’s revised 2017 refund is approximately $13 million, and the revised 2018 revenue requirement is approximately $23 million. The increase in 2018 revenue requirements from the original request is primarily driven by the TCJA impact on PTCs earned on existing wind asset-related costs. A decision from the MPUC is expected later in 2018.

Pending Regulatory Proceeding — FERC

MISO ROE Complaints — In November 2013, a group of customers filed a complaint at the FERC against MISO 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, and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership), effective Nov. 12, 2013.

In September 2016, the FERC approved an Administrative Law Judge (ALJ) recommendation that MISO TOs be granted a 10.32 percent base ROE using the methodology adopted by FERC in June 2014 (Opinion 531). This ROE would be applicable for the 15-month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent, including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action.

In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any RTO adder was filed, resulting in a second period of potential refunds from Feb. 12, 2015 to May 11, 2016. In June 2016, an ALJ recommended a base ROE of 9.7 percent, applying the FERC Opinion 531 methodology. Various parties filed exceptions to the ALJ recommendation, and FERC action is pending. In April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint.

NSP-Minnesota has recognized a current refund liability consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.

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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, 2017, 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.

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, 2018 and Dec. 31, 2017, 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 has a stated maximum amount; 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, 2018		Dec. 31, 2017
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 a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017, which involves targeted source removal of impacted soils and historic MGP infrastructure. It is anticipated that remediation activities will be performed in 2018. NSP-Minnesota has also 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 May 31, 2018.

NSP-Minnesota had recorded an estimated liability of $15 million as of March 31, 2018 and $16 million as of Dec. 31, 2017, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately $22 million, of which approximately $7 million has been spent. NSP-Minnesota has deferred Fargo MGP Site costs allocable to the North Dakota jurisdiction, or approximately 88 percent of all remediation costs, as approved by the North Dakota Public Service Commission (NDPSC). In December 2017, NSP-Minnesota filed a request with the MPUC to defer post-2017 MGP remediation expenditures allocable to the Minnesota jurisdiction, including the Fargo MGP site. In March 2018, the DOC recommended that the MPUC deny NSP-Minnesota’s deferral request. A MPUC decision is expected mid-2018.

Other MGP, Landfill or Disposal Sites — NSP-Minnesota is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. NSP-Minnesota has identified seven sites, in addition to the site in Fargo, N.D., where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities. NSP-Minnesota anticipates that these investigation or remediation activities will continue through at least 2018. NSP-Minnesota had accrued $3 million as of March 31, 2018 and Dec. 31, 2017 for all of these sites. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. Xcel Energy anticipates that any amounts spent will be fully recovered from customers.

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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, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			85
Average amount outstanding	14			25
Maximum amount outstanding	99			142
Weighted average interest rate, computed on a daily basis	1.59		%	1.14		%
Weighted average interest rate at period end	N/A			1.18

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	500		$	500
Amount outstanding at period end	—			20
Average amount outstanding	83			62
Maximum amount outstanding	195			237
Weighted average interest rate, computed on a daily basis	1.73		%	1.10		%
Weighted average interest rate at period end	N/A			1.93

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, 2018 and Dec. 31, 2017, there were $25 million and $24 million, respectively, 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 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, 2018, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	25	$	475

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

^(b)  Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at March 31, 2018 and Dec. 31, 2017.

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 net asset value (NAV).

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take 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 may be redeemed for NAV 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.

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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 classification. 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. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. 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 the cleared prices for each FTR for the most recent auction.

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 transparency in the auction process, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements 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, the limited transparency associated with the valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

The Nuclear Regulatory Commission 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 decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments. 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 impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $543 million and $560 million as of March 31, 2018 and Dec. 31, 2017, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $18 million and $7 million as of March 31, 2018 and Dec. 31, 2017, 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 as of March 31, 2018 and Dec. 31, 2017:

	March 31, 2018
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	41,250	$	41,250	$	—	$	—	$	—	$	41,250
Commingled funds:
Non U.S. equities	270,384		226,127		—		—		90,369		316,496
Emerging market debt funds	157,087		—		—		—		163,868		163,868
Private equity investments	141,991		—		—		—		198,060		198,060
Real estate	118,189		—		—		—		185,851		185,851
Other commingled funds	3,902		900		—		—		2,975		3,875
Debt securities:
Government securities	78,197		—		77,505		—		—		77,505
U.S. corporate bonds	325,042		—		320,812		—		—		320,812
Non U.S. corporate bonds	54,637		—		53,151		—		—		53,151
Equity securities:
U.S. equities	277,853		556,816		—		—		—		556,816
Non U.S. equities	152,670		228,903		—		—		—		228,903
Total	$	1,621,202	$	1,053,996	$	451,468	$	—	$	641,123	$	2,146,587

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.

^(b)  Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

	Dec. 31, 2017
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	28,741	$	28,741	$	—	$	—	$	—	$	28,741
Commingled funds:
Non U.S. equities	263,694		216,551		—		—		89,857		306,408
Emerging market debt funds	156,057		—		—		—		166,375		166,375
Private equity investments	141,413		—		—		—		198,037		198,037
Real estate	130,787		—		—		—		201,842		201,842
Other commingled funds	9,340		6,286		—		—		2,975		9,261
Debt securities:
Government securities	67,760		—		69,413		—		—		69,413
U.S. corporate bonds	319,809		—		322,129		—		—		322,129
Non U.S. corporate bonds	50,121		—		50,102		—		—		50,102
Equity securities:
U.S. equities	271,166		556,974		—		—		—		556,974
Non U.S. equities	151,961		233,999		—		—		—		233,999
Total	$	1,590,849	$	1,042,551	$	441,644	$	—	$	659,086	$	2,143,281

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49 million of rabbi trust assets and miscellaneous investments.

^(b)  Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

For the three months ended March 31, 2018 and 2017 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

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The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, as of March 31, 2018:

	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	$	—	$	9,124	$	2,318	$	66,063	$	77,505
U.S. corporate bonds	2,886		87,565		173,634		56,727		320,812
Non U.S. corporate bonds	—		16,263		33,328		3,560		53,151
Debt securities	$	2,886	$	112,952	$	209,280	$	126,350	$	451,468

Rabbi Trusts

In 2016, NSP-Minnesota established a rabbi trust to provide partial funding for future deferred compensation plan distributions. The following tables present the cost and fair value of the assets held in rabbi trust at March 31, 2018 and Dec. 31, 2017:

	March 31, 2018
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trust (a)
Cash equivalents	$	393	$	393	$	—	$	—	$	393
Mutual funds	10,373		11,151		—		—		11,151
Total	$	10,766	$	11,544	$	—	$	—	$	11,544

	Dec. 31, 2017
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	783	$	783	$	—	$	—	$	783
Mutual funds	10,332		11,283		—		—		11,283
Total	$	11,115	$	12,066	$	—	$	—	$	12,066

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

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, 2018, 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 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, energy-related instruments and natural gas related instruments, including derivatives. 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.

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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, 2018, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. NSP-Minnesota enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be 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, 2018 and 2017.

At March 31, 2018, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net gains 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, 2018 and Dec. 31, 2017:

(Amounts in Thousands)(a)(b)	March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	32,451	41,711
Million British thermal units of natural gas	18,330	23,829
Gallons of vehicle fuel	180	240

^(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, 2018 and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended March 31, 2018
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (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	$	—	$	—		$	261		(a)	$	—			$	—
Vehicle fuel and other commodity	7		—			(29		)	(b)	—				—
Total	$	7	$	—		$	232			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	2,740		(c)
Electric commodity	—		(4,259		)	—				2,169			(d)	—
Natural gas commodity	—		848			—				(520		)	(e)	(404		)	(e)
Total	$	—	$	(3,411	)	$	—			$	1,649			$	2,336

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	Three Months Ended March 31, 2017
	Pre-Tax Fair Value (Losses) Recognized During the Period in:					Pre-Tax (Gains) 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	$	—	$	—		$	342	(a)	$	—			$	—
Total	$	—	$	—		$	342		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	622		(c)
Electric commodity	—		(1,247		)	—			(2,788		)	(d)	—
Natural gas commodity	—		(665		)	—			698			(e)	(945		)	(e)
Total	$	—	$	(1,912	)	$	—		$	(2,090	)		$	(323	)

^(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, 2018 and 2017. 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 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 activities. At March 31, 2018, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $45.1 million or 58 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Two of the 10 most significant counterparties, comprising $15.8 million or 20 percent of this credit exposure, were not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. All ten of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those 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’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. At March 31, 2018 and Dec. 31, 2017, there were no derivative instruments in a material liability position with such underlying contract provisions.

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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, 2018 and Dec. 31, 2017.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2018:

	March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	85	$	—	$	85	$	—		$	85
Other derivative instruments:
Commodity trading	598		14,123		205		14,926		(6,931		)	7,995
Electric commodity	—		—		5,765		5,765		(33		)	5,732
Total current derivative assets	$	598	$	14,208	$	5,970	$	20,776	$	(6,964	)	13,812
PPAs (a)												752
Current derivative instruments												$	14,564
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	602		35,308		8,048		43,958		(14,170		)	29,788
Total noncurrent derivative assets	$	602	$	35,308	$	8,048	$	43,958	$	(14,170	)	29,788
PPAs (a)												114
Noncurrent derivative instruments												$	29,902

	March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	647	$	11,643	$	—	$	12,290	$	(7,351	)	$	4,939
Electric commodity	—		—		34		34		(34		)	—
Total current derivative liabilities	$	647	$	11,643	$	34	$	12,324	$	(7,385	)	4,939
PPAs (a)												14,106
Current derivative instruments												$	19,045
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1,868	$	27,604	$	468	$	29,940	$	(17,698	)	$	12,242
Total noncurrent derivative liabilities	$	1,868	$	27,604	$	468	$	29,940	$	(17,698	)	12,242
PPAs (a)												86,450
Noncurrent derivative instruments												$	98,692

^(a)  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, 2018. At March 31, 2018, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.9 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, 2017:

	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	107	$	—	$	107	$	—		$	107
Other derivative instruments:
Commodity trading	$	1,691	$	17,144	$	142	$	18,977	$	(11,744	)	$	7,233
Electric commodity	—		—		17,581		17,581		(425		)	17,156
Natural gas commodity	—		77		—		77		—			77
Total current derivative assets	$	1,691	$	17,328	$	17,723	$	36,742	$	(12,169	)	24,573
PPAs (a)												657
Current derivative instruments												$	25,230
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	29,121	$	5,363	$	34,484	$	(6,502	)	$	27,982
Total noncurrent derivative assets	$	—	$	29,121	$	5,363	$	34,484	$	(6,502	)	27,982
PPAs (a)												120
Noncurrent derivative instruments												$	28,102

	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1,713	$	13,853	$	—	$	15,566	$	(11,974	)	$	3,592
Electric commodity	—		—		425		425		(425		)	—
Total current derivative liabilities	$	1,713	$	13,853	$	425	$	15,991	$	(12,399	)	3,592
PPAs (a)												14,105
Current derivative instruments												$	17,697
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	22,163	$	—	$	22,163	$	(9,334	)	$	12,829
Total noncurrent derivative liabilities	$	—	$	22,163	$	—	$	22,163	$	(9,334	)	12,829
PPAs (a)												89,913
Noncurrent derivative instruments												$	102,742

^(a)  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, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.1 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, 2018 and 2017:

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Balance at Jan. 1	$	22,661		$	15,320
Purchases	2			280
Settlements	(1,934		)	(3,426		)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)	2,280			(792		)
Net losses recognized as regulatory assets and liabilities	(9,493		)	(6,739		)
Balance at March 31	$	13,516		$	4,643

^(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, 2018 and 2017.

