NORTHERN STATES POWER CO - FORM 10-Q

NORTHERN STATES POWER CO - FORM 10-Q - October 26, 2018

Attached files

Attached files

NORTHERN STATES POWER CO Reports

file	filename
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO	nspmex9901q32018.htm
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO	nspmex3201q32018.htm
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO	nspmex3102q32018.htm
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO	nspmex3101q32018.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended Sept. 30, 2018



¨	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 every Interactive Data File required to be submitted 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 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 ¨
	Emerging growth company ¨

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

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

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



Class		Outstanding at Oct. 26, 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



PART I —	FINANCIAL INFORMATION

Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 4 —	Controls and Procedures	35

PART II —	OTHER INFORMATION

Item 1 —	Legal Proceedings	36
Item 1A —	Risk Factors	36
Item 6 —	Exhibits	36

SIGNATURES		37

Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

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

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2018			2017			2018			2017
Operating revenues
Electric, non-affiliates	$	1,166,862		$	1,167,447		$	3,091,144		$	3,083,182
Electric, affiliates	122,636			123,524			357,025			366,598
Natural gas	54,625			57,442			379,169			356,631
Other	7,631			7,366			22,902			21,448
Total operating revenues	1,351,754			1,355,779			3,850,240			3,827,859

Operating expenses
Electric fuel and purchased power	479,813			435,003			1,304,087			1,215,071
Cost of natural gas sold and transported	19,595			20,723			211,679			198,968
Cost of sales — other	5,703			4,313			14,539			13,085
Operating and maintenance expenses	310,536			285,372			912,027			899,187
Conservation program expenses	29,434			31,674			87,762			92,238
Depreciation and amortization	187,201			176,739			547,333			522,070
Taxes (other than income taxes)	59,990			62,220			191,820			191,989
Total operating expenses	1,092,272			1,016,044			3,269,247			3,132,608

Operating income	259,482			339,735			580,993			695,251

Other expense, net	(1,976		)	(1,278		)	(3,994		)	(6,444		)
Allowance for funds used during construction — equity	5,899			10,683			19,550			23,391

Interest charges and financing costs
Interest charges — includes other financing costs of $1,853, $1,845, $5,501 and $5,437, respectively	56,398			57,577			170,517			172,548
Allowance for funds used during construction — debt	(3,500		)	(5,383		)	(10,287		)	(11,909		)
Total interest charges and financing costs	52,898			52,194			160,230			160,639

Income before income taxes	210,507			296,946			436,319			551,559
Income taxes	9,331			67,943			31,016			140,728
Net income	$	201,176		$	229,003		$	405,303		$	410,831

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
	2018		2017		2018			2017
Net income	$	201,176	$	229,003	$	405,303		$	410,831

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $20, $21, $65 and $70, respectively	56		39		163			110

Derivative instruments:
Net fair value decrease, net of tax of $2, $16, $13 and $33, respectively	5		22		32			48
Reclassification of losses to net income, net of tax of $56, $222, $185 and $502, respectively	172		379		504			786
	177		401		536			834
Marketable securities:
Reclassification of gains to net income, net of tax of $0, $0, $(51) and $0, respectively	—		—		(128		)	—

Other comprehensive income	233		440		571			944
Comprehensive income	$	201,409	$	229,443	$	405,874		$	411,775

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Nine Months Ended Sept. 30,
	2018			2017
Operating activities
Net income	$	405,303		$	410,831
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	552,141			526,784
Nuclear fuel amortization	92,393			87,654
Deferred income taxes	32,672			98,125
Amortization of investment tax credits	(1,226		)	(1,241		)
Allowance for equity funds used during construction	(19,550		)	(23,391		)
Net realized and unrealized hedging and derivative transactions	(2,278		)	(2,703		)
Other, net	(1,038		)	(1,072		)
Changes in operating assets and liabilities:
Accounts receivable	(29,320		)	(14,677		)
Accrued unbilled revenues	28,610			33,465
Inventories	17,168			(4,265		)
Other current assets	84,801			35,591
Accounts payable	(21,377		)	(34,275		)
Net regulatory assets and liabilities	115,043			(15,467		)
Other current liabilities	(78,895		)	(73,898		)
Pension and other employee benefit obligations	(57,593		)	(55,548		)
Change in other noncurrent assets	880			(3,585		)
Change in other noncurrent liabilities	(32,596		)	(30,704		)
Net cash provided by operating activities	1,085,138			931,624

Investing activities
Utility capital/construction expenditures	(697,705		)	(696,857		)
Allowance for equity funds used during construction	19,550			23,391
Purchases investment securities	(493,893		)	(965,086		)
Proceeds from the sale of investment securities	478,614			948,558
Investments in utility money pool arrangement	(748,000		)	(122,000		)
Repayments from utility money pool arrangement	748,000			122,000
Other, net	(2,775		)	(3,463		)
Net cash used in investing activities	(696,209		)	(693,457		)

Financing activities
Repayments of short-term borrowings, net	4,000			(85,000		)
Borrowings under utility money pool arrangement	345,000			516,000
Repayments under utility money pool arrangement	(430,000		)	(466,000		)
Proceeds from issuance of long-term debt	—			586,264
Repayments of long-term debt	(1		)	(507,865		)
Capital contributions from parent	49,622			123,247
Dividends paid to parent	(371,960		)	(418,133		)
Other, net	(93		)	—
Net cash (used in) provided by financing activities	(403,432		)	(251,487		)