Fair Value of Long-Term Debt

As of March 31, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,934,024	$	5,352,133	$	4,933,018	$	5,601,919

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, 2018 and Dec. 31, 2017, 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 (Expense), Net

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

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Interest income	$	2,935		$	2,709
Insurance policy income (expense)	342			(855		)
Other nonoperating income	1			10
Benefits non-service cost	(3,062		)	(3,398		)
Other income (expense), net	$	216		$	(1,534	)

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, 2018
Operating revenues (a)(b)	$	1,062,263	$	241,432	$	7,056	$	—		$	1,310,751
Intersegment revenues	165		144		—		(309		)	—
Total revenues	$	1,062,428	$	241,576	$	7,056	$	(309	)	$	1,310,751
Net income	$	85,722	$	25,445	$	573	$	—		$	111,740

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2017
Operating revenues (a)(b)	$	1,079,030	$	221,183	$	6,927		$	—		$	1,307,140
Intersegment revenues	109		94		—			(203		)	—
Total revenues	$	1,079,139	$	221,277	$	6,927		$	(203	)	$	1,307,140
Net income	$	78,082	$	17,505	$	(1,421	)	$	—		$	94,166

^(a)  Operating revenues include $117 million and $124 million of affiliate electric revenue for the three months ended March 31, 2018 and 2017.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 2018 and 2017.

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,982		$	6,958		$	43		$	36
Interest cost (a)	8,804			10,177			769			854
Expected return on plan assets (a)	(14,541		)	(15,017		)	(96		)	(54		)
Amortization of prior service cost (credit) (a)	(29		)	265			(759		)	(759		)
Amortization of net loss (a)	9,615			9,902			595			507
Net periodic benefit cost	10,831			12,285			552			584
Costs not recognized due to the effects of regulation	(2,763		)	(4,899		)				—
Net benefit cost recognized for financial reporting	$	8,068		$	7,386		$	552		$	584

^(a) The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the income statement or capitalized on the balance sheet as a regulatory asset.

In January 2018, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $63.0 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2018.

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12. Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2018 and 2017 were as follows:

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(20,895	)	$	128		$	(3,770	)	$	(24,537	)
Other comprehensive income before reclassifications	5			—			—			5
Losses reclassified from net accumulated other comprehensive loss	167			(128		)	53			92
Net current period other comprehensive income	172			(128		)	53			97
Accumulated other comprehensive loss at March 31	$	(20,723	)	$	—		$	(3,717	)	$	(24,440	)

	Three Months Ended March 31, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(18,208	)	$	105	$	(2,680	)	$	(20,783	)
Losses reclassified from net accumulated other comprehensive loss	203			—		35			238
Net current period other comprehensive income	203			—		35			238
Accumulated other comprehensive loss at March 31	$	(18,005	)	$	105	$	(2,645	)	$	(20,545	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2018 and 2017 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	261		(a)	$	342		(a)
Vehicle fuel derivatives	(29		)	(b)	—			(b)
Total, pre-tax	232				342
Tax benefit	(65		)		(139		)
Total, net of tax	167				203
Defined benefit pension and postretirement losses:
Amortization of net loss	125			(c)	109			(c)
Prior service credit	(49		)	(c)	(49		)	(c)
Total, pre-tax	76				60
Tax benefit	(23		)		(25		)
Total, net of tax	53				35
Marketable securities:
Realization of gains	(179		)		—
Total, pre-tax	(179		)		—
Tax expense	51				—
Total, net of tax	(128		)		—
Total amounts reclassified, net of tax	$	92			$	238

^(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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13. Revenues

NSP-Minnesota principally generates revenue from the transmission, distribution and sale of electricity and the transportation, distribution and sale of natural gas to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such NSP-Minnesota does not recognize a separate financing component of its collections from customers. NSP-Minnesota presents its revenues net of any excise or other fiduciary-type taxes or fees.

NSP-Minnesota participates in MISO. NSP-Minnesota recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

NSP-Minnesota has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.

When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.

In the following tables, revenue is classified by the type of goods/services rendered and market/customer type. The tables also reconcile revenue to the reportable segments.

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	311,129	$	131,659	$	6,323	$	449,111
Commercial and industrial (C&I)	468,023		96,908		43		564,974
Other	9,719		—		690		10,409
Total retail	788,871		228,567		7,056		1,024,494
Wholesale	46,365		—		—		46,365
Transmission	54,798		—		—		54,798
Interchange	116,972		—		—		116,972
Other	11,545		2,211		—		13,756
Total revenue from contracts with customers	1,018,551		230,778		7,056		1,256,385
Alternative revenue and other	43,712		10,654		—		54,366
Total revenues	$	1,062,263	$	241,432	$	7,056	$	1,310,751

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	Three Months Ended March 31, 2017
(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	304,413	$	121,413	$	6,210	$	432,036
C&I	485,103		88,491		38		573,632
Other	8,203		—		679		8,882
Total retail	797,719		209,904		6,927		1,014,550
Wholesale	45,919		—		—		45,919
Transmission	53,959		—		—		53,959
Interchange	123,689		—		—		123,689
Other	5,963		1,245		—		7,208
Total revenue from contracts with customers	1,027,249		211,149		6,927		1,245,325
Alternative revenue and other	51,781		10,034		—		61,815
Total revenues	$	1,079,030	$	221,183	$	6,927	$	1,307,140

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 including the TCJA’s impact to NSP-Minnesota and its customers, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” 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, 2017 and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-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 or cost of capital; and employee work force factors.

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Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin and natural gas margin.  Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from the most directly comparable measure calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures internally for financial planning and analysis, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our operating performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric margin is presented as electric revenues less electric fuel and purchased power expenses and natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas sold and transported are generally recovered through various recovery mechanisms, and as a result, changes in these expenses are offset in operating revenues. Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales — other, O&M expenses, conservation program expenses, depreciation and amortization and taxes (other than income taxes).

Results of Operations

NSP-Minnesota’s net income was approximately $112 million for the first quarter of 2018, compared with approximately $94 million for the same period of 2017. The increase in earnings, driven by lower O&M expenses and higher natural gas margins, was partially offset by higher depreciation expense.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. The following table details the electric revenues and margin:

	Three Months Ended March 31
(Millions of Dollars)	2018			2017
Electric revenues	$	1,089		$	1,079
Electric fuel and purchased power	(408		)	(396		)
Electric margin before impact of the TCJA	$	681		$	683
Impact of the TCJA (offset as a reduction in income tax expense)	(27		)	—
Electric margin	$	654		$	683

The following tables summarize the components of the changes in electric revenues and electric margin for the three months endedMarch 31:

Electric Revenues

(Millions of Dollars)	2018 vs. 2017
Interchange agreement billings with NSP-Wisconsin	$	(7	)
Conservation program revenue, offset by expenses	(4		)
Conservation incentive	(3		)
Fuel and purchased power cost recovery	14
Estimated impact of weather, net of Minnesota decoupling	5
Wholesale transmission revenue	4
Other, net	1
Total increase in electric revenue before impact of the TCJA	$	10
Impact of the TCJA (offset as a reduction in income tax expense)	(27		)
Total decrease in electric revenues	$	(17	)

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Electric Margin

(Millions of Dollars)	2018 vs. 2017
Interchange agreement billings with NSP-Wisconsin	$	(8	)
Conservation program revenue, offset by expenses	(4		)
Conservation incentive	(3		)
Purchased capacity costs	10
Estimated impact of weather, net of Minnesota decoupling	5
Other, net	(2		)
Total decrease in electric margin before impact of the TCJA	$	(2	)
Impact of the TCJA (offset as a reduction in income tax expense)	(27		)
Total decrease in electric margin	$	(29	)

Natural Gas Revenues and Margin

Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas have minimal impact on natural gas margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin:

	Three Months Ended March 31
(Millions of Dollars)	2018			2017
Natural gas revenues	$	244		$	221
Cost of natural gas sold and transported	(155		)	(143		)
Natural gas margin before impact of the TCJA	$	89		$	78
Impact of the TCJA (offset as a reduction in income tax expense)	(3		)	—
Natural gas margin	$	86		$	78

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the three months endedMarch 31:

Natural Gas Revenues

(Millions of Dollars)	2018 vs. 2017
Purchased natural gas adjustment clause recovery	$	11
Estimated impact of weather	7
Conservation program revenue, offset by expenses	2
Other, net	3
Total increase in natural gas revenues before impact of the TCJA	$	23
Impact of the TCJA (offset as a reduction in income tax expense)	(3		)
Total increase in natural gas revenues	$	20

Natural Gas Margin

(Millions of Dollars)	2018 vs. 2017
Estimated impact of weather	$	7
Conservation program revenue, offset by expenses	2
Other, net	2
Total increase in natural gas margin before impact of the TCJA	$	11
Impact of the TCJA (offset as a reduction in income tax expense)	(3		)
Total increase in natural gas margin	$	8

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Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses decreased $16 million, or 5.3 percent, for the first quarter of 2018, largely reflecting expense timing. The significant changes are summarized in the table below:

(Millions of Dollars)	2018 vs. 2017
Nuclear plant operations and amortization	$	(10	)
Employee benefits expense	(7		)
Plant generation costs	(2		)
Other, net	3
Total decrease in O&M expenses	$	(16	)

• Nuclear plant operations and amortization expenses are lower largely reflecting expense timing, savings initiatives and reduced refueling outage costs; and

• Plant generation costs decreased primarily due to the timing of planned maintenance and overhauls at a number of generation facilities.

Conservation Program Expenses — Conservation program expenses decreased$2 million, or 5.2 percent, for the first quarter of 2018. The decrease was due to lower recovery rates, partially offset by additional customer participation in electric conservation programs. Conservation expenses are generally recovered concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.

Depreciation and Amortization— Depreciation and amortization expense increased$9 million, or 5.4 percent, for the first quarter of 2018. The increase was primarily attributable to capital investments due to normal system expansion.

Income Taxes — Income tax expense decreased$26 million for the first quarter of 2018 compared with the same period in 2017. The decrease was primarily driven by a lower federal tax rate due to the TCJA, an increase in wind PTCs, which are largely flowed back to customers through electric margin, and an increase in plant-related regulatory differences related to ARAM. This was partially offset by the deferral of the effects of ARAM. The ETR was 10.2 percent for the first quarter of 2018 compared with 29.3 percent for the same period in 2017. The lower ETR in 2018 is primarily due to the items referenced above.

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, 2017 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

PPA Terminations and Amendments — In 2017, NSP-Minnesota filed requests with the MPUC and NDPSC to terminate or amend various PPAs to reduce future costs for customers, which are anticipated to result in excess of $600 million in net cost savings to NSP System customers over the next 10 years. In January 2018, the MPUC issued an order approving NSP-Minnesota’s petition to terminate the PPAs with Benson Power LLC (Benson) and Laurentian Energy Authority I, LLC (Laurentian), as well as purchase and close the Benson biomass facility. In March 2018, the MPUC denied requests by several parties to reconsider its approval to terminate the Benson and Laurentian PPAs. NSP-Minnesota reached a settlement agreement with the NDPSC Staff which allows for the termination of the PPAs with Benson and Laurentian, as well as the purchase and closure of the Benson biomass facility. A NDPSC decision is anticipated in May 2018.

Wind Development — In 2017, the MPUC approved NSP-Minnesota’s proposal to add 1,550 MW of new wind generation including ownership of 1,150 MW of wind generation. NSP-Minnesota plans to submit updates including TCJA impacts on the new wind generation to the MPUC and NDPSC in May 2018. The timing of a NDPSC order is uncertain. The regulatory filing updates are not expected to impact the timing of these projects which are expected to be completed by the end of 2020 and qualify for 100 percent of the PTC. NSP-Minnesota’s total capital investment for these wind ownership projects is expected to be approximately $1.9 billion.

In 2017, NSP-Minnesota filed with the MPUC seeking approval to build and own the Dakota Range, a 300 MW wind project in South Dakota. The project is expected to be placed into service by the end of 2021 and qualify for 80 percent of the PTC. In March 2018, NSP-Minnesota submitted supplemental filings to the MPUC and NDPSC regarding the impacts of the TCJA and other updated information for Dakota Range. These impacts result in a minimal increase in the revenue requirement for Dakota Range and the project continues to show significant benefits to customers. In April 2018, the MPUC approved NSP-Minnesota’s petition to build and own the Dakota Range. A NDPSC decision is pending.

29

These wind projects are expected to provide significant savings to NSP-Minnesota’s customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with various commission approved resource plans.

Minnesota State Right-Of-First Refusal (ROFR) Statute Complaint — In September 2017, LSP Transmission Holdings, LLC (LSP Transmission) filed a complaint in the U.S. District Court for the District of Minnesota (Minnesota District Court) against the Minnesota Attorney General, the MPUC and the DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from near Mankato, Minn. to Winnebago, Minn. The line was estimated by MISO to cost $103 million. The project was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenges the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In April 2018, the Antitrust Division of the United States Department of Justice, filed a statement in support of LSP Transmission’s position that the statute is unconstitutional. The matter is pending before the Minnesota District Court. The timing and outcome of the litigation is uncertain.

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, 2017 for further discussion regarding the nuclear generating plants. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2017, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated herein by reference.

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 58 percent of its 2018 and approximately 24 percent of its 2019 enriched nuclear material requirements from sources that could be impacted by current political/world events, including those related to Ukraine/Russia. Alternate potential sources are expected to provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply to ensure that plant availability and reliability will not be negatively impacted in the near-term. Long-term, through 2024, NSP-Minnesota is scheduled to take delivery of approximately 35 percent of its average enriched nuclear material requirements from these sources. NSP-Minnesota is closely following the progression of these events and will periodically assess if further actions are required to assure a secure supply of enriched nuclear material.

Separately, NSP-Minnesota has enriched nuclear fuel materials in process with Westinghouse Electric Corporation (Westinghouse). Westinghouse filed for Chapter 11 bankruptcy protection in March 2017. NSP-Minnesota owns materials in Westinghouse’s inventory and has contracts in place under which Westinghouse will provide certain services during an upcoming outage at PI. Westinghouse will provide nuclear fuel assemblies for the upcoming PI outage under the current nuclear fuel fabrication contract. Westinghouse has indicated its intention to continue to perform under the arrangements. Based on Westinghouse’s stated intent and the interim financing secured to fund its on-going operations, NSP-Minnesota does not expect the bankruptcy to materially impact NSP-Minnesota’s operational or financial performance. Westinghouse announced on Jan. 4, 2018 it has agreed to be acquired by Brookfield Business Partners LP and other institutional partners. Brookfield’s acquisition of Westinghouse is expected to close in the third quarter of 2018, subject to bankruptcy court and regulatory approvals. NSP-Minnesota will continue to monitor the Westinghouse acquisition process.

Summary of Recent Federal Regulatory Developments

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2017. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

Xcel Energy, which includes NSP-Minnesota, attempts to mitigate the risk of regulatory penalties through formal training on

prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations.

30

FERC Order, ROE Policy — In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order (Opinion 531) issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including two ROE complaints involving the MISO TOs, which include NSP-Minnesota and NSP-Wisconsin. In April 2017, the D.C. Circuit vacated and remanded the June 2014 ROE order. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for the NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. The FERC has yet to act on the D.C. Circuit’s decision. See Note 5 to the consolidated financial statements for discussion of the D.C. Circuit’s decision and the impact on the MISO ROE Complaints.

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, 2018, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Part I Item 2 and Note 5 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

NSP-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. 31,2017, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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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)).
4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from Northern States Power Company to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds (Exhibit 4(b)(3) to Form S-3 of Xcel Energy, filed April 18, 2018 (file no. 333-224333)).
4.02*	Indenture, dated July 1, 1999, between Northern States Power Company and Norwest Bank Minnesota, National Association, as Trustee, providing for the issuance of Sr. Debt Securities (Exhibit 4(b)(7) to Form S-3 of Xcel Energy, filed April 18, 2018 (file no. 333-224333)).
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, 2018 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)
April 27, 2018	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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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: April 27, 2018

/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: April 27, 2018

/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, 2018, 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: April 27, 2018

/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 of cost or 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, 2017, 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, 2018	Apr. 27, 2018
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	2018
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating revenues
Electric, non-affiliates	$ 945,291	$ 955,341
Electric, affiliates	116,972	123,689
Natural gas	241,432	221,183
Other	7,056	6,927
Total operating revenues	1,310,751	1,307,140
Operating expenses
Electric fuel and purchased power	407,772	396,121
Cost of natural gas sold and transported	155,266	142,745
Cost of sales — other	4,181	4,178
Operating and maintenance expenses	292,295	308,626
Conservation program expenses	30,810	32,499
Depreciation and amortization	181,478	172,179
Taxes (other than income taxes)	67,545	68,324
Total operating expenses	1,139,347	1,124,672
Operating income	171,404	182,468
Other income (expense), net	216	(1,534)
Allowance for funds used during construction — equity	6,748	6,283
Interest charges and financing costs
Interest charges — includes other financing costs of $1,815 and $1,786, respectively	57,352	57,264
Allowance for funds used during construction — debt	(3,435)	(3,228)
Total interest charges and financing costs	53,917	54,036
Income before income taxes	124,451	133,181
Income taxes	12,711	39,015
Net income	$ 111,740	$ 94,166

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Interest charges and financing costs
Other financing costs	$ 1,815	$ 1,786

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Comprehensive income:
Net income	$ 111,740	$ 94,166
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $23 and $25, respectively	53	35
Derivative instruments:
Net fair value increase (decrease), net of tax of $2 and $0, respectively	5	0
Reclassification of losses to net income, net of tax of $65 and $139, respectively	167	203
Total derivative instruments, net of tax	172	203
Marketable securities:
Reclassification of gains to net income, net of tax of $(51) and $0, respectively	(128)	0
Other comprehensive income	97	238
Comprehensive income	$ 111,837	$ 94,404

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, tax	$ 23	$ 25
Derivative instruments:
Net fair value (decrease) increase, tax	2	0
Reclassification of losses to net income, tax	65	139
Other Comprehensive Income (Loss), Available-for-sale Securities, Tax [Abstract]
Reclassification of gains to net income, tax	$ (51)	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities
Net income	$ 111,740	$ 94,166
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	183,058	173,726
Nuclear fuel amortization	30,785	30,852
Deferred income taxes	9,474	52,411
Amortization of Investment Tax Credits	(409)	(414)
Allowance for equity funds used during construction	(6,748)	(6,283)
Net realized and unrealized hedging and derivative transactions	(1,006)	1,744
Other, net	(1,245)	0
Changes in operating assets and liabilities:
Accounts receivable	(34,677)	(25,483)
Accrued unbilled revenues	76,058	69,893
Inventories	45,261	32,678
Other current assets	39,247	(6,397)
Accounts payable	(47,971)	(22,007)
Net regulatory assets and liabilities	74,143	1,513
Other current liabilities	34,793	(16,016)
Pension and other employee benefit obligations	(60,804)	(58,004)
Change in other noncurrent assets	750	849
Change in other noncurrent liabilities	(18,304)	(11,593)
Net cash provided by operating activities	434,145	311,635
Investing activities
Utility capital/construction expenditures	(214,092)	(277,125)
Allowance for equity funds used during construction	6,748	6,283
Purchases of investment securities	(184,565)	(172,751)
Proceeds from the sale of investment securities	179,472	167,658
Investments in utility money pool arrangement	(159,000)	(87,000)
Repayments from utility money pool arrangement	111,000	87,000
Other, net	(2,605)	(4,565)
Net cash used in investing activities	(263,042)	(280,500)
Financing activities
Repayments of short-term borrowings, net	(20,000)	(46,000)
Borrowings under utility money pool arrangement	69,000	25,000
Repayments under utility money pool arrangement	(154,000)	(25,000)
Repayments of long-term debt, including reacquisition premiums	(5)	(10)
Capital contributions from parent	49,622	89,487
Dividends paid to parent	(98,687)	(89,428)
Net cash used in financing activities	(154,070)	(45,951)
Net change in cash and cash equivalents	17,033	(14,816)
Cash and cash equivalents at beginning of period	43,781	47,595
Cash and cash equivalents at end of period	60,814	32,779
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(63,767)	(68,511)
Cash received for income taxes, net	48,205	10,080
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 35,823	$ 48,551

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 60,814	$ 43,781
Accounts receivable, net	380,488	345,110
Accounts receivable from affiliates	18,770	48,494
Investments Receivable in Utility Money Pool Arrangement	48,000	0
Accrued unbilled revenues	201,658	277,716
Inventories	292,491	337,712
Regulatory assets	283,438	276,392
Derivative instruments	14,564	25,230
Prepaid Taxes	33,205	79,145
Prepayments and other	51,077	43,682
Total current assets	1,384,505	1,477,262
Property, plant and equipment, net	13,028,405	13,033,612
Other assets
Nuclear decommissioning fund and other investments	2,198,254	2,192,344
Regulatory assets	1,165,925	1,190,429
Derivative instruments	29,902	28,102
Other	15,393	4,142
Total other assets	3,409,474	3,415,017
Total assets	17,822,384	17,925,891
Current liabilities
Current portion of long-term debt	7	7
Short-term debt	0	20,000
Borrowings under utility money pool arrangement	0	85,000
Accounts payable	308,039	368,342
Accounts payable to affiliates	54,787	80,070
Regulatory liabilities	84,405	83,403
Taxes accrued	295,569	229,335
Accrued interest	52,517	65,896
Dividends payable to parent	84,558	98,687
Derivative instruments	19,045	17,697
Customer deposits	99,293	95,369
Other	145,054	152,965
Total current liabilities	1,143,274	1,296,771
Deferred credits and other liabilities
Deferred income taxes	1,617,720	1,612,341
Deferred investment tax credits	22,119	22,528
Regulatory liabilities	2,013,845	1,978,527
Asset retirement obligations	2,109,092	2,083,874
Derivative instruments	98,692	102,742
Pension and employee benefit obligations	269,870	331,087
Other	90,907	89,440
Total deferred credits and other liabilities	6,222,245	6,220,539
Commitments and contingencies
Capitalization
Long-term debt	4,934,017	4,933,011
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at March 31, 2018 and Dec. 31, 2017, respectively	10	10
Additional paid in capital	3,600,234	3,580,234
Retained earnings	1,947,044	1,919,863
Accumulated other comprehensive loss	(24,440)	(24,537)
Total common stockholder’s equity	5,522,848	5,475,570
Total liabilities and equity	$ 17,822,384	$ 17,925,891

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Capitalization
Common stock, shares authorized (in shares)	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	1,000,000	1,000,000

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Management's Opinion

3 Months Ended

Mar. 31, 2018

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, 2018 and Dec. 31, 2017; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2018 and 2017; and its cash flows for the three months endedMarch 31, 2018 and 2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2018 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, 2017 balance sheet information has been derived from the audited 2017 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2017. 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, 2017, filed with the SEC on Feb. 26, 2018. 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, 2018

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, 2017, 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, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Leases —In February 2016, the Financial Accounting Standards Board (FASB) issued Leases, Topic 842 (Accounting Standards Update (ASU) No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. NSP-Minnesota has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered into prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. NSP-Minnesota expects that similar agreements entered into after Dec. 31, 2018 will generally qualify as leases under the new standard.

Recently Adopted

Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. NSP-Minnesota implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on NSP-Minnesota’s consolidated financial statements. For related disclosures, see Note 13.

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 eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. NSP-Minnesota implemented the guidance on Jan. 1, 2018. As a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, historically classified as available-for-sale, continue to be deferred to a regulatory asset, and the overall adoption impacts were not material.

Presentation of Net Periodic Benefit Cost —In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment, and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. NSP-Minnesota implemented the new guidance on Jan. 1, 2018, and as a result, $3.4 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for the three months ended March 31, 2017. Under a practical expedient permitted by the standard, NSP-Minnesota used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

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Selected Balance Sheet Data

3 Months Ended

Mar. 31, 2018

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	401,941		$	366,388
Less allowance for bad debts	(21,453		)	(21,278		)
	$	380,488		$	345,110

(Thousands of Dollars)	March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	208,571	$	209,236
Fuel	78,668		94,483
Natural gas	5,252		33,993
	$	292,491	$	337,712

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	17,132,020		$	17,024,925
Natural gas plant	1,383,329			1,370,330
Common and other property	726,591			724,066
Construction work in progress	547,219			530,126
Total property, plant and equipment	19,789,159			19,649,447
Less accumulated depreciation	(7,136,022		)	(7,018,249		)
Nuclear fuel	2,701,050			2,697,412
Less accumulated amortization	(2,325,782		)	(2,294,998		)
	$	13,028,405		$	13,033,612

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Income Taxes

3 Months Ended

Mar. 31, 2018

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, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:

	Three Months ended March 31
		2018		2017
Federal statutory rate		21.0	%	35.0	%
State tax, net of federal tax effect		7.1		5.8
Increases (decreases) in tax from:
Wind production tax credits		(17.0	)	(10.7	)
Regulatory differences - ARAM (a)		(8.7	)	(0.2	)
Regulatory differences - ARAM deferral (b)		8.5		—
Regulatory differences - other utility plant items		0.1		0.1
Other tax credits, net of federal income tax expense		(1.5	)	(1.0	)
Other, net		0.7		0.3
Effective income tax rate		10.2	%	29.3	%

^(a)   The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

^(b) As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

Federal Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	December 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback and in 2015 the IRS forwarded the issue to the Office of Appeals (“Appeals”). In 2017 Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. As of March 31, 2018, the case has been forwarded to the Joint Committee on Taxation.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of March 31, 2018, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is uncertain.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2018, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In 2016, the state of Minnesota began an audit of years 2010 through 2014. As of March 31, 2018, Minnesota had not proposed any material adjustments.

Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	10.6	$	10.2
Unrecognized tax benefit — Temporary tax positions	7.9		7.9
Total unrecognized tax benefit	$	18.5	$	18.1

The unrecognized tax benefit amounts were reduced by the tax benefits associated with 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, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(14.6	)	$	(12.8	)

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 progresses and audit resumes, the Minnesota audit progresses, and other state audits resume. As the IRS Appeals and Minnesota audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $12 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	March 31, 2018			Dec. 31, 2017
Payable for interest related to unrecognized tax benefits at beginning of period	$	(0.9	)	$	(2.0	)
Interest income (expense) related to unrecognized tax benefits recorded during the period	(1.0		)	1.1
Payable for interest related to unrecognized tax benefits at end of period	$	(1.9	)	$	(0.9	)

No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2018 or Dec. 31, 2017.

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Rate Matters

3 Months Ended

Mar. 31, 2018

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, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Tax Reform — Regulatory Proceedings

The Minnesota Public Utility Commission (MPUC) opened a TCJA docket and issued a request for information on the impacts of the TCJA in January 2018. In March 2018, the Minnesota Department of Commerce (DOC) recommended adjusting rates or implementing refunds for the current tax impacts and incorporating the deferred tax impacts in each utility’s next rate case.

In April 2018, NSP-Minnesota filed an update of the estimated impact of the TCJA, which reflected an overall reduction in 2018 revenue requirements of approximately $136 million for electric and $7 million for natural gas. The filing also proposed recommended options for delivering tax reform benefits to customers. The proposed electric options included: customer refunds and rider impacts of $68 million, deferral of $44 million to allow for a rate case stay-out for 2020, acceleration of depreciation for the King coal plant of $22 million and low income program funding of $2 million. The proposed natural gas options included customer refunds and rider impacts of $3 million, with the remaining TCJA benefits deferred to mitigate increased costs in the next natural gas rate case. A MPUC decision is expected later in 2018.

Dockets have also been opened in North Dakota and South Dakota. In February 2018, NSP-Minnesota proposed using the reduced revenue requirements from the TCJA to defer planned future rate filings in both jurisdictions.

Federal Energy Regulatory Commission (FERC) Formula Rates — The FERC has not yet issued guidance on how or when electric utilities should reflect the impacts of the TCJA in FERC jurisdictional wholesale rates. The FERC issued a Notice of Inquiry (NOI) in March 2018 seeking comments on how to reflect TCJA impacts in wholesale rates, in particular changes to accumulated deferred income taxes and bonus depreciation. Comments for the NOI are due in May 2018. However, FERC-approved formula rates for wholesale customers are generally adjusted on an annual basis for certain changes in rate base and actual operating expenses, including income taxes. As a result, these revenues would be subject to an automatic reduction for the effect of the TCJA corporate tax rate change through the annual true-up process, absent specific FERC action.

NSP-Minnesota was a party to a February 2018 FERC filing by certain transmission owner (TO) members of the Midcontinent Independent System Operator, Inc. (MISO) proposing to commence early reductions to transmission formula rates in 2018 for corporate tax rate impacts of the TCJA. In March 2018, the FERC issued orders granting MISO TO waiver requests so that 2018 rates will reflect the lower federal corporate tax rate.

Pending Regulatory Proceedings — MPUC

GUIC Rider — In February 2018, the MPUC approved a 2017 revenue requirement of approximately $20 million for GUIC investments. New rates went into effect in March 2018. In November 2017, NSP-Minnesota filed the 2018 GUIC rider with the MPUC requesting recovery of approximately $28 million from Minnesota gas utility customers. In March 2018, NSP-Minnesota filed a supplement to the 2018 GUIC rider filing to provide an updated capital forecast and address the impact of the TCJA. The net result decreased NSP-Minnesota’s 2018 GUIC revenue requirement to approximately $24 million. The MPUC is currently considering the 2018 petition.

Renewable Energy Standard (RES) Rider — In 2017, NSP-Minnesota filed the 2017 and 2018 RES rider petition with the MPUC, requesting approval of a 2017 over-recovery of approximately $10 million and a 2018 revenue requirement of approximately $11 million. The petition was based on a requested return on equity (ROE) of 10.0 percent and includes costs associated with the Courtenay wind farm and the 1,550 megawatt (MW) wind portfolio, which are offset by production tax credits (PTCs) and proceeds from renewable energy credit (REC) sales. The increase in revenue requirements in 2018 is due to new wind projects entering the construction phase. In February and March 2018, NSP-Minnesota filed supplements to the 2017 and 2018 RES rider petition to provide updated actual results and address TCJA impacts. NSP-Minnesota’s revised 2017 refund is approximately $13 million, and the revised 2018 revenue requirement is approximately $23 million. The increase in 2018 revenue requirements from the original request is primarily driven by the TCJA impact on PTCs earned on existing wind asset-related costs. A decision from the MPUC is expected later in 2018.

Pending Regulatory Proceeding — FERC

MISO ROE Complaints — In November 2013, a group of customers filed a complaint at the FERC against MISO 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, and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership), effective Nov. 12, 2013.

In September 2016, the FERC approved an Administrative Law Judge (ALJ) recommendation that MISO TOs be granted a 10.32 percent base ROE using the methodology adopted by FERC in June 2014 (Opinion 531). This ROE would be applicable for the 15-month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent, including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action.

In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any RTO adder was filed, resulting in a second period of potential refunds from Feb. 12, 2015 to May 11, 2016. In June 2016, an ALJ recommended a base ROE of 9.7 percent, applying the FERC Opinion 531 methodology. Various parties filed exceptions to the ALJ recommendation, and FERC action is pending. In April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint.

NSP-Minnesota has recognized a current refund liability consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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, 2017, 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.

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, 2018 and Dec. 31, 2017, 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 has a stated maximum amount; 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, 2018		Dec. 31, 2017
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 a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017, which involves targeted source removal of impacted soils and historic MGP infrastructure. It is anticipated that remediation activities will be performed in 2018. NSP-Minnesota has also 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 May 31, 2018.

NSP-Minnesota had recorded an estimated liability of $15 million as of March 31, 2018 and $16 million as of Dec. 31, 2017, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately $22 million, of which approximately $7 million has been spent. NSP-Minnesota has deferred Fargo MGP Site costs allocable to the North Dakota jurisdiction, or approximately 88 percent of all remediation costs, as approved by the North Dakota Public Service Commission (NDPSC). In December 2017, NSP-Minnesota filed a request with the MPUC to defer post-2017 MGP remediation expenditures allocable to the Minnesota jurisdiction, including the Fargo MGP site. In March 2018, the DOC recommended that the MPUC deny NSP-Minnesota’s deferral request. A MPUC decision is expected mid-2018.

Other MGP, Landfill or Disposal Sites — NSP-Minnesota is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. NSP-Minnesota has identified seven sites, in addition to the site in Fargo, N.D., where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities. NSP-Minnesota anticipates that these investigation or remediation activities will continue through at least 2018. NSP-Minnesota had accrued $3 million as of March 31, 2018 and Dec. 31, 2017 for all of these sites. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. Xcel Energy anticipates that any amounts spent will be fully recovered from customers.

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, 2018

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, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			85
Average amount outstanding	14			25
Maximum amount outstanding	99			142
Weighted average interest rate, computed on a daily basis	1.59		%	1.14		%
Weighted average interest rate at period end	N/A			1.18

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	500		$	500
Amount outstanding at period end	—			20
Average amount outstanding	83			62
Maximum amount outstanding	195			237
Weighted average interest rate, computed on a daily basis	1.73		%	1.10		%
Weighted average interest rate at period end	N/A			1.93

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, 2018 and Dec. 31, 2017, there were $25 million and $24 million, respectively, 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 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, 2018, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	25	$	475

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

^(b)  Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at March 31, 2018 and Dec. 31, 2017.

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Fair Value of Financial Assets and Liabilities

3 Months Ended

Mar. 31, 2018

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 net asset value (NAV).

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take 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 may be redeemed for NAV 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 classification. 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. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. 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 the cleared prices for each FTR for the most recent auction.

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 transparency in the auction process, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements 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, the limited transparency associated with the valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

The Nuclear Regulatory Commission 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 decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments. 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 impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $543 million and $560 million as of March 31, 2018 and Dec. 31, 2017, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $18 million and $7 million as of March 31, 2018 and Dec. 31, 2017, 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 as of March 31, 2018 and Dec. 31, 2017:

	March 31, 2018
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	41,250	$	41,250	$	—	$	—	$	—	$	41,250
Commingled funds:
Non U.S. equities	270,384		226,127		—		—		90,369		316,496
Emerging market debt funds	157,087		—		—		—		163,868		163,868
Private equity investments	141,991		—		—		—		198,060		198,060
Real estate	118,189		—		—		—		185,851		185,851
Other commingled funds	3,902		900		—		—		2,975		3,875
Debt securities:
Government securities	78,197		—		77,505		—		—		77,505
U.S. corporate bonds	325,042		—		320,812		—		—		320,812
Non U.S. corporate bonds	54,637		—		53,151		—		—		53,151
Equity securities:
U.S. equities	277,853		556,816		—		—		—		556,816
Non U.S. equities	152,670		228,903		—		—		—		228,903
Total	$	1,621,202	$	1,053,996	$	451,468	$	—	$	641,123	$	2,146,587

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.

^(b)  Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

	Dec. 31, 2017
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	28,741	$	28,741	$	—	$	—	$	—	$	28,741
Commingled funds:
Non U.S. equities	263,694		216,551		—		—		89,857		306,408
Emerging market debt funds	156,057		—		—		—		166,375		166,375
Private equity investments	141,413		—		—		—		198,037		198,037
Real estate	130,787		—		—		—		201,842		201,842
Other commingled funds	9,340		6,286		—		—		2,975		9,261
Debt securities:
Government securities	67,760		—		69,413		—		—		69,413
U.S. corporate bonds	319,809		—		322,129		—		—		322,129
Non U.S. corporate bonds	50,121		—		50,102		—		—		50,102
Equity securities:
U.S. equities	271,166		556,974		—		—		—		556,974
Non U.S. equities	151,961		233,999		—		—		—		233,999
Total	$	1,590,849	$	1,042,551	$	441,644	$	—	$	659,086	$	2,143,281

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49 million of rabbi trust assets and miscellaneous investments.

^(b)  Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

For the three months ended March 31, 2018 and 2017 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, as of March 31, 2018:

	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	$	—	$	9,124	$	2,318	$	66,063	$	77,505
U.S. corporate bonds	2,886		87,565		173,634		56,727		320,812
Non U.S. corporate bonds	—		16,263		33,328		3,560		53,151
Debt securities	$	2,886	$	112,952	$	209,280	$	126,350	$	451,468

Rabbi Trusts

In 2016, NSP-Minnesota established a rabbi trust to provide partial funding for future deferred compensation plan distributions. The following tables present the cost and fair value of the assets held in rabbi trust at March 31, 2018 and Dec. 31, 2017:

	March 31, 2018
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trust (a)
Cash equivalents	$	393	$	393	$	—	$	—	$	393
Mutual funds	10,373		11,151		—		—		11,151
Total	$	10,766	$	11,544	$	—	$	—	$	11,544

	Dec. 31, 2017
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	783	$	783	$	—	$	—	$	783
Mutual funds	10,332		11,283		—		—		11,283
Total	$	11,115	$	12,066	$	—	$	—	$	12,066

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

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, 2018, 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 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, energy-related instruments and natural gas related instruments, including derivatives. 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, 2018, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. NSP-Minnesota enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be 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, 2018 and 2017.