Net change in cash and cash equivalents	(14,503		)	(13,320		)
Cash and cash equivalents at beginning of period	43,781			47,595
Cash and cash equivalents at end of period	$	29,278		$	34,275

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(167,301	)	$	(177,336	)
Cash received (paid) for income taxes, net	59,461			(60,911		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	79,346		$	47,261

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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



	Sept. 30, 2018			Dec. 31, 2017
Assets
Current assets
Cash and cash equivalents	$	29,278		$	43,781
Accounts receivable, net	387,855			345,110
Accounts receivable from affiliates	17,758			48,494
Accrued unbilled revenues	249,106			277,716
Inventories	288,678			337,712
Regulatory assets	278,288			276,392
Derivative instruments	30,450			25,230
Prepaid taxes	20,789			79,145
Prepayments and other	32,591			43,682
Total current assets	1,334,793			1,477,262

Property, plant and equipment, net	13,215,718			13,033,612

Other assets
Nuclear decommissioning fund and other investments	2,262,751			2,192,344
Regulatory assets	1,326,785			1,190,429
Derivative instruments	22,083			28,102
Other	10,032			4,142
Total other assets	3,621,651			3,415,017
Total assets	$	18,172,162		$	17,925,891

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	16		$	7
Short-term debt	24,000			20,000
Borrowings under utility money pool arrangement	—			85,000
Accounts payable	391,695			368,342
Accounts payable to affiliates	61,347			80,070
Regulatory liabilities	219,169			83,403
Taxes accrued	246,397			229,335
Accrued interest	52,530			65,896
Dividends payable to parent	84,177			98,687
Derivative instruments	18,664			17,697
Customer deposits	58,949			95,369
Other	146,862			152,965
Total current liabilities	1,303,806			1,296,771

Deferred credits and other liabilities
Deferred income taxes	1,700,494			1,612,341
Deferred investment tax credits	21,301			22,528
Regulatory liabilities	1,984,514			1,978,527
Asset retirement obligations	2,167,201			2,083,874
Derivative instruments	86,748			102,742
Pension and employee benefit obligations	278,614			331,087
Other	160,242			89,440
Total deferred credits and other liabilities	6,399,114			6,220,539

Commitments and contingencies
Capitalization
Long-term debt	4,936,119			4,933,011
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at Sept. 30, 2018 and Dec. 31, 2017, respectively	10			10
Additional paid in capital	3,589,363			3,580,234
Retained earnings	1,967,716			1,919,863
Accumulated other comprehensive loss	(23,966		)	(24,537		)
Total common stockholder’s equity	5,533,123			5,475,570
Total liabilities and equity	$	18,172,162		$	17,925,891

See Notes to Consolidated Financial Statements

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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 Sept. 30, 2018 and Dec. 31, 2017; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2018 and 2017; and its cash flows for the nine months ended Sept. 30, 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 Sept. 30, 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. Adoption will occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and included in Targeted Improvements, Topic 842 (ASU No. 2018-11). On Jan. 1, 2019, agreements historically disclosed as operating leases for the use of real estate, equipment and certain fossil-fueled generating facilities operated under purchased power agreements (PPAs) are expected to be recognized on the consolidated balance sheet. Other than first-time recognition of these types of operating leases on the consolidated balance sheet, the implementation is not expected to have a significant impact on NSP-Minnesota’s consolidated financial statements.

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 material impact on NSP-Minnesota’s consolidated financial statements. For related disclosures, see Note 13 to the consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which 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.

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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 the 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 and $10.2 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for the three and nine months ended Sept. 30, 2017, respectively. 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)	Sept. 30, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	409,740		$	366,388
Less allowance for bad debts	(21,885		)	(21,278		)
	$	387,855		$	345,110



(Thousands of Dollars)	Sept. 30, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	176,183	$	209,236
Fuel	76,962		94,483
Natural gas	35,533		33,993
	$	288,678	$	337,712



(Thousands of Dollars)	Sept. 30, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	17,363,519		$	17,024,925
Natural gas plant	1,426,646			1,370,330
Common and other property	726,127			724,066
Construction work in progress	685,047			530,126
Total property, plant and equipment	20,201,339			19,649,447
Less accumulated depreciation	(7,314,826		)	(7,018,249		)
Nuclear fuel	2,716,595			2,697,412
Less accumulated amortization	(2,387,390		)	(2,294,998		)
	$	13,215,718		$	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.

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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:



	Nine Months Ended Sept. 30
	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 (PTCs) ^(a)	(12.1	)	(11.3	)
Regulatory differences - ARAM ^(b)	(9.5	)	(0.1	)
Regulatory differences - ARAM deferral ^(c)	7.7		—
Regulatory differences - reversal of prior quarters’ ARAM deferral ^(c)	(7.1	)	—
Regulatory differences - other utility plant items	0.2		(0.3	)
Other tax credits (net of federal income tax expense)	(1.4	)	(1.1	)
Other (net)	1.2		(2.5	)
Effective income tax rate	7.1	%	25.5	%


^(a)	Quarterly PTCs may vary due to production and timing differences. Annual 2018 PTCs are forecasted to exceed 2017.


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


^(c)	ARAM has been deferred when regulatory treatment has not been established. As NSP-Minnesota received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding 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 - 2014		October 2019
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. In 2017 Xcel Energy and the Office of Appeals (Appeals) reached an agreement and the benefit related to the agreed upon portions was recognized. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

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). Xcel Energy filed a protest with the IRS. As of Sept. 30, 2018 the case has been forwarded to Appeals and 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 unknown.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 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 Sept. 30, 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.