At March 31, 2018, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net gains 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, 2018 and Dec. 31, 2017:

(Amounts in Thousands)(a)(b)	March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	32,451	41,711
Million British thermal units of natural gas	18,330	23,829
Gallons of vehicle fuel	180	240

^(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, 2018 and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended March 31, 2018
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (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	$	—	$	—		$	261		(a)	$	—			$	—
Vehicle fuel and other commodity	7		—			(29		)	(b)	—				—
Total	$	7	$	—		$	232			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	2,740		(c)
Electric commodity	—		(4,259		)	—				2,169			(d)	—
Natural gas commodity	—		848			—				(520		)	(e)	(404		)	(e)
Total	$	—	$	(3,411	)	$	—			$	1,649			$	2,336

	Three Months Ended March 31, 2017
	Pre-Tax Fair Value (Losses) Recognized During the Period in:					Pre-Tax (Gains) 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	$	—	$	—		$	342	(a)	$	—			$	—
Total	$	—	$	—		$	342		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	622		(c)
Electric commodity	—		(1,247		)	—			(2,788		)	(d)	—
Natural gas commodity	—		(665		)	—			698			(e)	(945		)	(e)
Total	$	—	$	(1,912	)	$	—		$	(2,090	)		$	(323	)

^(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, 2018 and 2017. 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 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 activities. At March 31, 2018, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $45.1 million or 58 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Two of the 10 most significant counterparties, comprising $15.8 million or 20 percent of this credit exposure, were not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. All ten of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those 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’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. At March 31, 2018 and Dec. 31, 2017, there were no derivative instruments in a material liability position with such underlying contract provisions.

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, 2018 and Dec. 31, 2017.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2018:

	March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	85	$	—	$	85	$	—		$	85
Other derivative instruments:
Commodity trading	598		14,123		205		14,926		(6,931		)	7,995
Electric commodity	—		—		5,765		5,765		(33		)	5,732
Total current derivative assets	$	598	$	14,208	$	5,970	$	20,776	$	(6,964	)	13,812
PPAs (a)												752
Current derivative instruments												$	14,564
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	602		35,308		8,048		43,958		(14,170		)	29,788
Total noncurrent derivative assets	$	602	$	35,308	$	8,048	$	43,958	$	(14,170	)	29,788
PPAs (a)												114
Noncurrent derivative instruments												$	29,902

	March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	647	$	11,643	$	—	$	12,290	$	(7,351	)	$	4,939
Electric commodity	—		—		34		34		(34		)	—
Total current derivative liabilities	$	647	$	11,643	$	34	$	12,324	$	(7,385	)	4,939
PPAs (a)												14,106
Current derivative instruments												$	19,045
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1,868	$	27,604	$	468	$	29,940	$	(17,698	)	$	12,242
Total noncurrent derivative liabilities	$	1,868	$	27,604	$	468	$	29,940	$	(17,698	)	12,242
PPAs (a)												86,450
Noncurrent derivative instruments												$	98,692

^(a)  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, 2018. At March 31, 2018, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.9 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, 2017:

	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	107	$	—	$	107	$	—		$	107
Other derivative instruments:
Commodity trading	$	1,691	$	17,144	$	142	$	18,977	$	(11,744	)	$	7,233
Electric commodity	—		—		17,581		17,581		(425		)	17,156
Natural gas commodity	—		77		—		77		—			77
Total current derivative assets	$	1,691	$	17,328	$	17,723	$	36,742	$	(12,169	)	24,573
PPAs (a)												657
Current derivative instruments												$	25,230
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	29,121	$	5,363	$	34,484	$	(6,502	)	$	27,982
Total noncurrent derivative assets	$	—	$	29,121	$	5,363	$	34,484	$	(6,502	)	27,982
PPAs (a)												120
Noncurrent derivative instruments												$	28,102

	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1,713	$	13,853	$	—	$	15,566	$	(11,974	)	$	3,592
Electric commodity	—		—		425		425		(425		)	—
Total current derivative liabilities	$	1,713	$	13,853	$	425	$	15,991	$	(12,399	)	3,592
PPAs (a)												14,105
Current derivative instruments												$	17,697
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	22,163	$	—	$	22,163	$	(9,334	)	$	12,829
Total noncurrent derivative liabilities	$	—	$	22,163	$	—	$	22,163	$	(9,334	)	12,829
PPAs (a)												89,913
Noncurrent derivative instruments												$	102,742

^(a)  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, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.1 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, 2018 and 2017:

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Balance at Jan. 1	$	22,661		$	15,320
Purchases	2			280
Settlements	(1,934		)	(3,426		)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)	2,280			(792		)
Net losses recognized as regulatory assets and liabilities	(9,493		)	(6,739		)
Balance at March 31	$	13,516		$	4,643

^(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, 2018 and 2017.

Fair Value of Long-Term Debt

As of March 31, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,934,024	$	5,352,133	$	4,933,018	$	5,601,919

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, 2018 and Dec. 31, 2017, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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Other (Expense) Income, Net

3 Months Ended

Mar. 31, 2018

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

Other Income (Expense), Net

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

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Interest income	$	2,935		$	2,709
Insurance policy income (expense)	342			(855		)
Other nonoperating income	1			10
Benefits non-service cost	(3,062		)	(3,398		)
Other income (expense), net	$	216		$	(1,534	)

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Segment Information

3 Months Ended

Mar. 31, 2018

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, 2018
Operating revenues (a)(b)	$	1,062,263	$	241,432	$	7,056	$	—		$	1,310,751
Intersegment revenues	165		144		—		(309		)	—
Total revenues	$	1,062,428	$	241,576	$	7,056	$	(309	)	$	1,310,751
Net income	$	85,722	$	25,445	$	573	$	—		$	111,740

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2017
Operating revenues (a)(b)	$	1,079,030	$	221,183	$	6,927		$	—		$	1,307,140
Intersegment revenues	109		94		—			(203		)	—
Total revenues	$	1,079,139	$	221,277	$	6,927		$	(203	)	$	1,307,140
Net income	$	78,082	$	17,505	$	(1,421	)	$	—		$	94,166

^(a)  Operating revenues include $117 million and $124 million of affiliate electric revenue for the three months ended March 31, 2018 and 2017.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 2018 and 2017.

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Benefit Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,982		$	6,958		$	43		$	36
Interest cost (a)	8,804			10,177			769			854
Expected return on plan assets (a)	(14,541		)	(15,017		)	(96		)	(54		)
Amortization of prior service cost (credit) (a)	(29		)	265			(759		)	(759		)
Amortization of net loss (a)	9,615			9,902			595			507
Net periodic benefit cost	10,831			12,285			552			584
Costs not recognized due to the effects of regulation	(2,763		)	(4,899		)				—
Net benefit cost recognized for financial reporting	$	8,068		$	7,386		$	552		$	584

^(a) The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the income statement or capitalized on the balance sheet as a regulatory asset.

In January 2018, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $63.0 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2018.

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Other Comprehensive Income

3 Months Ended

Mar. 31, 2018

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2018 and 2017 were as follows:

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(20,895	)	$	128		$	(3,770	)	$	(24,537	)
Other comprehensive income before reclassifications	5			—			—			5
Losses reclassified from net accumulated other comprehensive loss	167			(128		)	53			92
Net current period other comprehensive income	172			(128		)	53			97
Accumulated other comprehensive loss at March 31	$	(20,723	)	$	—		$	(3,717	)	$	(24,440	)

	Three Months Ended March 31, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(18,208	)	$	105	$	(2,680	)	$	(20,783	)
Losses reclassified from net accumulated other comprehensive loss	203			—		35			238
Net current period other comprehensive income	203			—		35			238
Accumulated other comprehensive loss at March 31	$	(18,005	)	$	105	$	(2,645	)	$	(20,545	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2018 and 2017 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	261		(a)	$	342		(a)
Vehicle fuel derivatives	(29		)	(b)	—			(b)
Total, pre-tax	232				342
Tax benefit	(65		)		(139		)
Total, net of tax	167				203
Defined benefit pension and postretirement losses:
Amortization of net loss	125			(c)	109			(c)
Prior service credit	(49		)	(c)	(49		)	(c)
Total, pre-tax	76				60
Tax benefit	(23		)		(25		)
Total, net of tax	53				35
Marketable securities:
Realization of gains	(179		)		—
Total, pre-tax	(179		)		—
Tax expense	51				—
Total, net of tax	(128		)		—
Total amounts reclassified, net of tax	$	92			$	238

^(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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Revenues

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenues

Revenues

NSP-Minnesota principally generates revenue from the transmission, distribution and sale of electricity and the transportation, distribution and sale of natural gas to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such NSP-Minnesota does not recognize a separate financing component of its collections from customers. NSP-Minnesota presents its revenues net of any excise or other fiduciary-type taxes or fees.

NSP-Minnesota participates in MISO. NSP-Minnesota recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

NSP-Minnesota has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.

When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.

In the following tables, revenue is classified by the type of goods/services rendered and market/customer type. The tables also reconcile revenue to the reportable segments.

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	311,129	$	131,659	$	6,323	$	449,111
Commercial and industrial (C&I)	468,023		96,908		43		564,974
Other	9,719		—		690		10,409
Total retail	788,871		228,567		7,056		1,024,494
Wholesale	46,365		—		—		46,365
Transmission	54,798		—		—		54,798
Interchange	116,972		—		—		116,972
Other	11,545		2,211		—		13,756
Total revenue from contracts with customers	1,018,551		230,778		7,056		1,256,385
Alternative revenue and other	43,712		10,654		—		54,366
Total revenues	$	1,062,263	$	241,432	$	7,056	$	1,310,751

	Three Months Ended March 31, 2017
(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	304,413	$	121,413	$	6,210	$	432,036
C&I	485,103		88,491		38		573,632
Other	8,203		—		679		8,882
Total retail	797,719		209,904		6,927		1,014,550
Wholesale	45,919		—		—		45,919
Transmission	53,959		—		—		53,959
Interchange	123,689		—		—		123,689
Other	5,963		1,245		—		7,208
Total revenue from contracts with customers	1,027,249		211,149		6,927		1,245,325
Alternative revenue and other	51,781		10,034		—		61,815
Total revenues	$	1,079,030	$	221,183	$	6,927	$	1,307,140

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Selected Balance Sheet Data (Tables)

3 Months Ended

Mar. 31, 2018

Balance Sheet Related Disclosures [Abstract]

Accounts receivable, net

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	401,941		$	366,388
Less allowance for bad debts	(21,453		)	(21,278		)
	$	380,488		$	345,110

Inventories

(Thousands of Dollars)	March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	208,571	$	209,236
Fuel	78,668		94,483
Natural gas	5,252		33,993
	$	292,491	$	337,712

Property, plant and equipment, net

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	17,132,020		$	17,024,925
Natural gas plant	1,383,329			1,370,330
Common and other property	726,591			724,066
Construction work in progress	547,219			530,126
Total property, plant and equipment	19,789,159			19,649,447
Less accumulated depreciation	(7,136,022		)	(7,018,249		)
Nuclear fuel	2,701,050			2,697,412
Less accumulated amortization	(2,325,782		)	(2,294,998		)
	$	13,028,405		$	13,033,612

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:

	Three Months ended March 31
		2018		2017
Federal statutory rate		21.0	%	35.0	%
State tax, net of federal tax effect		7.1		5.8
Increases (decreases) in tax from:
Wind production tax credits		(17.0	)	(10.7	)
Regulatory differences - ARAM (a)		(8.7	)	(0.2	)
Regulatory differences - ARAM deferral (b)		8.5		—
Regulatory differences - other utility plant items		0.1		0.1
Other tax credits, net of federal income tax expense		(1.5	)	(1.0	)
Other, net		0.7		0.3
Effective income tax rate		10.2	%	29.3	%

^(a)   The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

^(b) As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block]

NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	December 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	March 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	10.6	$	10.2
Unrecognized tax benefit — Temporary tax positions	7.9		7.9
Total unrecognized tax benefit	$	18.5	$	18.1

Tax Benefits Associated with NOL and Tax Credit Carryforwards

The unrecognized tax benefit amounts were reduced by the tax benefits associated with 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, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(14.6	)	$	(12.8	)

Interest Payable related to Unrecognized Tax Benefits [Table Text Block]

(Millions of Dollars)	March 31, 2018			Dec. 31, 2017
Payable for interest related to unrecognized tax benefits at beginning of period	$	(0.9	)	$	(2.0	)
Interest income (expense) related to unrecognized tax benefits recorded during the period	(1.0		)	1.1
Payable for interest related to unrecognized tax benefits at end of period	$	(1.9	)	$	(0.9	)

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Commitments and Contingencies Schedule of Guarantor Obligations (Tables)

3 Months Ended

Mar. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations [Table Text Block]

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

(Millions of Dollars)	March 31, 2018		Dec. 31, 2017
Guarantee issued and outstanding	$	4.8	$	4.8

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Borrowings and Other Financing Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At March 31, 2018, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	500	$	25	$	475

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

^(b)  Includes outstanding letters of credit.

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			85
Average amount outstanding	14			25
Maximum amount outstanding	99			142
Weighted average interest rate, computed on a daily basis	1.59		%	1.14		%
Weighted average interest rate at period end	N/A			1.18

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, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	500		$	500
Amount outstanding at period end	—			20
Average amount outstanding	83			62
Maximum amount outstanding	195			237
Weighted average interest rate, computed on a daily basis	1.73		%	1.10		%
Weighted average interest rate at period end	N/A			1.93

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Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

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 as of March 31, 2018 and Dec. 31, 2017:

	March 31, 2018
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	41,250	$	41,250	$	—	$	—	$	—	$	41,250
Commingled funds:
Non U.S. equities	270,384		226,127		—		—		90,369		316,496
Emerging market debt funds	157,087		—		—		—		163,868		163,868
Private equity investments	141,991		—		—		—		198,060		198,060
Real estate	118,189		—		—		—		185,851		185,851
Other commingled funds	3,902		900		—		—		2,975		3,875
Debt securities:
Government securities	78,197		—		77,505		—		—		77,505
U.S. corporate bonds	325,042		—		320,812		—		—		320,812
Non U.S. corporate bonds	54,637		—		53,151		—		—		53,151
Equity securities:
U.S. equities	277,853		556,816		—		—		—		556,816
Non U.S. equities	152,670		228,903		—		—		—		228,903
Total	$	1,621,202	$	1,053,996	$	451,468	$	—	$	641,123	$	2,146,587

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.

^(b)  Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

	Dec. 31, 2017
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV (b)		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	28,741	$	28,741	$	—	$	—	$	—	$	28,741
Commingled funds:
Non U.S. equities	263,694		216,551		—		—		89,857		306,408
Emerging market debt funds	156,057		—		—		—		166,375		166,375
Private equity investments	141,413		—		—		—		198,037		198,037
Real estate	130,787		—		—		—		201,842		201,842
Other commingled funds	9,340		6,286		—		—		2,975		9,261
Debt securities:
Government securities	67,760		—		69,413		—		—		69,413
U.S. corporate bonds	319,809		—		322,129		—		—		322,129
Non U.S. corporate bonds	50,121		—		50,102		—		—		50,102
Equity securities:
U.S. equities	271,166		556,974		—		—		—		556,974
Non U.S. equities	151,961		233,999		—		—		—		233,999
Total	$	1,590,849	$	1,042,551	$	441,644	$	—	$	659,086	$	2,143,281

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49 million of rabbi trust assets and miscellaneous investments.

^(b)  Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

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, as of March 31, 2018:

	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	$	—	$	9,124	$	2,318	$	66,063	$	77,505
U.S. corporate bonds	2,886		87,565		173,634		56,727		320,812
Non U.S. corporate bonds	—		16,263		33,328		3,560		53,151
Debt securities	$	2,886	$	112,952	$	209,280	$	126,350	$	451,468

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

In 2016, NSP-Minnesota established a rabbi trust to provide partial funding for future deferred compensation plan distributions. The following tables present the cost and fair value of the assets held in rabbi trust at March 31, 2018 and Dec. 31, 2017:

	March 31, 2018
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trust (a)
Cash equivalents	$	393	$	393	$	—	$	—	$	393
Mutual funds	10,373		11,151		—		—		11,151
Total	$	10,766	$	11,544	$	—	$	—	$	11,544

	Dec. 31, 2017
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	783	$	783	$	—	$	—	$	783
Mutual funds	10,332		11,283		—		—		11,283
Total	$	11,115	$	12,066	$	—	$	—	$	12,066

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

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, 2018 and Dec. 31, 2017:

(Amounts in Thousands)(a)(b)	March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	32,451	41,711
Million British thermal units of natural gas	18,330	23,829
Gallons of vehicle fuel	180	240

^(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, 2018 and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended March 31, 2018
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (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	$	—	$	—		$	261		(a)	$	—			$	—
Vehicle fuel and other commodity	7		—			(29		)	(b)	—				—
Total	$	7	$	—		$	232			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	2,740		(c)
Electric commodity	—		(4,259		)	—				2,169			(d)	—
Natural gas commodity	—		848			—				(520		)	(e)	(404		)	(e)
Total	$	—	$	(3,411	)	$	—			$	1,649			$	2,336

	Three Months Ended March 31, 2017
	Pre-Tax Fair Value (Losses) Recognized During the Period in:					Pre-Tax (Gains) 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	$	—	$	—		$	342	(a)	$	—			$	—
Total	$	—	$	—		$	342		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	622		(c)
Electric commodity	—		(1,247		)	—			(2,788		)	(d)	—
Natural gas commodity	—		(665		)	—			698			(e)	(945		)	(e)
Total	$	—	$	(1,912	)	$	—		$	(2,090	)		$	(323	)

^(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 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 March 31, 2018:

	March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	85	$	—	$	85	$	—		$	85
Other derivative instruments:
Commodity trading	598		14,123		205		14,926		(6,931		)	7,995
Electric commodity	—		—		5,765		5,765		(33		)	5,732
Total current derivative assets	$	598	$	14,208	$	5,970	$	20,776	$	(6,964	)	13,812
PPAs (a)												752
Current derivative instruments												$	14,564
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	602		35,308		8,048		43,958		(14,170		)	29,788
Total noncurrent derivative assets	$	602	$	35,308	$	8,048	$	43,958	$	(14,170	)	29,788
PPAs (a)												114
Noncurrent derivative instruments												$	29,902

	March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	647	$	11,643	$	—	$	12,290	$	(7,351	)	$	4,939
Electric commodity	—		—		34		34		(34		)	—
Total current derivative liabilities	$	647	$	11,643	$	34	$	12,324	$	(7,385	)	4,939
PPAs (a)												14,106
Current derivative instruments												$	19,045
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1,868	$	27,604	$	468	$	29,940	$	(17,698	)	$	12,242
Total noncurrent derivative liabilities	$	1,868	$	27,604	$	468	$	29,940	$	(17,698	)	12,242
PPAs (a)												86,450
Noncurrent derivative instruments												$	98,692

^(a)  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, 2018. At March 31, 2018, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.9 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, 2017:

	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	107	$	—	$	107	$	—		$	107
Other derivative instruments:
Commodity trading	$	1,691	$	17,144	$	142	$	18,977	$	(11,744	)	$	7,233
Electric commodity	—		—		17,581		17,581		(425		)	17,156
Natural gas commodity	—		77		—		77		—			77
Total current derivative assets	$	1,691	$	17,328	$	17,723	$	36,742	$	(12,169	)	24,573
PPAs (a)												657
Current derivative instruments												$	25,230
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	29,121	$	5,363	$	34,484	$	(6,502	)	$	27,982
Total noncurrent derivative assets	$	—	$	29,121	$	5,363	$	34,484	$	(6,502	)	27,982
PPAs (a)												120
Noncurrent derivative instruments												$	28,102

	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1,713	$	13,853	$	—	$	15,566	$	(11,974	)	$	3,592
Electric commodity	—		—		425		425		(425		)	—
Total current derivative liabilities	$	1,713	$	13,853	$	425	$	15,991	$	(12,399	)	3,592
PPAs (a)												14,105
Current derivative instruments												$	17,697
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	22,163	$	—	$	22,163	$	(9,334	)	$	12,829
Total noncurrent derivative liabilities	$	—	$	22,163	$	—	$	22,163	$	(9,334	)	12,829
PPAs (a)												89,913
Noncurrent derivative instruments												$	102,742

^(a)  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, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.1 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, 2018 and 2017:

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Balance at Jan. 1	$	22,661		$	15,320
Purchases	2			280
Settlements	(1,934		)	(3,426		)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)	2,280			(792		)
Net losses recognized as regulatory assets and liabilities	(9,493		)	(6,739		)
Balance at March 31	$	13,516		$	4,643

^(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, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,934,024	$	5,352,133	$	4,933,018	$	5,601,919

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Other (Expense) Income, Net (Tables)

3 Months Ended

Mar. 31, 2018

Other Income and Expenses [Abstract]

Other (Expense) Income, Net

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

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Interest income	$	2,935		$	2,709
Insurance policy income (expense)	342			(855		)
Other nonoperating income	1			10
Benefits non-service cost	(3,062		)	(3,398		)
Other income (expense), net	$	216		$	(1,534	)

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2018

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, 2018
Operating revenues (a)(b)	$	1,062,263	$	241,432	$	7,056	$	—		$	1,310,751
Intersegment revenues	165		144		—		(309		)	—
Total revenues	$	1,062,428	$	241,576	$	7,056	$	(309	)	$	1,310,751
Net income	$	85,722	$	25,445	$	573	$	—		$	111,740

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2017
Operating revenues (a)(b)	$	1,079,030	$	221,183	$	6,927		$	—		$	1,307,140
Intersegment revenues	109		94		—			(203		)	—
Total revenues	$	1,079,139	$	221,277	$	6,927		$	(203	)	$	1,307,140
Net income	$	78,082	$	17,505	$	(1,421	)	$	—		$	94,166

^(a)  Operating revenues include $117 million and $124 million of affiliate electric revenue for the three months ended March 31, 2018 and 2017.

^(b)  Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 2018 and 2017.

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Benefit Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,982		$	6,958		$	43		$	36
Interest cost (a)	8,804			10,177			769			854
Expected return on plan assets (a)	(14,541		)	(15,017		)	(96		)	(54		)
Amortization of prior service cost (credit) (a)	(29		)	265			(759		)	(759		)
Amortization of net loss (a)	9,615			9,902			595			507
Net periodic benefit cost	10,831			12,285			552			584
Costs not recognized due to the effects of regulation	(2,763		)	(4,899		)				—
Net benefit cost recognized for financial reporting	$	8,068		$	7,386		$	552		$	584

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2018

Stockholders' Equity Note [Abstract]

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

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2018 and 2017 were as follows:

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(20,895	)	$	128		$	(3,770	)	$	(24,537	)
Other comprehensive income before reclassifications	5			—			—			5
Losses reclassified from net accumulated other comprehensive loss	167			(128		)	53			92
Net current period other comprehensive income	172			(128		)	53			97
Accumulated other comprehensive loss at March 31	$	(20,723	)	$	—		$	(3,717	)	$	(24,440	)

	Three Months Ended March 31, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(18,208	)	$	105	$	(2,680	)	$	(20,783	)
Losses reclassified from net accumulated other comprehensive loss	203			—		35			238
Net current period other comprehensive income	203			—		35			238
Accumulated other comprehensive loss at March 31	$	(18,005	)	$	105	$	(2,645	)	$	(20,545	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2018 and 2017 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	261		(a)	$	342		(a)
Vehicle fuel derivatives	(29		)	(b)	—			(b)
Total, pre-tax	232				342
Tax benefit	(65		)		(139		)
Total, net of tax	167				203
Defined benefit pension and postretirement losses:
Amortization of net loss	125			(c)	109			(c)
Prior service credit	(49		)	(c)	(49		)	(c)
Total, pre-tax	76				60
Tax benefit	(23		)		(25		)
Total, net of tax	53				35
Marketable securities:
Realization of gains	(179		)		—
Total, pre-tax	(179		)		—
Tax expense	51				—
Total, net of tax	(128		)		—
Total amounts reclassified, net of tax	$	92			$	238