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



(Millions of Dollars)	Sept. 30, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	11.4	$	10.2
Unrecognized tax benefit — Temporary tax positions	5.4		7.9
Total unrecognized tax benefit	$	16.8	$	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)	Sept. 30, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(14.0	)	$	(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 audit progress and the IRS audit resumes, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $13 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)	Sept. 30, 2018			Dec. 31, 2017
Payable for interest related to unrecognized tax benefits at beginning of period	$	(0.9	)	$	(2.0	)
Interest (expense) income related to unrecognized tax benefits recorded during the period	(1.1		)	1.1
Payable for interest related to unrecognized tax benefits at end of period	$	(2.0	)	$	(0.9	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 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 and in Note 5 to the consolidated financial statements to NSP-Minnesota’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2018 and June 30, 2018, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Tax Reform — Regulatory Proceedings

The specific impacts of the TCJA on customer rates are subject to regulatory approval. The following details the status of regulatory decisions in each state where NSP-Minnesota operates.

Minnesota — In August 2018, the Minnesota Public Utilities Commission (MPUC) ordered NSP-Minnesota to refund the 2018 impacts of TCJA, including $5 million to natural gas customers and $131 million to electric customers, including low income program funding of $2 million.

South Dakota — In July 2018, the South Dakota Public Utilities Commission approved a settlement providing a one-time customer refund of $11 million for the 2018 impact of the TCJA, while NSP-Minnesota would retain the benefits of the TCJA in 2019 and 2020 in exchange for a two-year rate case moratorium.

North Dakota — Natural Gas — In August 2018, NSP-Minnesota and the North Dakota Public Service Commission (NDPSC) Staff reached a TCJA settlement, in which NSP-Minnesota would amortize $1 million annually of the regulatory asset for the remediation of the manufactured gas plant (MGP) site in Fargo, N.D. beginning in 2018, and retain the TCJA savings to approximately offset the MGP amortization expense. The TCJA benefits would be incorporated into a future rate case and the MGP amortization would then be recoverable through the cost of gas rider until fully amortized. A NDPSC decision related to the settlement is expected to be received by the end of 2018. See Note 6 for further discussion of the Fargo, N.D. MGP Site.

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North Dakota — Electric — In October 2018, NSP-Minnesota and the NDPSC Staff reached a settlement which included a one-time customer refund of $10 million for 2018, while NSP-Minnesota would retain the benefits of the TCJA in 2019 and 2020 in exchange for a two-year rate case moratorium. The settlement also includes an earnings sharing provision in which annual weather normalized earnings exceeding an ROE of 9.85 percent are returned to customers.

A NDPSC decision related to the settlement is expected to be received by the end of 2018 or during the first quarter of 2019.

Recently Concluded Regulatory Proceedings — MPUC and the NDPSC

PPA Terminations and Amendments — In June 2018, NSP-Minnesota terminated the Benson and Laurentian PPAs, and purchased the Benson biomass facility. As a result, a $103 million regulatory asset was recognized for the costs of the Benson transaction, including payments to Benson of $93 million, as well as other transaction costs and future estimated facility removal costs. For Laurentian, a regulatory asset of $109 million was recognized for annual termination payments over six years. The regulatory approvals provide for recovery of the Benson regulatory asset over approximately 10 years, and for recovery of the Laurentian termination payments as they occur, through fuel and purchased energy recovery mechanisms. The termination of the PPAs is expected to save customers over $600 million over the next 10 years.

Pending Regulatory Proceeding — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) Return on Equity (ROE) Complaints — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, 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. 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. 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.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 to the consolidated financial statements, 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 and in Notes 5 and 6 to NSP-Minnesota’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2018 and June 30, 2018, 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

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.

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NSP-Minnesota had approximately 1,002 Megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2018 and 1,069 MW as of 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 various expiration dates through 2027.

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 agreement expires in 2019.

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



(Millions of Dollars)	Sept. 30, 2018		Dec. 31, 2017
Guarantee issued and outstanding	$	4.8	$	4.8

Environmental Contingencies

Fargo, N.D. Manufactured Gas Plant (MGP) Site — NSP-Minnesota is remediating a former MGP site in Fargo, N.D. Remediation is expected to be completed in early November 2018, and several years of groundwater monitoring is expected to follow. NSP-Minnesota has also initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota has set a trial date for Spring of 2020.

NSP-Minnesota recorded an estimated liability of $6 million as of Sept. 30, 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 $25 million, of which approximately $19 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 NDPSC. In October 2018, the MPUC denied NSP-Minnesota’s request to defer post-2017 MGP remediation expenditures allocable to the Minnesota jurisdiction, including the Fargo MGP Site.

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 five sites, in addition to the Fargo MGP Site, 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 2019. NSP-Minnesota accrued $3 million as of Sept. 30, 2018 and Dec. 31, 2017 for all of these sites. There may be insurance recovery and/or recovery from other responsible parties that will offset any costs incurred.

Environmental Requirements

Water and Waste

Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the United States Environmental Protection Agency published a final rule regulating the management, storage, and disposal of coal combustion residuals (CCRs) as a nonhazardous waste (CCR Rule).

Under the CCR Rule, utilities are required to complete certain groundwater sampling around their CCR landfills and surface impoundments. NSP-Minnesota is currently conducting additional groundwater sampling and will evaluate whether corrective action is required at any CCR landfills or surface impoundments. Until NSP-Minnesota completes additional groundwater sampling, it is uncertain what impact, if any, there will be on the operations, financial position or cash flows. NSP-Minnesota believes that any associated costs would be recoverable through regulatory mechanisms.

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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 Sept. 30, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			85
Average amount outstanding	34			25
Maximum amount outstanding	143			142
Weighted average interest rate, computed on a daily basis	1.97		%	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 Sept. 30, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	500		$	500
Amount outstanding at period end	24			20
Average amount outstanding	6			62
Maximum amount outstanding	73			237
Weighted average interest rate, computed on a daily basis	2.12		%	1.10		%
Weighted average interest rate at period end	2.30			1.93

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Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2018 and Dec. 31, 2017, there were $37 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 Sept. 30, 2018, NSP-Minnesota had the following committed credit facility available (in millions of dollars):



Credit Facility ^(a)		Drawn ^(b)		Available
$	500	$	61	$	439


^(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 Sept. 30, 2018 and Dec. 31, 2017.


8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the 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.

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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 asset class target allocations approved by the MPUC for the 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 $600 million and $560 million as of Sept. 30, 2018 and Dec. 31, 2017, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $22 million and $7 million as of Sept. 30, 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 Sept. 30, 2018 and Dec. 31, 2017:



	Sept. 30, 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	$	33,040	$	33,040	$	—	$	—	$	—	$	33,040
Commingled funds:
Non U.S. equities	262,345		195,959		—		—		91,426		287,385
Emerging market debt funds	162,835		—		—		—		164,772		164,772
Private equity investments	169,676		—		—		—		249,881		249,881
Real estate	125,422		—		—		—		198,422		198,422
Debt securities:
Government securities	75,799		—		73,317		—		—		73,317
U.S. corporate bonds	334,219		—		329,727		—		—		329,727
Non U.S. corporate bonds	55,856		—		54,813		—		—		54,813
Equity securities:
U.S. equities	257,932		590,310		—		—		—		590,310
Non U.S. equities	156,225		229,245		—		—		—		229,245
Total	$	1,633,349	$	1,048,554	$	457,857	$	—	$	704,501	$	2,210,912


^(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 and nine months ended Sept. 30, 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 Sept. 30, 2018:



	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	—	$	—	$	1,750	$	71,567	$	73,317
U.S. corporate bonds	12,759		90,982		175,662		50,324		329,727
Non U.S. corporate bonds	1,998		20,498		28,151		4,166		54,813
Debt securities	$	14,757	$	111,480	$	205,563	$	126,057	$	457,857

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 Sept. 30, 2018 and Dec. 31, 2017:



	Sept. 30, 2018
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trust ^(a)
Cash equivalents	$	2,321	$	2,321	$	—	$	—	$	2,321
Mutual funds	10,474		11,748		—		—		11,748
Total	$	12,795	$	14,069	$	—	$	—	$	14,069



	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 Sept. 30, 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 Sept. 30, 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 and nine months ended Sept. 30, 2018 and 2017.

At Sept. 30, 2018, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial 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 Sept. 30, 2018 and Dec. 31, 2017:


^(a)	Amounts are not reflective of net positions in the underlying commodities.


^(b)	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2018 and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities and income:



	Three Months Ended Sept. 30, 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 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)			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	267		^(a)	$	—		$	—
Vehicle fuel and other commodity	7		—			(39		)	^(b)	—			—
Total	$	7	$	—		$	228			$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—		$	3,447	^(c)
Electric commodity	—		1,127			—				447		^(d)	—
Natural gas commodity	—		(370		)	—				—		^(e)	—		^(e)
Total	$	—	$	757		$	—			$	447		$	3,447

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	Nine Months Ended Sept. 30, 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	$	—	$	—		$	792		^(a)	$	—			$	—
Vehicle fuel and other commodity	45		—			(103		)	^(b)	—				—
Total	$	45	$	—		$	689			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	11,114		^(c)
Electric commodity	—		(4,487		)	—				3,758			^(d)	—
Natural gas commodity	—		460			—				(521		)	^(e)	(404		)	^(e)
Total	$	—	$	(4,027	)	$	—			$	3,237			$	10,710




	Three Months Ended Sept. 30, 2017
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	612		^(a)	$	—			$	—
Vehicle fuel and other commodity	38		—			(11		)	^(b)	—				—
Total	$	38	$	—		$	601			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	1,493	^(c)
Electric commodity	—		20,216			—				(5,356		)	^(d)	—
Natural gas commodity	—		(383		)	—				—			^(e)	—		^(e)
Total	$	—	$	19,833		$	—			$	(5,356	)		$	1,493

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	Nine Months Ended Sept. 30, 2017
	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	$	—	$	—		$	1,304		^(a)	$	—			$	—
Vehicle fuel and other commodity	81		—			(16		)	^(b)	—				—
Total	$	81	$	—		$	1,288			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	8,092		^(c)
Electric commodity	—		17,444			—				(9,293		)	^(d)	—
Natural gas commodity	—		(1,010		)	—				698			^(e)	(945		)	^(e)
Total	$	—	$	16,434		$	—			$	(8,595	)		$	7,147


^(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 and nine months ended Sept. 30, 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 Sept. 30, 2018, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $41.8 million or 51 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 $14.0 million or 17 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 Sept. 30, 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 Sept. 30, 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 Sept. 30, 2018:



	Sept. 30, 2018
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	48	$	—	$	48	$	—		$	48
Other derivative instruments:
Commodity trading	422		17,565		1,951		19,938		(8,162		)	11,776
Electric commodity	—		—		18,002		18,002		(172		)	17,830
Natural gas commodity	—		771		—		771		—			771
Total current derivative assets	$	422	$	18,384	$	19,953	$	38,759	$	(8,334	)	30,425
PPAs ^(a)												25
Current derivative instruments												$	30,450
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	19	$	28,125	$	5,399	$	33,543	$	(11,561	)	$	21,982
Total noncurrent derivative assets	$	19	$	28,125	$	5,399	$	33,543	$	(11,561	)	21,982
PPAs ^(a)												101
Noncurrent derivative instruments												$	22,083



	Sept. 30, 2018
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	135	$	14,792	$	1,754	$	16,681	$	(11,868	)	$	4,813
Electric commodity	—		—		172		172		(172		)	—
Total current derivative liabilities	$	135	$	14,792	$	1,926	$	16,853	$	(12,040	)	4,813
PPAs ^(a)												13,851
Current derivative instruments												$	18,664
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	2	$	19,507	$	411	$	19,920	$	(12,696	)	$	7,224
Total noncurrent derivative liabilities	$	2	$	19,507	$	411	$	19,920	$	(12,696	)	7,224
PPAs ^(a)												79,524
Noncurrent derivative instruments												$	86,748


^(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 is being 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 Sept. 30, 2018. At Sept. 30, 2018, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.9 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		Fair Value Total		Counterparty Netting ^(b)			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		Fair Value Total		Counterparty Netting ^(b)			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 is being 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 and nine months ended Sept. 30, 2018 and 2017:



	Three Months Ended Sept. 30
(Thousands of Dollars)	2018			2017
Balance at July 1	$	28,029		$	40,572
Settlements	(8,694		)	(23,186		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	303			527
Net gains recognized as regulatory assets and liabilities	3,377			27,500
Balance at Sept. 30	$	23,015		$	45,413

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2018			2017
Balance at Jan. 1	$	22,661		$	15,320
Purchases	26,397			40,740
Settlements	(15,798		)	(34,681		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings ^(a)	(70		)	5,742
Net (losses) gains recognized as regulatory assets and liabilities	(10,175		)	18,292
Balance at Sept. 30	$	23,015		$	45,413


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

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2018 and 2017.

Fair Value of Long-Term Debt

As of Sept. 30, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:



	Sept. 30, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,936,135	$	5,159,080	$	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 Sept. 30, 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 Expense, Net

Other expense, net consisted of the following:



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2018			2017			2018			2017
Interest income	$	1,596		$	2,936		$	5,053		$	6,250
Other nonoperating expense	(722		)	(429		)	(24		)	(402		)
Insurance policy income (expense)	157			(387		)	(1,038		)	(2,098		)
Benefits non-service cost	(3,007		)	(3,398		)	(7,985		)	(10,194		)
Other expense, net	$	(1,976	)	$	(1,278	)	$	(3,994	)	$	(6,444	)

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10.	Segment Information

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

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


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


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


•	Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

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

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 operating and maintenance (O&M) expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2018
Operating revenues^(a)(b)	$	1,289,498	$	54,625		$	7,631	$	—		$	1,351,754
Intersegment revenues	219		138			—		(357		)	—
Total revenues	$	1,289,717	$	54,763		$	7,631	$	(357	)	$	1,351,754
Net income (loss)	$	207,316	$	(8,416	)	$	2,276	$	—		$	201,176



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2017
Operating revenues ^(a)(b)	$	1,290,971	$	57,442		$	7,366	$	—		$	1,355,779
Intersegment revenues	160		100			—		(260		)	—
Total revenues	$	1,291,131	$	57,542		$	7,366	$	(260	)	$	1,355,779
Net income (loss)	$	232,078	$	(6,242	)	$	3,167	$	—		$	229,003


^(a)	Operating revenues include $123 million and $124 million of affiliate electric revenue for the three months ended Sept. 30, 2018 and 2017.


^(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended Sept. 30, 2018 and 2017.



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2018
Operating revenues^(a)(b)	$	3,448,169	$	379,169	$	22,902	$	—		$	3,850,240
Intersegment revenues	512		398		—		(910		)	—
Total revenues	$	3,448,681	$	379,567	$	22,902	$	(910	)	$	3,850,240
Net income	$	381,913	$	17,428	$	5,962	$	—		$	405,303

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2017
Operating revenues ^(a)(b)	$	3,449,780	$	356,631	$	21,448	$	—		$	3,827,859
Intersegment revenues	512		371		—		(883		)	—
Total revenues	$	3,450,292	$	357,002	$	21,448	$	(883	)	$	3,827,859
Net income	$	399,637	$	7,903	$	3,291	$	—		$	410,831


^(a)	Operating revenues include $357 million and $367 million of affiliate electric revenue for the nine months ended Sept. 30, 2018 and 2017.


^(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the nine months ended Sept. 30, 2018 and 2017.