^(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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Revenues Revenues (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	311,129	$	131,659	$	6,323	$	449,111
Commercial and industrial (C&I)	468,023		96,908		43		564,974
Other	9,719		—		690		10,409
Total retail	788,871		228,567		7,056		1,024,494
Wholesale	46,365		—		—		46,365
Transmission	54,798		—		—		54,798
Interchange	116,972		—		—		116,972
Other	11,545		2,211		—		13,756
Total revenue from contracts with customers	1,018,551		230,778		7,056		1,256,385
Alternative revenue and other	43,712		10,654		—		54,366
Total revenues	$	1,062,263	$	241,432	$	7,056	$	1,310,751

	Three Months Ended March 31, 2017
(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	304,413	$	121,413	$	6,210	$	432,036
C&I	485,103		88,491		38		573,632
Other	8,203		—		679		8,882
Total retail	797,719		209,904		6,927		1,014,550
Wholesale	45,919		—		—		45,919
Transmission	53,959		—		—		53,959
Interchange	123,689		—		—		123,689
Other	5,963		1,245		—		7,208
Total revenue from contracts with customers	1,027,249		211,149		6,927		1,245,325
Alternative revenue and other	51,781		10,034		—		61,815
Total revenues	$	1,079,030	$	221,183	$	6,927	$	1,307,140

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Accounting Pronouncements (Details) - Accounting Standards Update 2017-07 $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Operating and Maintenance Expense
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net benefit cost recognized for financial reporting	$ (3.4)
Other Income
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net benefit cost recognized for financial reporting	$ 3.4

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Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$ 401,941	$ 366,388
Less allowance for bad debts	(21,453)	(21,278)
Accounts receivable, net	$ 380,488	$ 345,110

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Selected Balance Sheet Data, Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Public Utilities, Inventory [Line Items]
Inventories	$ 292,491	$ 337,712
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	208,571	209,236
Fuel
Public Utilities, Inventory [Line Items]
Inventories	78,668	94,483
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 5,252	$ 33,993

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Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 19,789,159	$ 19,649,447
Less accumulated depreciation	(7,136,022)	(7,018,249)
Property, plant and equipment, net	13,028,405	13,033,612
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	17,132,020	17,024,925
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,383,329	1,370,330
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	726,591	724,066
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	547,219	530,126
Nuclear fuel
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,701,050	2,697,412
Less accumulated depreciation	$ (2,325,782)	$ (2,294,998)

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Income Taxes (Details) - USD ($)	3 Months Ended			9 Months Ended	12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017		Sep. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2012
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	$ (1,900,000)				$ (900,000)	$ (2,000,000)
Interest Expense related to unrecognized tax benefits	$ (1,000,000)				1,100,000
Tax Audits [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	7.10%	5.80%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	(17.00%)	(10.70%)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	(8.70%)	(0.20%)	[1]
Effective Income Tax Rate Reconciliation, Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Percent	8.50%	0.00%	[2]
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent	0.10%	0.10%
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items	(1.50%)	(1.00%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent	0.70%	0.30%
Effective Income Tax Rate Reconciliation, Percent	10.20%	29.30%
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions	$ 10,600,000				10,200,000
Unrecognized tax benefit — Temporary tax positions	7,900,000				7,900,000
Total unrecognized tax benefit	18,500,000				18,100,000
NOL and tax credit carryforwards	(14,600,000)				(12,800,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	12,000,000
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
State Jurisdiction (Minnesota)
Tax Audits [Abstract]
Year(s) under examination						2010 through 2014
Earliest year subject to examination	2009

[1] The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

[2] As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

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Rate Matters (Details) - NSP-Minnesota $ in Millions	1 Months Ended								2 Months Ended	3 Months Ended	12 Months Ended
	Apr. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Feb. 28, 2018 USD ($)	Nov. 30, 2017 USD ($)	Sep. 30, 2016	Jun. 30, 2016	Feb. 28, 2015	Nov. 30, 2013	Mar. 31, 2018 USD ($)	Mar. 31, 2018	Dec. 31, 2017 USD ($) MW
FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates							12.38%	12.38%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties							8.67%	9.15%
Minnesota Public Utilities Commission | Gas Utility Infrastructure Cost Rider 2017 [Member]
Rate Matters [Abstract]
Public Utilities, Approved Rider Revenue, Amount			$ 20
Minnesota Public Utilities Commission | Gas Utility Infrastructure Cost Rider 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rider Revenue, Amount				$ 28
Public Utilities, Revised Requested Rider Revenue		$ 24
Minnesota Public Utilities Commission | MPUC Proceeding - 2017 and 2018 Renewable Energy Standard Rider - 2017 Rates [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rider Revenue, Amount											$ (10)
Public Utilities, Revised Requested Rider Revenue									$ (13)
Minnesota Public Utilities Commission | MPUC Proceeding - 2017 and 2018 Renewable Energy Standard Rider - 2018 Rates [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rider Revenue, Amount											$ 11
Public Utilities, Revised Requested Rider Revenue									$ 23
Minnesota Public Utilities Commission | MPUC Proceeding - 2017 and 2018 Renewable Energy Standard Rider [Member]
Rate Matters [Abstract]
Public Utilities, Requested Return on Equity, Percentage											10.00%
Public Utilities, Facility Generating Capacity | MW											1,550
Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved					10.32%
Public Utilities, Length of Refund Period, In Months					15 months
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved										10.82%
Public Utilities, ROE Basis Point Adder, Approved										50
Administrative Law Judge | FERC Proceeding, MISO ROE Complaint
Rate Matters [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties						9.70%
Subsequent Event [Member] | Minnesota Public Utilities Commission | MPUC Proceeding - Tax Cuts and Jobs Act of 2017 [Member]
Rate Matters [Abstract]
Tax Cuts and Jobs Act of 2017, Estimated 2018 Electric Rate Reduction	$ 136
Tax Cuts and Jobs Act of 2017, Estimated 2018 Natural Gas Rate Reduction	7
Tax Cuts and Jobs Act of 2017, Proposed 2018 Electric Refund of TCJA Benefits	68
Tax Cuts and Jobs Act of 2017, Proposed Electric Deferral of TCJA Benefits	44
Tax Cuts and Jobs Act of 2017, Proposed Amount of Accelerated Depreciation	22
Tax Cuts and Jobs Act of 2017, Proposed Low Income Program Funding from TCJA Benefits	2
Tax Cuts and Jobs Act of 2017, Proposed 2018 Natural Gas Refund of TCJA Benefits	$ 3

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Commitments and Contingencies, Purchased Power Agreements (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($) MW
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity under long term purchased power agreements (in MW) | MW	1,069	1,069
Purchase Power Agreement Expiration (year)	2028
Payment or Performance Guarantee
Purchased Power Agreements [Abstract]
Lease Guarantee Expiration (year)	2019
Other MGP Sites [Member]
Purchased Power Agreements [Abstract]
Accrual for Environmental Loss Contingencies, Gross | $	$ 3	$ 3

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Commitments and Contingencies Commitments and Contingencies, Guarantees and Indemnifications (Details) - Payment or Performance Guarantee - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Guarantor Obligations [Line Items]
Lease Guarantee Expiration (year)	2019
Guarantees issued and outstanding	$ 4.8	$ 4.8

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Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Fargo MGP Site
Environmental Requirements [Abstract]
Accrual for Environmental Loss Contingencies, Gross	$ 15	$ 16
Current Cost Estimate for Site Remediation	22
Estimated amount spent on cleanup	$ 7
Percentage of Response Costs Allocable to the Minnesota Jurisdiction	88.00%
Other MGP Sites [Member]
Environmental Requirements [Abstract]
Accrual for Environmental Loss Contingencies, Gross	$ 3	$ 3
Number of identified MGP sites under current investigation and/or remediation in addition to those separately disclosed	7

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 20,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000,000	250,000,000
Amount outstanding at period end	0	85,000,000
Average amount outstanding	14,000,000	25,000,000
Maximum amount outstanding	$ 99,000,000	$ 142,000,000
Weighted average interest rate, computed on a daily basis (percentage)	1.59%	1.14%
Weighted average interest rate at period end (percentage)		1.18%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 500,000,000	$ 500,000,000
Amount outstanding at period end	0	20,000,000
Average amount outstanding	83,000,000	62,000,000
Maximum amount outstanding	$ 195,000,000	$ 237,000,000
Weighted average interest rate, computed on a daily basis (percentage)	1.73%	1.10%
Weighted average interest rate at period end (percentage)		1.93%

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 20,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 25,000	$ 24,000
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) - Credit Facility - USD ($)		3 Months Ended
		Mar. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Credit Facility	[1]	$ 500,000,000
Drawn	[2]	25,000,000
Available		$ 475,000,000
Maturity Date		Jun. 30, 2021
Direct advances on the credit facility outstanding		$ 0	$ 0

[1] This credit facility expires in June 2021.

[2] Includes outstanding letters of credit.

XML

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities (Details)	3 Months Ended
	Mar. 31, 2018
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, 2018		Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain on Securities	$ 543,000		$ 560,000
Unrealized Loss on Securities	18,000		7,000
Investments [Abstract]
Miscellaneous investments	52,000		49,000
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	41,250	[1]	28,741	[2]
Investments [Abstract]
Equity Securities	1,621,202	[1]	1,590,849	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities
Investments [Abstract]
Equity Securities	270,384	[1]	263,694	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Emerging market debt funds
Investments [Abstract]
Equity Securities	157,087	[1]	156,057	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments
Investments [Abstract]
Equity Securities	141,991	[1]	141,413	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate
Investments [Abstract]
Equity Securities	118,189	[1]	130,787	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Other commingled funds
Investments [Abstract]
Equity Securities	3,902	[1]	9,340	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities
Investments [Abstract]
Available-for-sale Securities, Debt Securities	78,197	[1]	67,760	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	325,042	[1]	319,809	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	54,637	[1]	50,121	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. equities
Investments [Abstract]
Equity Securities	277,853	[1]	271,166	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities
Investments [Abstract]
Equity Securities	152,670	[1]	151,961	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	41,250	[1]	28,741	[2]
Alternative Investment, Fair Value Disclosure	641,123	[1],[3]	659,086	[2],[4]
Investments [Abstract]
Equity Securities	2,146,587	[1]	2,143,281	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	0	[1],[3]	0	[2],[4]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. equities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	90,369	[1],[3]	89,857	[2],[4]
Investments [Abstract]
Equity Securities	316,496	[1]	306,408	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Emerging market debt funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	163,868	[1],[3]	166,375	[2],[4]
Investments [Abstract]
Equity Securities	163,868	[1]	166,375	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	198,060	[1],[3]	198,037	[2],[4]
Investments [Abstract]
Equity Securities	198,060	[1]	198,037	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	185,851	[1],[3]	201,842	[2],[4]
Investments [Abstract]
Equity Securities	185,851	[1]	201,842	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Other commingled funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	2,975	[1],[3]	2,975	[2],[4]
Investments [Abstract]
Equity Securities	3,875	[1]	9,261	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	0	[1],[3]	0	[2],[4]
Investments [Abstract]
Available-for-sale Securities, Debt Securities	77,505	[1]	69,413	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	0	[1],[3]	0	[2],[4]
Investments [Abstract]
Available-for-sale Securities, Debt Securities	320,812	[1]	322,129	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. corporate bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	0	[1],[3]	0	[2],[4]
Investments [Abstract]
Available-for-sale Securities, Debt Securities	53,151	[1]	50,102	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. equities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	0	[1],[3]	0	[2],[4]
Investments [Abstract]
Equity Securities	556,816	[1]	556,974	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. equities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	0	[1],[3]	0	[2],[4]
Investments [Abstract]
Equity Securities	228,903	[1]	233,999	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	41,250	[1]	28,741	[2]
Investments [Abstract]
Equity Securities	1,053,996	[1]	1,042,551	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities
Investments [Abstract]
Equity Securities	226,127	[1]	216,551	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Emerging market debt funds
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Other commingled funds
Investments [Abstract]
Equity Securities	900	[1]	6,286	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities
Investments [Abstract]
Available-for-sale Securities, Debt Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. equities
Investments [Abstract]
Equity Securities	556,816	[1]	556,974	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities
Investments [Abstract]
Equity Securities	228,903	[1]	233,999	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[2]
Investments [Abstract]
Equity Securities	451,468	[1]	441,644	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Emerging market debt funds
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Other commingled funds
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities
Investments [Abstract]
Available-for-sale Securities, Debt Securities	77,505	[1]	69,413	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	320,812	[1]	322,129	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	53,151	[1]	50,102	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. equities
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[2]
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Emerging market debt funds
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Other commingled funds
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities
Investments [Abstract]
Available-for-sale Securities, Debt Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. corporate bonds
Investments [Abstract]
Available-for-sale Securities, Debt Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. equities
Investments [Abstract]
Equity Securities	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities
Investments [Abstract]
Equity Securities	$ 0	[1]	$ 0	[2]

[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.

[2] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49 million of rabbi trust assets and miscellaneous investments.

[3] Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

[4] Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

XML

Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Thousands	Mar. 31, 2018 USD ($)
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	$ 2,886
Due in 1 to 5 Years	112,952
Due in 5 to 10 Years	209,280
Due after 10 Years	126,350
Total	451,468
Government securities
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	9,124
Due in 5 to 10 Years	2,318
Due after 10 Years	66,063
Total	77,505
U.S. corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	2,886
Due in 1 to 5 Years	87,565
Due in 5 to 10 Years	173,634
Due after 10 Years	56,727
Total	320,812
Non U.S. corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	16,263
Due in 5 to 10 Years	33,328
Due after 10 Years	3,560
Total	$ 53,151

XML

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Rabbi Trust (Details) - Fair Value Measured on a Recurring Basis - USD ($) $ in Thousands		Mar. 31, 2018	Dec. 31, 2017
Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	$ 10,766	$ 11,115
Cost | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	393	783
Cost | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	10,373	10,332
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	11,544	12,066
Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	11,544	12,066
Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	0	0
Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	0	0
Fair Value | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	393	783
Fair Value | Rabbi Trust [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	393	783
Fair Value | Rabbi Trust [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Fair Value | Rabbi Trust [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Fair Value | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	11,151	11,283
Fair Value | Mutual Funds [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	11,151	11,283
Fair Value | Mutual Funds [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	0	0
Fair Value | Mutual Funds [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	$ 0	$ 0

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

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions		3 Months Ended
		Mar. 31, 2018 USD ($) MMBTU MWh gal Counterparty	Dec. 31, 2017 MMBTU MWh gal
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		10
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		8
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 45.1
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		58.00%
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [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 | $		$ 15.8
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		20.00%
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]	32,451	41,711
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]	18,330	23,829
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	180	240
Commodity Derivative
Reclassification of Cash Flow Hedge Gain (Loss) [Abstract]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $		$ 0.1

[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, 2018	Mar. 31, 2017
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	7,000	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	232,000	342,000
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	261,000	342,000
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	7,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(29,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0
Pre-tax gains (losses) recognized during the period in income	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	(3,411,000)	(1,912,000)
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)	1,649,000	(2,090,000)
Pre-tax gains (losses) recognized during the period in income	2,336,000	(323,000)
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	2,740,000	622,000
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	(4,259,000)	(1,247,000)
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)	2,169,000	(2,788,000)
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	848,000	(665,000)
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)	(520,000)	698,000
Pre-tax gains (losses) recognized during the period in income	$ (404,000)	$ (945,000)

XML

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0	$ 0
Collateral posted on derivative instruments	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, 2018		Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		3,900		3,100
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14,564		25,230
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		29,902		28,102
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		19,045		17,697
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		98,692		102,742
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		13,812		24,573
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(6,964)	[1]	(12,169)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		7,995		7,233
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(6,931)	[1]	(11,744)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5,732		17,156
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(33)	[1]	(425)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				77
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[2]			0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		29,788		27,982
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(14,170)	[1]	(6,502)	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		29,788		27,982
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(14,170)	[1]	(6,502)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		4,939		3,592
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(7,385)	[1]	(12,399)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		4,939		3,592
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(7,351)	[1]	(11,974)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(34)	[1]	(425)	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		12,242		12,829
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(17,698)	[1]	(9,334)	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		12,242		12,829
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(17,698)	[1]	(9,334)	[2]
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		598		1,691
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		598		1,691
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		602		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		602		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		647		1,713
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		647		1,713
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 Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,868		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,868		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14,208		17,328
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		14,123		17,144
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				77
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		35,308		29,121
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		35,308		29,121
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		11,643		13,853
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		11,643		13,853
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 Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		27,604		22,163
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		27,604		22,163
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5,970		17,723
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		205		142
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		5,765		17,581
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		8,048		5,363
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		8,048		5,363
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		34		425
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
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		34		425
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		468		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		468		0
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		752	[3]	657	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		114	[3]	120	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		14,106	[3]	14,105	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		86,450	[3]	89,913	[4]
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		20,776		36,742
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14,926		18,977
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5,765		17,581
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				77
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		43,958		34,484
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		43,958		34,484
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		12,324		15,991
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		12,290		15,566
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		34		425
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		29,940		22,163
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		29,940		22,163
Cash Flow Hedges | Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		85		107
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		0	[1]	0
Cash Flow Hedges | Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Cash Flow Hedges | Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		85		107
Cash Flow Hedges | Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Cash Flow Hedges | Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 85		$ 107

[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, 2018. At March 31, 2018, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.9 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, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.1 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] 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] During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 22,661,000	$ 15,320,000
Purchases		2,000	280,000
Settlements		(1,934,000)	(3,426,000)
Gains (losses) recognized in earnings	[1]	2,280,000	(792,000)
Net losses recognized as regulatory assets and liabilities		(9,493,000)	(6,739,000)
Balance at end of period		13,516,000	4,643,000
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.

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,934,024	$ 4,933,018
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 5,352,133	$ 5,601,919

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Other (Expense) Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Other Income and Expenses [Abstract]
Interest income	$ 2,935	$ 2,709
Benefits non-service cost	342	(855)
Other nonoperating income	1	10
Defined Benefit Plan, Non-service Costs	(3,062)	(3,398)
Other income (expense), net	$ 216	$ (1,534)

XML

Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Operating revenues		$ 1,310,751	$ 1,307,140
Net income (loss)		111,740	94,166
Affiliate electric revenue		116,972	123,689
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues		1,062,428	1,079,139
Net income (loss)		85,722	78,082
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues		241,576	221,277
Net income (loss)		25,445	17,505
All Other
Segment Reporting Information [Line Items]
Operating revenues		7,056	6,927
Net income (loss)		573	(1,421)
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	[1],[2]	1,310,751	1,307,140
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	[1]	1,062,263	1,079,030
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	[2]	241,432	221,183
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues		7,056	6,927
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues		(309)	(203)
Net income (loss)		0	0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues		165	109
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues		144	94
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues		$ 0	$ 0

[1] Operating revenues include $117 million and $124 million of affiliate electric revenue for the three months ended March 31, 2018 and 2017.

[2] Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 2018 and 2017.

XML

Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Jan. 31, 2018 USD ($) Plan	Mar. 31, 2018 USD ($)	Mar. 31, 2017 USD ($)
Pension Plan [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 6,982	$ 6,958
Interest cost (a)		8,804	10,177
Expected return on plan assets (a)		(14,541)	(15,017)
Amortization of prior service cost (credit) (a)		(29)	265
Amortization of net loss (a)		9,615	9,902
Net periodic benefit cost		10,831	12,285
Costs not recognized due to the effects of regulation		(2,763)	(4,899)
Net benefit cost recognized for financial reporting		8,068	7,386
Total contributions to the pension plans during the period	$ 63,000
Pension Plan [Member] | Xcel Energy Inc.
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to the pension plans during the period	$ 150,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4
Other Postretirement Benefits Plan [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost		43	36
Interest cost (a)		769	854
Expected return on plan assets (a)		(96)	(54)
Amortization of prior service cost (credit) (a)		(759)	(759)
Amortization of net loss (a)		595	507
Net periodic benefit cost		552	584
Costs not recognized due to the effects of regulation			0
Net benefit cost recognized for financial reporting		$ 552	$ 584

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	$ 5,475,570
(Gains) losses reclassified from net accumulated other comprehensive loss	92	$ 238
Accumulated other comprehensive (loss) income at end of period	5,522,848
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(20,895)	(18,208)
Other comprehensive income (loss) before reclassifications	5
(Gains) losses reclassified from net accumulated other comprehensive loss	167	203
Net current period other comprehensive income (loss)	172	203
Accumulated other comprehensive (loss) income at end of period	(20,723)	(18,005)
Unrealized Gains and Losses on Marketable Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	128	105
Other comprehensive income (loss) before reclassifications	0
(Gains) losses reclassified from net accumulated other comprehensive loss	(128)	0
Net current period other comprehensive income (loss)	(128)	0
Accumulated other comprehensive (loss) income at end of period	0	105
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(3,770)	(2,680)
Other comprehensive income (loss) before reclassifications	0
(Gains) losses reclassified from net accumulated other comprehensive loss	53	35
Net current period other comprehensive income (loss)	53	35
Accumulated other comprehensive (loss) income at end of period	(3,717)	(2,645)
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(24,537)	(20,783)
Other comprehensive income (loss) before reclassifications	5
(Gains) losses reclassified from net accumulated other comprehensive loss	92	238
Net current period other comprehensive income (loss)	97	238
Accumulated other comprehensive (loss) income at end of period	$ (24,440)	$ (20,545)

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Other Comprehensive Income (Reclassification from AOCI) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	$ 292,295	$ 308,626
Total, pre-tax	(124,451)	(133,181)
Tax benefit	12,711	39,015
Total amounts reclassified, net of tax	92	238
Gains and Losses on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax	167	203
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	232	342
Tax benefit	(65)	(139)
Total, net of tax	167	203
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	261	342
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	(29)	0
Amortization of net loss | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	125	109
Prior service credit | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	(49)	(49)
Defined Benefit Pension and Postretirement Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax	53	35
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	76	60
Tax (benefit) expense	(23)	(25)
Total amounts reclassified, net of tax	53	35
Marketable securities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax	(128)	0
Marketable securities | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Realization of gains	(179)	0
Total, pre-tax	(179)	0
Tax benefit	51	0
Total, net of tax	$ (128)	$ 0

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Revenues Revenues (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		$ 1,256,385	$ 1,245,325
Alternative revenue and other		54,366	61,815
Total operating revenues		$ 1,310,751	1,307,140
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs		24 months
Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	[1],[2]	$ 1,310,751	1,307,140
Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		1,024,494	1,014,550
Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		449,111	432,036
Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		564,974	573,632
Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		10,409	8,882
Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		46,365	45,919
Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		54,798	53,959
Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		116,972	123,689
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		13,756	7,208
Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		1,018,551	1,027,249
Alternative revenue and other		43,712	51,781
Total operating revenues		1,062,428	1,079,139
Regulated Electric | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	[1]	1,062,263	1,079,030
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		788,871	797,719
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		311,129	304,413
Regulated Electric | Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		468,023	485,103
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		9,719	8,203
Regulated Electric | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		46,365	45,919
Regulated Electric | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		54,798	53,959
Regulated Electric | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		116,972	123,689
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		11,545	5,963
Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		230,778	211,149
Alternative revenue and other		10,654	10,034
Total operating revenues		241,576	221,277
Regulated Natural Gas | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	[2]	241,432	221,183
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		228,567	209,904
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		131,659	121,413
Regulated Natural Gas | Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		96,908	88,491
Regulated Natural Gas | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0
Regulated Natural Gas | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0
Regulated Natural Gas | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0
Regulated Natural Gas | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0
Regulated Natural Gas | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		2,211	1,245
All Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		7,056	6,927
Alternative revenue and other		0	0
Total operating revenues		7,056	6,927
All Other | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues		7,056	6,927
All Other | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		7,056	6,927
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		6,323	6,210
All Other | Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		43	38
All Other | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		690	679
All Other | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0
All Other | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0
All Other | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0
All Other | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		$ 0	$ 0

[1] Operating revenues include $117 million and $124 million of affiliate electric revenue for the three months ended March 31, 2018 and 2017.

[2] Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended March 31, 2018 and 2017.