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost



	Three Months Ended Sept. 30
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,982		$	6,958		$	42		$	36
Interest cost ^(a)	8,805			10,177			768			854
Expected return on plan assets ^(a)	(14,542		)	(15,016		)	(95		)	(53		)
Amortization of prior service (credit) cost ^(a)	(29		)	265			(759		)	(759		)
Amortization of net loss ^(a)	9,614			9,902			596			506
Settlement charge ^(b)	34,907			—			—			—
Net periodic benefit cost	45,737			12,286			552			584
Costs not recognized due to the effects of regulation	(42,037		)	(4,899		)	—			—
Net benefit cost recognized for financial reporting	$	3,700		$	7,387		$	552		$	584



	Nine Months Ended Sept. 30
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	20,946		$	20,874		$	128		$	108
Interest cost ^(a)	26,413			30,531			2,306			2,562
Expected return on plan assets ^(a)	(43,625		)	(45,050		)	(287		)	(161		)
Amortization of prior service (credit) cost ^(a)	(86		)	795			(2,277		)	(2,277		)
Amortization of net loss ^(a)	28,843			29,706			1,786			1,520
Settlement charge ^(b)	34,907			—			—			—
Net periodic benefit cost	67,398			36,856			1,656			1,752
Costs not recognized due to the effects of regulation	(47,869		)	(14,696		)	—			—
Net benefit cost recognized for financial reporting	$	19,529		$	22,160		$	1,656		$	1,752


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

^(b)

A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the third quarter of 2018 as a result of lump-sum distributions during the 2018 plan year, NSP-Minnesota recorded a total pension settlement charge of $35 million, which was not recognized due to the effects of rate making. In the fourth quarter of 2017 as a result of lump-sum distributions during the 2017 plan year, NSP-Minnesota recorded a total pension settlement charge of $48 million, which was not recognized due to the effects of rate making.

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 and nine months ended Sept. 30, 2018 and 2017 were as follows:



	Three Months Ended Sept. 30, 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 July 1	$	(20,536	)	$	—	$	(3,663	)	$	(24,199	)
Other comprehensive income before reclassifications	5			—		—			5
Losses reclassified from net accumulated other comprehensive loss	172			—		56			228
Net current period other comprehensive income	177			—		56			233
Accumulated other comprehensive loss at Sept. 30	$	(20,359	)	$	—	$	(3,607	)	$	(23,966	)



	Three Months Ended Sept. 30, 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 July 1	$	(17,775	)	$	105	$	(2,609	)	$	(20,279	)
Other comprehensive income before reclassifications	22			—		—			22
Losses reclassified from net accumulated other comprehensive loss	379			—		39			418
Net current period other comprehensive income	401			—		39			440
Accumulated other comprehensive loss at Sept. 30	$	(17,374	)	$	105	$	(2,570	)	$	(19,839	)



	Nine Months Ended Sept. 30, 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	32			—			—			32
Losses (gains) reclassified from net accumulated other comprehensive loss	504			(128		)	163			539
Net current period other comprehensive income	536			(128		)	163			571
Accumulated other comprehensive loss at Sept. 30	$	(20,359	)	$	—		$	(3,607	)	$	(23,966	)



	Nine Months Ended Sept. 30, 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	)
Other comprehensive income before reclassifications	48			—		—			48
Losses reclassified from net accumulated other comprehensive loss	786			—		110			896
Net current period other comprehensive income	834			—		110			944
Accumulated other comprehensive loss at Sept. 30	$	(17,374	)	$	105	$	(2,570	)	$	(19,839	)

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Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2018 and 2017 were as follows:



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2018				Three Months Ended Sept. 30, 2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	267		^(a)	$	612		^(a)
Vehicle fuel derivatives	(39		)	^(b)	(11		)	^(b)
Total, pre-tax	228				601
Tax benefit	(56		)		(222		)
Total, net of tax	172				379
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	(20		)		(21		)
Total, net of tax	56				39
Marketable securities:
Realization of gains	—				—
Total, pre-tax	—				—
Tax expense	—				—
Total, net of tax	—				—
Total amounts reclassified, net of tax	$	228			$	418



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2018				Nine Months Ended Sept. 30, 2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	792		^(a)	$	1,304		^(a)
Vehicle fuel derivatives	(103		)	^(b)	(16		)	^(b)
Total, pre-tax	689				1,288
Tax benefit	(185		)		(502		)
Total, net of tax	504				786
Defined benefit pension and postretirement losses:
Amortization of net loss	375			^(c)	327			^(c)
Prior service credit	(147		)	^(c)	(147		)	^(c)
Total, pre-tax	228				180
Tax benefit	(65		)		(70		)
Total, net of tax	163				110
Marketable securities:
Realization of gains	(179		)		—
Total, pre-tax	(179		)		—
Tax expense	51				—
Total, net of tax	(128		)		—
Total amounts reclassified, net of tax	$	539			$	896


^(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 to the consolidated financial statements for details regarding these benefit plans.

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13. Revenues

NSP-Minnesota principally generates revenue from the generation, 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 Sept. 30, 2018
(Thousands of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	392,334	$	24,863	$	6,999	$	424,196
Commercial and industrial (C&I)	604,301		22,337		42		626,680
Other	8,694		—		590		9,284
Total retail	1,005,329		47,200		7,631		1,060,160
Wholesale	47,708		—		—		47,708
Transmission	66,166		—		—		66,166
Interchange	122,636		—		—		122,636
Other	4,586		5,280		—		9,866
Total revenue from contracts with customers	1,246,425		52,480		7,631		1,306,536
Alternative revenue and other	43,073		2,145		—		45,218
Total revenues	$	1,289,498	$	54,625	$	7,631	$	1,351,754

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	Three Months Ended Sept. 30, 2017
(Thousands of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	357,209	$	24,475	$	6,791	$	388,475
C&I	626,590		22,389		39		649,018
Other	9,327		—		536		9,863
Total retail	993,126		46,864		7,366		1,047,356
Wholesale	36,598		—		—		36,598
Transmission	65,667		—		—		65,667
Interchange	123,523		—		—		123,523
Other	8,632		1,589		—		10,221
Total revenue from contracts with customers	1,227,546		48,453		7,366		1,283,365
Alternative revenue and other	63,425		8,989		—		72,414
Total revenues	$	1,290,971	$	57,442	$	7,366	$	1,355,779



	Nine Months Ended Sept. 30, 2018
(Thousands of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,014,549	$	198,920	$	20,032	$	1,233,501
Commercial and industrial (C&I)	1,587,034		152,662		127		1,739,823
Other	27,052		—		2,743		29,795
Total retail	2,628,635		351,582		22,902		3,003,119
Wholesale	136,106		—		—		136,106
Transmission	180,915		—		—		180,915
Interchange	357,025		—		—		357,025
Other	22,164		10,808		—		32,972
Total revenue from contracts with customers	3,324,845		362,390		22,902		3,710,137
Alternative revenue and other	123,324		16,779		—		140,103
Total revenues	$	3,448,169	$	379,169	$	22,902	$	3,850,240



	Nine Months Ended Sept. 30, 2017
(Thousands of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	950,355	$	182,748	$	19,417	$	1,152,520
C&I	1,638,560		142,262		169		1,780,991
Other	25,384		—		1,862		27,246
Total retail	2,614,299		325,010		21,448		2,960,757
Wholesale	111,358		—		—		111,358
Transmission	175,803		—		—		175,803
Interchange	366,596		—		—		366,596
Other	22,040		4,286		—		26,326
Total revenue from contracts with customers	3,290,096		329,296		21,448		3,640,840
Alternative revenue and other	159,684		27,335		—		187,019
Total revenues	$	3,449,780	$	356,631	$	21,448	$	3,827,859

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements 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: changes in environmental laws and regulations; unusual weather and climate change, including compliance with any accompanying legislative and regulatory changes; ability to recover costs from customers; actions of credit rating agencies; 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; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; fuel costs; and employee work force factors.

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 and Natural Gas Margins

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).

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Results of Operations

NSP-Minnesota’s net income was approximately $405 million for 2018 year-to-date, compared with approximately $411 million for the same period of 2017. The decrease in earnings reflects higher depreciation expense due to increased invested capital and O&M expenses, partially offset by higher electric and natural gas margins due to favorable weather.

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. In addition, electric customers receive a credit for PTCs that are generated in a particular period. The following table details the electric revenues and margin:



	Nine Months Ended Sept. 30
(Millions of Dollars)	2018			2017
Electric revenues before impact of the TCJA	3,582			3,450
Electric fuel and purchased power	(1,308		)	(1,215		)
Electric margin before impact of the TCJA	$	2,274		$	2,235
Impact of the TCJA (offset as a reduction in income tax expense)	(130		)	—
Electric margin	2,144			2,235

The following tables summarize the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30:

Electric Revenues



(Millions of Dollars)	2018 vs. 2017
Interchange agreement billings with NSP-Wisconsin	$	(10	)
Conservation incentive	(9		)
Conservation program revenue (offset by expenses)	(7		)
Fuel and purchased power cost recovery	73
Trading	27
Retail sales growth (including Minnesota decoupling and sales true-up)	19
Estimated impact of weather (net of Minnesota decoupling)	17
Wholesale transmission revenue	17
Non-fuel riders	4
Other (net)	1
Total increase in electric revenues before impact of the TCJA	$	132
Impact of the TCJA (offset as a reduction in income tax expense)	(134		)
Total decrease in electric revenues	$	(2	)

Electric Margin



(Millions of Dollars)	2018 vs. 2017
Interchange agreement billings with NSP-Wisconsin	$	(17	)
Conservation incentive	(9		)
Conservation program revenue (offset by expenses)	(7		)
Purchased capacity costs	29
Retail sales growth (including Minnesota decoupling and sales true-up)	19
Estimated impact of weather (net of Minnesota decoupling)	17
Wholesale transmission margin	6
Non-fuel riders	4
Other (net)	(3		)
Total increase in electric margin before impact of the TCJA	$	39
Impact of the TCJA (offset as a reduction in income tax expense)	(130		)
Total decrease in electric margin	$	(91	)

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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:



	Nine Months Ended Sept. 30
(Millions of Dollars)	2018			2017
Natural gas revenues before impact of the TCJA	$	384		$	357
Cost of natural gas sold and transported	(212		)	(199		)
Natural gas margin before impact of the TCJA	$	172		$	158
Impact of the TCJA (offset as a reduction in income tax expense)	(5		)	—
Natural gas margin	$	167		$	158

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

Natural Gas Revenues



(Millions of Dollars)	2018 vs. 2017
Purchased natural gas adjustment clause recovery	$	13
Estimated impact of weather	10
Conservation program revenue (offset by expenses)	1
Other (net)	3
Total increase in natural gas revenues before impact of the TCJA	$	27
Impact of TCJA (offset as a reduction in income tax expense)	(5		)
Total increase in natural gas revenues	$	22

Natural Gas Margin



(Millions of Dollars)	2018 vs. 2017
Estimated impact of weather	$	10
Conservation program revenue (offset by expenses)	1
Other (net)	3
Total increase in natural gas margin before impact of TCJA	$	14
Impact of the TCJA (offset as a reduction in income tax expense)	(5		)
Total increase in natural gas margin	$	9

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $13 million, or 1.4 percent, for 2018 year-to-date, largely reflecting expense timing. The significant changes are summarized in the table below:



(Millions of Dollars)	2018 vs. 2017
Nuclear plant operations and amortization	$	(16	)
Business systems and contract labor	23
Plant generation costs	10
Distribution costs	4
Other (net)	(8		)
Total increase in O&M expenses	$	13


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


•	Business systems and contract labor costs increased due to growing network and storage needs, cybersecurity initiatives to support our customer strategy, and various projects and initiatives to improve business processes

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•	Plant generation costs increased primarily due to the timing of planned maintenance and overhauls at certain generation facilities; and


•	Distribution costs reflect high maintenance expenses, including vegetation management.

Conservation Program Expenses — Conservation program expenses decreased $4 million, or 4.9 percent, for 2018 year-to-date. 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 $25 million, or 4.8 percent, for 2018 year-to-date. The increase was primarily driven by capital expenditures due to planned system investments and amortization of certain regulatory assets.

Income Taxes — Income tax expense decreased $110 million for the first nine months of 2018 compared with the same period in 2017. The decrease was primarily driven by a lower federal tax rate due to the TCJA and lower pretax earnings and an increase in plant-related regulatory differences related to ARAM (net of deferrals). These were partially offset by a decrease in wind production tax credits and a higher tax benefit for the resolution of past appeals/audits in 2017. The ETR was 7.1 percent for the first nine months of 2018 compared with 25.5 percent for the same period in 2017. The lower ETR in 2018 is primarily due to the items referenced above. See Note 4 to the consolidated financial statements.

Public Utility Regulation

Except to the extent noted below and in Note 5 to the consolidated financial statements, 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 and in Item 2 of NSP-Minnesota’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2018 and June 30, 2018, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

Wind Development — In 2017, the MPUC approved NSP-Minnesota’s proposal to add 1,550 megawatts (MW) of new wind generation including ownership of 1,150 MW of wind generation.

Additionally, in April 2018, the MPUC approved NSP-Minnesota’s petition 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. NSP-Minnesota’s total capital investment for the Dakota Range is expected to be approximately $350 million.

In September 2018, NSP-Minnesota reached a settlement with the NDPSC Staff for these wind development projects. The settlement agreement is subject to NDPSC approval. A NDPSC decision is expected to be received by the end of 2018 or during the first quarter of 2019.

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 Department of Commerce. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 kilovolts transmission line from near Mankato, Minnesota to Winnebago, Minnesota. The project was estimated by MISO to cost $108 million. The project was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenged 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 June 2018, the Minnesota District Court granted the defendants’ motions to dismiss with prejudice. LSP Transmission filed an appeal to the 8th Circuit Court of Appeals in July 2018. It is uncertain when a decision will be rendered regarding this appeal.

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Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. See Note 12 to the financial statements 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 and Nuclear Power Operations included in Item 2 of NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2018 and June 30, 2018, 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 61 percent of its 2018 and approximately 24 percent of its 2019 enriched nuclear material requirements from sources that could be impacted by events in Ukraine and extended sanctions against 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 34 percent of its average enriched nuclear material requirements from sources that could be impacted by events in Ukraine and extended sanctions against Russia. 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 had enriched nuclear fuel materials in process with Westinghouse Electric Corporation (Westinghouse). Westinghouse filed for Chapter 11 bankruptcy protection in March 2017. NSP-Minnesota owned materials in Westinghouse’s inventory and had contracts in place under which Westinghouse agreed to provide certain services in the 2018 PI outage. Westinghouse also agreed to provide nuclear fuel assemblies for the 2018 PI outage under its nuclear fuel fabrication contract. Westinghouse announced on Jan. 4, 2018 it agreed to be acquired by Brookfield Business Partners LP (Brookfield) and other institutional partners. Brookfield’s acquisition of Westinghouse closed on Aug. 1, 2018. In connection with the acquisition, Brookfield assumed Westinghouse’s contracts with NSP-Minnesota. Based on Brookfield’s assumption of Westinghouse’s contracts, NSP-Minnesota does not expect Westinghouse’s bankruptcy or its assignment of NSP Minnesota’s contracts to Brookfield to materially impact NSP-Minnesota’s operational or financial performance.

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 and NSP-Minnesota’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2018 and June 30, 2018. In addition to the matters discussed below, see Note 5 to the 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.

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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.

In October 2018, the FERC issued an order addressing the four complaint proceedings involving the NETOs base ROE, including the case in which the DC Circuit vacated and remanded Opinion No. 531. Under a new approach, the FERC intends to dismiss an ROE complaint if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile, unless that presumption is sufficiently rebutted. The new approach establishes a composite zone of reasonableness based on equal weighting of the Discounted Cash Flows (DCF), Capital Asset Pricing Model (CAPM), and expected earnings models.

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 Sept. 30, 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.

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Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

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

Item 1A — RISK FACTORS

NSP-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.

Item 6 — EXHIBITS

* Indicates incorporation by reference



3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern States Power Co. (a Minnesota corporation) as Amended and Restated on Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 000-31387)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 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.

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SIGNATURES

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



		Northern States Power Company (a Minnesota corporation)

Oct. 26, 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)

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

Sept. 30, 2018

Dec. 31, 2017

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel