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, 2017~~March 31, 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

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



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

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

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

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



Class		Outstanding at ~~Oct.~~April 27, ~~2017~~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	2726
Item 4 —	Controls and Procedures	3431

PART II —	OTHER INFORMATION

Item 1 —	Legal Proceedings	3431
Item 1A —	Risk Factors	3531
Item 6 —	Exhibits	3532

SIGNATURES		3633

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

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

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended March 31
	2017			2016			2017			2016			2018			2017
Operating revenues
Electric, non-affiliates	$	1,167,447		$	1,161,259		$	3,083,182		$	2,973,350		$	945,291		$	955,341
Electric, affiliates	123,524			121,315			366,598			359,338			116,972			123,689
Natural gas	57,442			55,519			356,631			314,020			241,432			221,183
Other	7,366			7,286			21,448			21,404			7,056			6,927
Total operating revenues	1,355,779			1,345,379			3,827,859			3,668,112			1,310,751			1,307,140

Operating expenses
Electric fuel and purchased power	435,003			435,560			1,215,071			1,148,818			407,772			396,121
Cost of natural gas sold and transported	20,723			19,105			198,968			163,608			155,266			142,745
Cost of sales — other	4,313			4,898			13,085			14,185			4,181			4,178
Operating and maintenance expenses	288,770			315,298			909,381			954,334			292,295			308,626
Conservation program expenses	31,674			23,926			92,238			67,424			30,810			32,499
Depreciation and amortization	176,739			149,408			522,070			442,649			181,478			172,179
Taxes (other than income taxes)	62,220			49,763			191,989			186,100			67,545			68,324
Total operating expenses	1,019,442			997,958			3,142,802			2,977,118			1,139,347			1,124,672

Operating income	336,337			347,421			685,057			690,994			171,404			182,468

Other income (expense), net	2,120			(439		)	3,750			1,834			216			(1,534		)
Allowance for funds used during construction — equity	10,683			7,983			23,391			21,011			6,748			6,283

Interest charges and financing costs
Interest charges — includes other financing costs of $1,845, $1,822, $5,437 and $5,325, respectively	57,577			57,859			172,548			168,010
Interest charges — includes other financing costs of $1,815 and $1,786, respectively													57,352			57,264
Allowance for funds used during construction — debt	(5,383		)	(3,591		)	(11,909		)	(9,575		)	(3,435		)	(3,228		)
Total interest charges and financing costs	52,194			54,268			160,639			158,435			53,917			54,036

Income before income taxes	296,946			300,697			551,559			555,404			124,451			133,181
Income taxes	67,943			94,145			140,728			176,047			12,711			39,015
Net income	$	229,003		$	206,552		$	410,831		$	379,357		$	111,740		$	94,166

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)


	Three Months Ended Sept. 30					Nine Months Ended Sept. 30				Three Months Ended March 31
	2017		2016			2017		2016		2018			2017
Net income	$	229,003	$	206,552		$	410,831	$	379,357	$	111,740		$	94,166

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $21, $15, $70 and $45, respectively	39		19			110		57
Amortization of losses included in net periodic benefit cost, net of tax of $23 and $25, respectively										53			35

Derivative instruments:
Net fair value increase (decrease), net of tax of $16, $(1), $33 and $3, respectively	22		(1		)	48		5
Reclassification of losses to net income, net of tax of $222, $162, $502 and $467, respectively	379		213			786		657
Net fair value increase (decrease), net of tax of $2 and $0, respectively										5			—
Reclassification of losses to net income, net of tax of $65 and $139, respectively										167			203
	401		212			834		662		172			203
Marketable securities:
Reclassification of gains to net income, net of tax of $(51) and $0, respectively										(128		)	—

Other comprehensive income	440		231			944		719		97			238
Comprehensive income	$	229,443	$	206,783		$	411,775	$	380,076	$	111,837		$	94,404

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)


	Nine Months Ended Sept. 30,						Three Months Ended March 31,
	2017			2016			2018			2017
Operating activities
Net income	$	410,831		$	379,357		$	111,740		$	94,166
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	526,784			447,284			183,058			173,726
Nuclear fuel amortization	87,654			89,475			30,785			30,852
Deferred income taxes	98,125			129,410			9,474			52,411
Amortization of investment tax credits	(1,241		)	(1,260		)	(409		)	(414		)
Allowance for equity funds used during construction	(23,391		)	(21,011		)	(6,748		)	(6,283		)
Net realized and unrealized hedging and derivative transactions	(2,703		)	2,873			(1,006		)	1,744
Other, net	(1,072		)	—			(1,245		)	—
Changes in operating assets and liabilities:
Accounts receivable	(14,677		)	(46,294		)	(34,677		)	(25,483		)
Accrued unbilled revenues	33,465			26,660			76,058			69,893
Inventories	(4,265		)	5,709			45,261			32,678
Other current assets	35,591			24,431			39,247			(6,397		)
Accounts payable	(34,275		)	19,736			(47,971		)	(22,007		)
Net regulatory assets and liabilities	(15,467		)	57,452			74,143			1,513
Other current liabilities	(73,898		)	(3,947		)	34,793			(16,016		)
Pension and other employee benefit obligations	(55,548		)	(42,447		)	(60,804		)	(58,004		)
Change in other noncurrent assets	(3,585		)	(8,862		)	750			849
Change in other noncurrent liabilities	(30,704		)	(17,084		)	(18,304		)	(11,593		)
Net cash provided by operating activities	931,624			1,041,482			434,145			311,635

Investing activities
Utility capital/construction expenditures	(696,857		)	(833,845		)	(214,092		)	(277,125		)
Allowance for equity funds used during construction	23,391			21,011			6,748			6,283
Purchases investment securities	(965,086		)	(349,717		)	(184,565		)	(172,751		)
Proceeds from the sale of investment securities	948,558			327,378			179,472			167,658
Investments in utility money pool arrangement	(122,000		)	(492,000		)	(159,000		)	(87,000		)
Repayments from utility money pool arrangement	122,000			441,000			111,000			87,000
Other, net	(3,463		)	(1,262		)	(2,605		)	(4,565		)
Net cash used in investing activities	(693,457		)	(887,435		)	(263,042		)	(280,500		)

Financing activities
Repayments of short-term borrowings, net	(85,000		)	(223,000		)	(20,000		)	(46,000		)
Borrowings under utility money pool arrangement	516,000			424,000			69,000			25,000
Repayments under utility money pool arrangement	(466,000		)	(424,000		)	(154,000		)	(25,000		)
Proceeds from issuance of long-term debt	586,264			342,570
Repayments of long-term debt, including reacquisition premiums	(507,865		)	(11		)	(5		)	(10		)
Capital contributions from parent	123,247			96,628			49,622			89,487
Dividends paid to parent	(418,133		)	(306,209		)	(98,687		)	(89,428		)
Net cash used in financing activities	(251,487		)	(90,022		)	(154,070		)	(45,951		)

Net change in cash and cash equivalents	(13,320		)	64,025			17,033			(14,816		)
Cash and cash equivalents at beginning of period	47,595			42,605			43,781			47,595
Cash and cash equivalents at end of period	$	34,275		$	106,630		$	60,814		$	32,779

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(177,336	)	$	(169,382	)	$	(63,767	)	$	(68,511	)
Cash paid for income taxes, net	(60,911		)	(14,279		)
Cash received for income taxes, net							48,205			10,080
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	47,261		$	72,889		$	35,823		$	48,551

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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


	Sept. 30, 2017			Dec. 31, 2016			March 31, 2018			Dec. 31, 2017
Assets
Current assets
Cash and cash equivalents	$	34,275		$	47,595		$	60,814		$	43,781
Accounts receivable, net	344,528			329,481			380,488			345,110
Accounts receivable from affiliates	19,989			49,355			18,770			48,494
Investments in utility money pool arrangement							48,000			—
Accrued unbilled revenues	226,125			259,590			201,658			277,716
Inventories	349,578			345,192			292,491			337,712
Regulatory assets	253,876			186,266			283,438			276,392
Derivative instruments	47,177			22,028			14,564			25,230
Prepaid taxes							33,205			79,145
Prepayments and other	65,292			98,006			51,077			43,682
Total current assets	1,340,840			1,337,513			1,384,505			1,477,262

Property, plant and equipment, net	13,360,494			13,300,793			13,028,405			13,033,612

Other assets
Nuclear decommissioning fund and other investments	2,105,741			1,905,059			2,198,254			2,192,344
Regulatory assets	1,187,195			1,245,151			1,165,925			1,190,429
Derivative instruments	28,520			24,678			29,902			28,102
Other	13,217			9,086			15,393			4,142
Total other assets	3,334,673			3,183,974			3,409,474			3,415,017
Total assets	$	18,036,007		$	17,822,280		$	17,822,384		$	17,925,891

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	7		$	10		$	7		$	7
Short-term debt	—			85,000			—			20,000
Borrowings under utility money pool arrangement	50,000			—			—			85,000
Accounts payable	292,970			371,589			308,039			368,342
Accounts payable to affiliates	50,745			59,216			54,787			80,070
Regulatory liabilities	98,587			60,779			84,405			83,403
Taxes accrued	235,999			241,100			295,569			229,335
Accrued interest	52,115			71,012			52,517			65,896
Dividends payable to parent	88,461			89,428			84,558			98,687
Derivative instruments	18,045			16,606			19,045			17,697
Customer deposits	103,549			110,244			99,293			95,369
Other	152,919			150,244			145,054			152,965
Total current liabilities	1,143,397			1,255,228			1,143,274			1,296,771

Deferred credits and other liabilities
Deferred income taxes	2,947,022			2,788,752			1,617,720			1,612,341
Deferred investment tax credits	22,935			24,175			22,119			22,528
Regulatory liabilities	491,385			489,825			2,013,845			1,978,527
Asset retirement obligations	2,543,497			2,452,567			2,109,092			2,083,874
Derivative instruments	105,963			116,804			98,692			102,742
Pension and employee benefit obligations	313,772			368,922			269,870			331,087
Other	94,372			127,283			90,907			89,440
Total deferred credits and other liabilities	6,518,946			6,368,328			6,222,245			6,220,539

Commitments and contingencies
Capitalization
Long-term debt	4,932,970			4,843,155			4,934,017			4,933,011
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively	10			10
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at March 31, 2018 and Dec. 31, 2017, respectively							10			10
Additional paid in capital	3,525,612			3,435,096			3,600,234			3,580,234
Retained earnings	1,934,911			1,941,246			1,947,044			1,919,863
Accumulated other comprehensive loss	(19,839		)	(20,783		)	(24,440		)	(24,537		)
Total common stockholder’s equity	5,440,694			5,355,569			5,522,848			5,475,570
Total liabilities and equity	$	18,036,007		$	17,822,280		$	17,822,384		$	17,925,891

See Notes to Consolidated Financial Statements

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, 2017~~March 31, 2018 and Dec. 31, ~~2016;~~2017; the results of its operations, including the components of net income and comprehensive income, for the three ~~and nine~~ months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016;~~2017; and its cash flows for the ~~nine~~three months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016.~~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, 2017~~March 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, ~~2016~~2017 balance sheet information has been derived from the audited ~~2016~~2017 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, ~~2016.~~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, ~~2016,~~2017, filed with the SEC on Feb. ~~24, 2017.~~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, ~~2016,~~2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

~~Revenue Recognition~~Leases — —I ~~In May 2014,~~n February 2016, the Financial Accounting Standards Board (FASB) issued ~~Revenue from Contracts with Customers,~~Leases, Topic ~~606~~842 (Accounting Standards Update (ASU) ~~No. 2014-09)~~, which provides a new framework for the recognition of revenue. NSP-Minnesota expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. NSP-Minnesota currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

~~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 eliminates the available-for-sale classification for marketable equity securities and also replaces 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 to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Minnesota expects that 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, currently classified as available-for-sale, will continue to be deferred to a regulatory asset, and that the overall impacts of the Jan. 1, 2018 adoption will not be material.

~~Leases —~~I~~n February 2016, the FASB issued~~ ~~Leases, Topic 842 (ASU~~ No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. NSP-Minnesota has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the ~~standard.~~standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered into prior to Jan. 1, ~~2017~~2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. NSP-Minnesota expects that similar agreements entered into after Dec. 31, ~~2016~~2018 will generally qualify as leases under the new ~~standard, but has not yet completed its evaluation of certain other contracts, including arrangements~~standard.

Recently Adopted

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

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. NSP-Minnesota implemented the guidance on Jan. 1, 2018. As a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, historically classified as ~~land easements.~~available-for-sale, continue to be deferred to a regulatory asset, and the overall adoption impacts were not material.

Presentation of Net Periodic Benefit Cost — InIn 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. ~~NSP-Minnesota expects that as~~As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the ~~current~~historical ratemaking treatment, and ~~that~~ the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. ~~This~~NSP-Minnesota implemented the new guidance ~~will be effective~~on Jan. 1, 2018, and as a result, $3.4 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for ~~interim and annual reporting~~the three months ended March 31, 2017. Under a practical expedient permitted by the standard, NSP-Minnesota used benefit cost amounts disclosed for prior periods ~~beginning after Dec. 15, 2017.~~as the basis for retrospective application.


3.	Selected Balance Sheet Data


(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016			March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	364,970		$	349,449		$	401,941		$	366,388
Less allowance for bad debts	(20,442		)	(19,968		)	(21,453		)	(21,278		)
	$	344,528		$	329,481		$	380,488		$	345,110


(Thousands of Dollars)		Sept. 30, 2017		Dec. 31, 2016		March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies		$	216,850	$	214,234	$	208,571	$	209,236
Fuel		91,555		97,527		78,668		94,483
Natural gas	��	41,173		33,431		5,252		33,993
		$	349,578	$	345,192	$	292,491	$	337,712


(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016			March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	17,323,127		$	17,059,993		$	17,132,020		$	17,024,925
Natural gas plant	1,340,688			1,311,235			1,383,329			1,370,330
Common and other property	803,599			710,958			726,591			724,066
Construction work in progress	508,306			509,891			547,219			530,126
Total property, plant and equipment	19,975,720			19,592,077			19,789,159			19,649,447
Less accumulated depreciation	(7,015,522		)	(6,682,418		)	(7,136,022		)	(7,018,249		)
Nuclear fuel	2,668,586			2,571,770			2,701,050			2,697,412
Less accumulated amortization	(2,268,290		)	(2,180,636		)	(2,325,782		)	(2,294,998		)
	$	13,360,494		$	13,300,793		$	13,028,405		$	13,033,612


4.	Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2016~~2017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

~~Federal Loss Carryback Claims~~ ~~— In 2012-2015, NSP-Minnesota identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond~~

Total income tax expense from operations differs from the ~~typical two-year carryback period. As a result of a higher~~amount computed by applying the statutory federal income tax rate ~~in prior years, NSP-Minnesota recognized a~~to income before income tax ~~benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.~~expense. The following reconciles such differences:



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


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


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

Federal Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s ~~2009 through 2011 and 2012 through 2013~~ federal income tax returns ~~following extensions, expires in June 2018 and October 2018, respectively.~~expire as follows:



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

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback ~~claims that would have resulted~~and in ~~$14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of~~ 2015 the IRS forwarded the issue to the Office of Appeals ~~(Appeals)~~(“Appeals”). In ~~the third quarter of~~ 2017 Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. As of March 31, 2018, the case has been forwarded to the Joint Committee on Taxation.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of ~~Sept. 30, 2017,~~March 31, 2018, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is ~~unknown.~~uncertain.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of ~~Sept. 30, 2017,~~March 31, 2018, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In 2016, the state of Minnesota began an audit of years 2010 through 2014. As of ~~Sept. 30, 2017,~~March 31, 2018, Minnesota had not proposed any material ~~adjustments, and there were no other state income tax audits in progress.~~adjustments.

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

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


(Millions of Dollars)	Sept. 30, 2017		Dec. 31, 2016		March 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	9.8	$	21.5	$	10.6	$	10.2
Unrecognized tax benefit — Temporary tax positions	8.1		39.3		7.9		7.9
Total unrecognized tax benefit	$	17.9	$	60.8	$	18.5	$	18.1

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


(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016			March 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(12.5	)	$	(19.3	)	$	(14.6	)	$	(12.8	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audit resumes, the Minnesota audit progresses, and other state audits resume. As the IRS Appeals and Minnesota audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $7$12 million.

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


(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016			March 31, 2018			Dec. 31, 2017
Payable for interest related to unrecognized tax benefits at beginning of period	$	(2.0	)	$	(0.2	)	$	(0.9	)	$	(2.0	)
Interest income (expense) related to unrecognized tax benefits recorded during the period	1.1			(1.8		)	(1.0		)	1.1
Payable for interest related to unrecognized tax benefits at end of period	$	(0.9	)	$	(2.0	)	$	(1.9	)	$	(0.9	)

No amounts were accrued for penalties related to unrecognized tax benefits as of ~~Sept. 30, 2017~~March 31, 2018 or Dec. 31, ~~2016.~~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, ~~2016 and in Note 5 to NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30,~~ 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

~~Minnesota 2016 Multi-Year Electric Rate Case~~ ~~— In June 2017, the MPUC issued a written order. NSP-Minnesota estimated the total rate increase to be approximately $245 million over the four-year period covering 2016-2019.~~

~~Key terms:~~

~~Four-year period covering 2016-2019;~~

~~Annual sales true-up with decoupling subject to~~The Minnesota Public Utility Commission (MPUC) opened a ~~3 percent cap;~~

~~Return~~TCJA docket and issued a request for information on ~~equity (ROE)~~the impacts of ~~9.2 percent and an equity ratio of 52.5 percent;~~

~~Nuclear related costs will not be considered provisional;~~

~~Continued use of all existing riders, however no new riders may be utilized during~~ the ~~four-year term;~~

~~Deferral of incremental 2016 property tax expense above a fixed threshold to~~TCJA in January 2018. In March 2018, ~~and 2019;~~

~~Four-year stay-out provision for rate cases;~~

~~Property tax true-up mechanism for 2017-2019; and~~

~~Capital expenditure true-up mechanism for 2016-2019.~~

(Millions of Dollars, Incremental) 2016 2017 2018 2019 Total
Revenues $ 74.99
$ 59.86
$ —
$ 50.12
$ 184.97
NSP-Minnesota’s sales true-up 59.95
—
—
(0.20 ) 59.75
Total rate impact $ 134.94
$ 59.86
$ —
$ 49.92
$ 244.72

In September 2017, the MPUC ordered NSP-Minnesota to collect final rates beginning March 1, 2017 (requested date was Jan. 1, 2017). As a result, NSP-Minnesota estimates the adjusted total rate increase to be approximately $240 million over the four-year period covering 2016-2019.

~~Annual Automatic Adjustment of Fuel Clause Charges —~~ In May 2017, the MPUC voted to disallow approximately $4.4 million of replacement energy costs for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction in 2015. This disallowance was recognized in the second quarter of 2017. In September 2017, the Minnesota Department of Commerce (DOC) recommended adjusting rates or implementing refunds for the current tax impacts and incorporating the deferred tax impacts in each utility’s next rate case.

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

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

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

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

Pending Regulatory Proceedings — MPUC

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

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

Pending Regulatory Proceeding — ~~Federal Energy Regulatory Commission (FERC)~~FERC

~~Midcontinent Independent System Operator, Inc. (MISO)~~MISO ROE Complaints — In November 2013, a group of customers filed a complaint at the FERC against MISO ~~transmission owners (TOs),~~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 ~~December 2015, an administrative law judge (ALJ) recommended~~September 2016, the FERC ~~approve~~approved an Administrative Law Judge (ALJ) recommendation that MISO TOs be granted a base ROE of 10.32 percent for the MISO TOs. The ALJ found the existing 12.38 percent ROE to be unjust and unreasonable. The recommended 10.32 percent ROE applied a FERC ROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE using the methodology adopted by FERC in ~~an order issued in September 2016.~~June 2014 (Opinion 531). This ROE would be applicable for the ~~15 month~~15-month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent, including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action.

In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any RTO adder was filed, ~~with the FERC,~~ resulting in a second period of potential ~~refund~~refunds from Feb. 12, 2015 to May 11, 2016. In June 2016, ~~the~~an ALJ recommended a base ROE of 9.7 percent, applying the ~~methodology adopted by~~FERC Opinion 531 methodology. Various parties filed exceptions to the ALJ recommendation, and FERC ~~in Opinion 531. A final FERC decision on the second ROE complaint was expected later in 2017, but in~~action is pending. In April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) ~~by opinion,~~ 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. The MISO TOs are evaluating the impact of the D.C. Circuit ruling on the November 2013 and February 2015 ROE complaints. In September 2017, certain MISO TOs (not including NSP-Minnesota and NSP-Wisconsin) filed a motion to dismiss the second ROE complaint. The motion to dismiss is pending FERC action.

~~As of Sept. 30, 2017,~~ NSP-Minnesota has ~~processed the refunds for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the September 2016 FERC order. NSP-Minnesota has also~~ recognized a current refund liability consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, ~~2016 and in Notes 5 and 6 to the consolidated financial statements included in NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30,~~ 2017, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

PPAs

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

NSP-Minnesota had approximately 1,069 ~~megawatts (MW)~~MW of capacity under long-term PPAs as of ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, with entities that have been determined to be variable interest entities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2028.

Guarantees

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

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


(Millions of Dollars)	Sept. 30, 2017		Dec. 31, 2016		March 31, 2018		Dec. 31, 2017
Guarantee issued and outstanding	$	4.8	$	4.8	$	4.8	$	4.8

Environmental Contingencies

Fargo, N.D. Manufactured Gas Plant (MGP) Site — In May 2015, underground pipes, tars and impacted soils were discovered in a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials ~~from the right-of-way~~ and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). ~~NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed.~~ The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January ~~2017.~~2017, which involves targeted source removal of impacted soils and historic MGP infrastructure. It is anticipated that remediation activities will be performed in 2018, although the timing and final scope of remediation is dependent on whether reasonable access is provided to NSP-Minnesota to perform and implement the approved cleanup plan. Access agreements have been reached with a majority of the property owners in the area to perform the work.2018. NSP-Minnesota has also initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until ~~January~~May 31, 2018.

~~As of Sept. 30, 2017 and Dec. 31, 2016,~~ NSP-Minnesota had recorded aan estimated liability of ~~$16.2~~$15 million as of March 31, 2018 and ~~$11.3~~$16 million ~~respectively,~~as of Dec. 31, 2017, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately ~~$23.0~~$22 million, of which approximately ~~$6.8~~$7 million has been spent. ~~In December 2015,~~NSP-Minnesota has deferred Fargo MGP Site costs allocable to the North Dakota jurisdiction, or approximately 88 percent of all remediation costs, as approved by the North Dakota Public Service Commission (NDPSC) ~~approved NSP-Minnesota’s~~. In December 2017, NSP-Minnesota filed a request with the MPUC to defer ~~costs associated with the Fargo~~post-2017 MGP ~~Site, resulting in deferral of all investigation and response costs with the exception of approximately 12 percent~~remediation expenditures allocable to the Minnesota ~~jurisdiction. Uncertainties related to~~jurisdiction, including the ~~liability recognized include obtaining access to perform~~Fargo MGP site. In March 2018, the ~~approved remediation (including~~DOC recommended that the ~~prospective purchase of the historic MGP property), and the potential for contributions from entities that may be identified as potentially responsible parties (PRPs).~~

MPUC deny NSP-Minnesota’s deferral request. A MPUC decision is expected mid-2018.

Other MGP, ~~and~~ Landfill or Disposal Sites — NSP-Minnesota is currently involved in investigating and/or remediating several MGP, landfill or other ~~MGP and landfill~~disposal sites. NSP-Minnesota has identified ~~six~~seven sites, in addition to the site in Fargo, N.D., where ~~former MGP or landfill disposal activities have or may have resulted in site~~ contamination is present and ~~are under current~~where investigation and/or ~~remediation. At some or all of these sites, there~~remediation activities are ~~other~~currently underway. Other parties ~~that~~ may have responsibility for some portion of ~~any remediation.~~the investigation and/or remediation activities. NSP-Minnesota anticipates that ~~the majority of the~~these investigation or remediation ~~at these sites~~activities will continue through at least 2018. NSP-Minnesota had accrued ~~$1.1~~$3 million ~~and $0.2 million for these sites~~ as of ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016, respectively.~~2017 for all of these sites. There may be insurance recovery and/or recovery from other PRPs tothat will offset any costs incurred. ~~NSP-Minnesota~~Xcel Energy anticipates that any ~~significant~~ amounts ~~incurred~~spent will be fully recovered from customers.

~~Environmental Requirements~~

~~Water and Waste~~

~~Federal Clean Water Act (CWA) Waters of the United States Rule~~ —In 2015, the United States Environmental Protection Agency (EPA) and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in the first quarter of 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

~~Federal CWA Effluent Limitations Guidelines (ELG)~~ —In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In September 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport water until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

~~Air~~

~~Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP)~~ — In 2015, the EPA issued its final rule for existing power plants. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.

The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the Clean Air Act (CAA). The EPA will take public comment on the proposal for 60 days. The EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing electric generating units.

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, 2017			Year Ended Dec. 31, 2016			Three Months Ended March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	50			—			—			85
Average amount outstanding	50			16			14			25
Maximum amount outstanding	116			225			99			142
Weighted average interest rate, computed on a daily basis	1.11		%	0.69		%	1.59		%	1.14		%
Weighted average interest rate at period end	1.11			N/A			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, 2017			Year Ended Dec. 31, 2016			Three Months Ended March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	500		$	500		$	500		$	500
Amount outstanding at period end	—			85			—			20
Average amount outstanding	51			73			83			62
Maximum amount outstanding	204			353			195			237
Weighted average interest rate, computed on a daily basis	1.33		%	0.65		%	1.73		%	1.10		%
Weighted average interest rate at period end	N/A			0.94			N/A			1.93

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, there were ~~$21~~$25 million and ~~$11~~$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, 2017,~~March 31, 2018, NSP-Minnesota had the following committed credit facility available (in millions of dollars):


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Credit Facility ^(a)	Drawn ^(b)		Available
$	500	$	21	$	479	500	$	25	$	475


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


^(b)	Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016.~~

~~Long-Term Borrowings~~

~~In September 2017, NSP-Minnesota issued $600 million of 3.60 percent first mortgage bonds due Sept. 15, 2047.~~

~~Debt Redemption~~

On Sept. 29, 2017, NSP-Minnesota reacquired $500 million of debt with a coupon rate of 5.25 percent and an original maturity date of March 1, 2018. The redemption resulted in payment of an early redemption premium of $7.9 million which was deferred as a regulatory asset.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.

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 PIPrairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other ~~investments – all classified as available-for-sale.~~investments. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

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

Unrealized gains for the nuclear decommissioning fund were ~~$511.7~~$543 million and ~~$378.6~~$560 million ~~at Sept. 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016,~~2017, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were ~~$10.3~~$18 million and ~~$46.9~~$7 million ~~at Sept. 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016,~~2017, respectively.

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund ~~at Sept. 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016:~~2017:


	Sept. 30, 2017												March 31, 2018
			Fair Value												Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total		Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	32,727	$	32,727	$	—	$	—	$	—	$	32,727	$	41,250	$	41,250	$	—	$	—	$	—	$	41,250
Commingled funds:
Non U.S. equities	257,487		204,502		—		—		86,654		291,156		270,384		226,127		—		—		90,369		316,496
Emerging market debt funds	97,285		—		—		—		106,842		106,842		157,087		—		—		—		163,868		163,868
Private equity investments	139,185		—		—		—		192,098		192,098		141,991		—		—		—		198,060		198,060
Real estate	129,219		—		—		—		195,506		195,506		118,189		—		—		—		185,851		185,851
Other commingled funds	146,179		14,964		—		—		145,313		160,277		3,902		900		—		—		2,975		3,875
Debt securities:
Government securities	45,310		—		44,944		—		—		44,944		78,197		—		77,505		—		—		77,505
U.S. corporate bonds	251,138		—		252,868		—		—		252,868		325,042		—		320,812		—		—		320,812
Non U.S. corporate bonds	46,245		—		46,611		—		—		46,611		54,637		—		53,151		—		—		53,151
Equity securities:
U.S. equities	258,075		509,564		—		—		—		509,564		277,853		556,816		—		—		—		556,816
Non U.S. equities	152,575		224,139		—		—		—		224,139		152,670		228,903		—		—		—		228,903
Total	$	1,555,425	$	985,896	$	344,423	$	—	$	726,413	$	2,056,732	$	1,621,202	$	1,053,996	$	451,468	$	—	$	641,123	$	2,146,587


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$49.0~~$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, 2016												Dec. 31, 2017
			Fair Value												Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total		Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	20,379	$	20,379	$	—	$	—	$	—	$	20,379	$	28,741	$	28,741	$	—	$	—	$	—	$	28,741
Commingled funds:
Non U.S. equities	260,877		133,126		—		—		112,233		245,359		263,694		216,551		—		—		89,857		306,408
Emerging market debt funds	93,597		—		—		—		97,543		97,543		156,057		—		—		—		166,375		166,375
Commodity funds	106,571		—		—		—		92,091		92,091
Private equity investments	132,190		—		—		—		190,462		190,462		141,413		—		—		—		198,037		198,037
Real estate	128,630		—		—		—		187,647		187,647		130,787		—		—		—		201,842		201,842
Other commingled funds	151,048		—		—		—		159,489		159,489		9,340		6,286		—		—		2,975		9,261
Debt securities:
Government securities	32,764		—		31,965		—		—		31,965		67,760		—		69,413		—		—		69,413
U.S. corporate bonds	104,913		—		105,772		—		—		105,772		319,809		—		322,129		—		—		322,129
Non U.S. corporate bonds	21,751		—		21,672		—		—		21,672		50,121		—		50,102		—		—		50,102
Municipal bonds	13,609		—		13,786		—		—		13,786
Mortgage-backed securities	2,785		—		2,816		—		—		2,816
Equity securities:
U.S. equities	270,779		473,400		—		—		—		473,400		271,166		556,974		—		—		—		556,974
Non U.S. equities	189,100		218,381		—		—		—		218,381		151,961		233,999		—		—		—		233,999
Total	$	1,528,993	$	845,286	$	176,011	$	—	$	839,465	$	1,860,762	$	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 ~~$44.3~~$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,~~March 31, 2018 and 2017 ~~and 2016~~ there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, atas of ~~Sept. 30, 2017~~March 31, 2018:


	Final Contractual Maturity										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		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	$	—	$	1,275	$	2,303	$	41,366	$	44,944	$	—	$	9,124	$	2,318	$	66,063	$	77,505
U.S. corporate bonds	3,834		64,119		150,741		34,174		252,868		2,886		87,565		173,634		56,727		320,812
Non U.S. corporate bonds	—		13,793		26,651		6,167		46,611		—		16,263		33,328		3,560		53,151
Debt securities	$	3,834	$	79,187	$	179,695	$	81,707	$	344,423	$	2,886	$	112,952	$	209,280	$	126,350	$	451,468

Rabbi Trusts

In ~~June~~ 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, 2017~~March 31, 2018 and Dec. 31, ~~2016:~~2017:


	Sept. 30, 2017										March 31, 2018
			Fair Value										Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total		Cost		Level 1		Level 2		Level 3		Total
Rabbi Trust ^(a)
Cash equivalents	$	391	$	391	$	—	$	—	$	391	$	393	$	393	$	—	$	—	$	393
Mutual funds	10,075		10,963		—		—		10,963		10,373		11,151		—		—		11,151
Total	$	10,466	$	11,354	$	—	$	—	$	11,354	$	10,766	$	11,544	$	—	$	—	$	11,544


	Dec. 31, 2016										Dec. 31, 2017
			Fair Value										Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total		Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	7,459	$	7,459	$	—	$	—	$	7,459	$	783	$	783	$	—	$	—	$	783
Mutual funds	1,663		1,901		—		—		1,901		10,332		11,283		—		—		11,283
Total	$	9,122	$	9,360	$	—	$	—	$	9,360	$	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, 2017,~~March 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included ~~$0.6~~$0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas related instruments, including derivatives. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives.

At ~~Sept. 30, 2017,~~March 31, 2018, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. NSP-Minnesota enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three ~~and nine~~ months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016.~~2017.

At ~~Sept. 30, 2017,~~March 31, 2018, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

The following table details the gross notional amounts of commodity forwards, options and FTRs at ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016:~~2017:


(Amounts in Thousands) ^(a)(b)	Sept. 30, 2017	Dec. 31, 2016	March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	58,582	37,805	32,451	41,711
Million British thermal units of natural gas	47,329	79,520	18,330	23,829
Gallons of vehicle fuel	300	—	180	240


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


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

The following tables detail the impact of derivative activity during the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2018 and 2017 ~~and 2016~~ on accumulated other comprehensive loss, regulatory assets and liabilities and income:

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)
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 ) —
—

—

Total $ —
$ 19,833
$ —
$ (5,356 ) $ 1,493

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



	Three Months Ended Sept. 30, 2016																Three Months Ended March 31, 2018
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains Recognized During the Period in Income				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)						Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities				Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges													Pre-Tax Gains Recognized During the Period in Income
Interest rate	$	—		$	—		$	350	^(a)	$	—		$	—			$	—		$	—			$	261		^(a)	$	—			$	—
Vehicle fuel and other commodity	(2		)	—			25		^(b)	—			—				7			—				(29		)	^(b)	—				—
Total	$	(2	)	$	—		$	375		$	—		$	—			$	7		$	—			$	232			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	1,808	^(c)		$	—		$	—			$	—			$	—			$	2,740		^(c)
Electric commodity	—			15,301			—			2,044		^(d)	—				—			(4,259		)		—				2,169			^(d)	—
Natural gas commodity	—			(792		)	—			—			—				—			848				—				(520		)	^(e)	(404		)	^(e)
Total	$	—		$	14,509		$	—		$	2,044		$	1,808			$	—		$	(3,411	)		$	—			$	1,649			$	2,336



	Nine Months Ended Sept. 30, 2016																Three Months Ended March 31, 2017
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income					Pre-Tax Fair Value (Losses) Recognized During the Period in:							Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and(Liabilities)							Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities				Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	1,042	^(a)	$	—		$	—				$	—		$	—			$	342	^(a)	$	—			$	—
Vehicle fuel and other commodity	8		—			82		^(b)	—			—
Total	$	8	$	—		$	1,124		$	—		$	—				$	—		$	—			$	342		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	3,069		^(c)		$	—		$	—			$	—		$	—			$	622		^(c)
Electric commodity	—		12,550			—			26,328		^(d)	—					—			(1,247		)		—			(2,788		)	^(d)	—
Natural gas commodity	—		(1,045		)	—			3,460		^(e)	(1,595		)	^(e)		—			(665		)		—			698			^(e)	(945		)	^(e)
Total	$	—	$	11,505		$	—		$	29,788		$	1,474				$	—		$	(1,912	)		$	—		$	(2,090	)		$	(323	)


^(a)	Amounts are recorded to interest charges.


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


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


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


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

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three ~~and nine~~ months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016.~~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, 2017, five~~March 31, 2018, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising ~~$23.9~~$45.1 million or 3358 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. ~~Four~~Two of the 10 most significant counterparties, comprising ~~$28.0~~$15.8 million or 3820 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. ~~The one remaining significant counterparty, comprising $0.9 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on ratings from internal analysis.~~ 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, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, there were no derivative instruments in a material liability position with such underlying contract provisions.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016.~~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, 2017:~~March 31, 2018:


	Sept. 30, 2017														March 31, 2018
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value							Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total				Level 1		Level 2		Level 3				Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	56	$	—	$	56		$	—		$	56	$	—	$	85	$	—		$	85	$	—		$	85
Other derivative instruments:
Commodity trading	1,297		8,933		81		10,311			(4,040		)	6,271		598		14,123		205			14,926		(6,931		)	7,995
Electric commodity	—		—		39,932		39,932			(261		)	39,671		—		—		5,765			5,765		(33		)	5,732
Natural gas commodity	—		427		—		427			—			427
Total current derivative assets	$	1,297	$	9,416	$	40,013	$	50,726		$	(4,301	)	46,425		$	598	$	14,208	$	5,970		$	20,776	$	(6,964	)	13,812
PPAs ^(a)													752														752
Current derivative instruments													$	47,177													$	14,564
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	11	$	—	$	11		$	—		$	11
Other derivative instruments:
Commodity trading	84		30,103		5,661		35,848			(7,465		)	28,383		602		35,308		8,048			43,958		(14,170		)	29,788
Total noncurrent derivative assets	$	84	$	30,114	$	5,661	$	35,859		$	(7,465	)	28,394		$	602	$	35,308	$	8,048		$	43,958	$	(14,170	)	29,788
PPAs ^(a)													126														114
Noncurrent derivative instruments													$	28,520													$	29,902


	Sept. 30, 2017														March 31, 2018
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value							Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total				Level 1		Level 2		Level 3				Total			Counterparty Netting ^(b)
Current derivative liabilities							Fair Value Total
Other derivative instruments:										Counterparty Netting ^(b)												Fair Value Total
Commodity trading	$	1,146	$	7,100	$	—	$	8,246		$	(4,307	)	$	3,939	$	647	$	11,643	$	—		$	12,290	$	(7,351	)	$	4,939
Electric commodity	—		—		261		261			(261		)	—		—		—		34			34		(34		)	—
Total current derivative liabilities	$	1,146	$	7,100	$	261	$	8,507		$	(4,568	)	3,939		$	647	$	11,643	$	34		$	12,324	$	(7,385	)	4,939
PPAs ^(a)													14,106														14,106
Current derivative instruments													$	18,045													$	19,045
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	52	$	22,666	$	—	$	22,718		$	(10,130	)	$	12,588	$	1,868	$	27,604	$	468		$	29,940	$	(17,698	)	$	12,242
Total noncurrent derivative liabilities	$	52	$	22,666	$	—	$	22,718		$	(10,130	)	12,588		$	1,868	$	27,604	$	468		$	29,940	$	(17,698	)	12,242
PPAs ^(a)													93,375														86,450
Noncurrent derivative instruments													$	105,963													$	98,692


^(a)	During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at ~~Sept. 30, 2017.~~March 31, 2018. At ~~Sept. 30, 2017,~~March 31, 2018, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of ~~$2.9~~$3.9 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, ~~2016:~~2017:


	Dec. 31, 2016														Dec. 31, 2017
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value							Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total				Level 1		Level 2		Level 3				Total			Counterparty Netting ^(b)
Current derivative assets							Fair Value Total
Derivatives designated as cash flow hedges:																						Fair Value Total
Vehicle fuel and other commodity															$	—	$	107	$	—		$	107	$	—		$	107
Other derivative instruments:										Counterparty Netting ^(b)
Commodity trading	$	12,053	$	8,651	$	—	$	20,704		$	(15,500	)	$	5,204	$	1,691	$	17,144	$	142		$	18,977	$	(11,744	)	$	7,233
Electric commodity	—		—		15,997		15,997			(677		)	15,320		—		—		17,581			17,581		(425		)	17,156
Natural gas commodity	—		912		—		912			—			912		—		77		—			77		—			77
Total current derivative assets	$	12,053	$	9,563	$	15,997	$	37,613		$	(16,177	)	21,436		$	1,691	$	17,328	$	17,723		$	36,742	$	(12,169	)	24,573
PPAs ^(a)													592														657
Current derivative instruments													$	22,028													$	25,230
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	100	$	31,029	$	—	$	31,129		$	(7,323	)	$	23,806	$	—	$	29,121	$	5,363		$	34,484	$	(6,502	)	$	27,982
Total noncurrent derivative assets	$	100	$	31,029	$	—	$	31,129		$	(7,323	)	23,806		$	—	$	29,121	$	5,363		$	34,484	$	(6,502	)	27,982
PPAs ^(a)													872														120
Noncurrent derivative instruments													$	24,678													$	28,102


	Dec. 31, 2016														Dec. 31, 2017
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value							Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total				Level 1		Level 2		Level 3				Total			Counterparty Netting ^(b)
Current derivative liabilities							Fair Value Total
Other derivative instruments:										Counterparty Netting ^(b)												Fair Value Total
Commodity trading	$	12,397	$	5,964	$	—	$	18,361		$	(15,837	)	$	2,524	$	1,713	$	13,853	$	—		$	15,566	$	(11,974	)	$	3,592
Electric commodity	—		—		677		677			(677		)	—		—		—		425			425		(425		)	—
Total current derivative liabilities	$	12,397	$	5,964	$	677	$	19,038		$	(16,514	)	2,524		$	1,713	$	13,853	$	425		$	15,991	$	(12,399	)	3,592
PPAs ^(a)													14,082														14,105
Current derivative instruments													$	16,606													$	17,697
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	89	$	23,424	$	—	$	23,513		$	(10,727	)	$	12,786	$	—	$	22,163	$	—		$	22,163	$	(9,334	)	$	12,829
Total noncurrent derivative liabilities	$	89	$	23,424	$	—	$	23,513		$	(10,727	)	12,786		$	—	$	22,163	$	—		$	22,163	$	(9,334	)	12,829
PPAs ^(a)													104,018														89,913
Noncurrent derivative instruments													$	116,804													$	102,742


^(a)	During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, ~~2016.~~2017. At Dec. 31, ~~2016,~~2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of ~~$3.7~~$3.1 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three ~~and nine~~ months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016:~~2017:


	Three Months Ended Sept. 30
(Thousands of Dollars)	2017			2016
Balance at July 1	$	40,572		$	23,488
Settlements	(23,186		)	(26,192		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	527			—
Net gains recognized as regulatory assets and liabilities	27,500			27,163
Balance at Sept. 30	$	45,413		$	24,459

	Nine Months Ended Sept. 30						Three Months Ended March 31
(Thousands of Dollars)	2017			2016			2018			2017
Balance at Jan. 1	$	15,320		$	12,969		$	22,661		$	15,320
Purchases	40,740			27,870			2			280
Settlements	(34,681		)	(38,300		)	(1,934		)	(3,426		)
Net transactions recorded during the period:
Gains (losses) recognized in earnings ^(a)	5,742			(2		)	2,280			(792		)
Net gains recognized as regulatory assets and liabilities	18,292			21,922
Balance at Sept. 30	$	45,413		$	24,459
Net losses recognized as regulatory assets and liabilities							(9,493		)	(6,739		)
Balance at March 31							$	13,516		$	4,643


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

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three ~~and nine~~ months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016.~~2017.

Fair Value of Long-Term Debt

As of ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Sept. 30, 2017				Dec. 31, 2016				March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,932,977	$	5,501,602	$	4,843,165	$	5,310,925	$	4,934,024	$	5,352,133	$	4,933,018	$	5,601,919

The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of ~~Sept. 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


9.	Other Income (Expense), Net

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


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended March 31
(Thousands of Dollars)	2017			2016			2017			2016			2018			2017
Interest income	$	2,936		$	510		$	6,250		$	3,975		$	2,935		$	2,709
Insurance policy income (expense)													342			(855		)
Other nonoperating income	—			—			—			248			1			10
Insurance policy expense	(387		)	(926		)	(2,098		)	(2,389		)
Other nonoperating expense	(429		)	(23		)	(402		)	—
Benefits non-service cost													(3,062		)	(3,398		)
Other income (expense), net	$	2,120		$	(439	)	$	3,750		$	1,834		$	216		$	(1,534	)


10.	Segment Information

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

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

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

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

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

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

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


(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total		Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2017
Three Months Ended March 31, 2018
Operating revenues^(a)(b)	$	1,290,971	$	57,442		$	7,366	$	—		$	1,355,779	$	1,062,263	$	241,432	$	7,056	$	—		$	1,310,751
Intersegment revenues	160		100			—		(260		)	—		165		144		—		(309		)	—
Total revenues	$	1,291,131	$	57,542		$	7,366	$	(260	)	$	1,355,779	$	1,062,428	$	241,576	$	7,056	$	(309	)	$	1,310,751
Net income (loss)	$	232,078	$	(6,242	)	$	3,167	$	—		$	229,003
Net income													$	85,722	$	25,445	$	573	$	—		$	111,740


(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total		Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2016
Three Months Ended March 31, 2017
Operating revenues ^(a)(b)	$	1,282,574	$	55,519		$	7,286	$	—		$	1,345,379	$	1,079,030	$	221,183	$	6,927		$	—		$	1,307,140
Intersegment revenues	118		189			—		(307		)	—		109		94		—			(203		)	—
Total revenues	$	1,282,692	$	55,708		$	7,286	$	(307	)	$	1,345,379	$	1,079,139	$	221,277	$	6,927		$	(203	)	$	1,307,140
Net income (loss)	$	217,674	$	(14,900	)	$	3,778	$	—		$	206,552
Net income													$	78,082	$	17,505	$	(1,421	)	$	—		$	94,166


^(a)	Operating revenues include ~~$124~~$117 million and ~~$121~~$124 million of affiliate electric revenue for the three months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016.~~2017.


^(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended ~~Sept. 30, 2017~~March 31, 2018 and ~~2016.~~2017.

(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

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Nine Months Ended Sept. 30, 2016
Operating revenues ^(a)(b)
$ 3,332,688
$ 314,020
$ 21,404
$ —
$ 3,668,112
Intersegment revenues 525
437
—
(962 ) —
Total revenues $ 3,333,213
$ 314,457
$ 21,404
$ (962 ) $ 3,668,112
Net income (loss) $ 367,776
$ 8,700
$ 2,881
$ —
$ 379,357


^(a)	~~Operating revenues include $367 million and $359 million of affiliate electric revenue for the nine months ended Sept. 30, 2017 and 2016.~~


^(b)	~~Operating revenues include an immaterial amount of affiliate gas revenue for the nine months ended Sept. 30, 2017 and 2016.~~


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

Three Months Ended Sept. 30
2017 2016 2017 2016
(Thousands of Dollars) Pension Benefits
Postretirement Health
Care Benefits
Service cost $ 6,958
$ 7,077
$ 36
$ 31
Interest cost 10,177
11,358
854
981
Expected return on plan assets (15,016 ) (15,236 ) (53 ) (43 )
Amortization of prior service cost (credit) 265
234
(759 ) (759 )
Amortization of net loss 9,902
9,194
506
401
Net periodic benefit cost 12,286
12,627
584
611
Costs not recognized due to the effects of regulation (4,899 ) (5,295 ) —
—
Net benefit cost recognized for financial reporting $ 7,387
$ 7,332
$ 584
$ 611



	Nine Months Ended Sept. 30												Three Months Ended March 31
	2017			2016			2017			2016			2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	20,874		$	21,231		$	108		$	93		$	6,982		$	6,958		$	43		$	36
Interest cost(a)	30,531			34,074			2,562			2,943			8,804			10,177			769			854
Expected return on plan assets(a)	(45,050		)	(45,708		)	(161		)	(129		)	(14,541		)	(15,017		)	(96		)	(54		)
Amortization of prior service cost (credit)(a)	795			702			(2,277		)	(2,277		)	(29		)	265			(759		)	(759		)
Amortization of net loss(a)	29,706			27,582			1,520			1,203			9,615			9,902			595			507
Net periodic benefit cost	36,856			37,881			1,752			1,833			10,831			12,285			552			584
Costs not recognized due to the effects of regulation	(14,696		)	(15,887		)	—			—			(2,763		)	(4,899		)				—
Net benefit cost recognized for financial reporting	$	22,160		$	21,994		$	1,752		$	1,833		$	8,068		$	7,386		$	552		$	584


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

In January ~~2017,~~2018, contributions of ~~$150.0~~$150 million were made across four of Xcel Energy’s pension plans, of which ~~$59.4~~$63.0 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during ~~2017.~~2018.


12.	Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive ~~(loss) income,~~loss, net of tax, for the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2018 and 2017 ~~and 2016~~ were as follows:


	Three Months Ended Sept. 30, 2017											Three Months Ended March 31, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at July 1	$	(17,775	)	$	105	$	(2,609	)	$	(20,279	)
Accumulated other comprehensive loss at Jan. 1												$	(20,895	)	$	128		$	(3,770	)	$	(24,537	)
Other comprehensive income before reclassifications	22			—		—			22			5			—			—			5
Losses reclassified from net accumulated other comprehensive loss	379			—		39			418			167			(128		)	53			92
Net current period other comprehensive income	401			—		39			440			172			(128		)	53			97
Accumulated other comprehensive (loss) income at Sept. 30	$	(17,374	)	$	105	$	(2,570	)	$	(19,839	)
Accumulated other comprehensive loss at March 31												$	(20,723	)	$	—		$	(3,717	)	$	(24,440	)


	Three Months Ended Sept. 30, 2016											Three Months Ended March 31, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at July 1	$	(18,640	)	$	105	$	(2,058	)	$	(20,593	)
Other comprehensive loss before reclassifications	(1		)	—		—			(1		)
Accumulated other comprehensive loss at Jan. 1												$	(18,208	)	$	105	$	(2,680	)	$	(20,783	)
Losses reclassified from net accumulated other comprehensive loss	213			—		19			232			203			—		35			238
Net current period other comprehensive income	212			—		19			231			203			—		35			238
Accumulated other comprehensive (loss) income at Sept. 30	$	(18,428	)	$	105	$	(2,039	)	$	(20,362	)
Accumulated other comprehensive loss at March 31												$	(18,005	)	$	105	$	(2,645	)	$	(20,545	)

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) income 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) income at Sept. 30 $ (17,374 ) $ 105
$ (2,570 ) $ (19,839 )

Nine Months Ended Sept. 30, 2016
(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) income at Jan. 1 $ (19,090 ) $ 105
$ (2,096 ) $ (21,081 )
Other comprehensive income before reclassifications 5
—
—
5
Losses reclassified from net accumulated other comprehensive loss 657
—
57
714
Net current period other comprehensive income 662
—
57
719
Accumulated other comprehensive (loss) income at Sept. 30 $ (18,428 ) $ 105
$ (2,039 ) $ (20,362 )

Reclassifications from accumulated other comprehensive loss for the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2018 and 2017 ~~and 2016~~ were as follows:


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2017				Three Months Ended Sept. 30, 2016				Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	612		^(a)	$	350		^(a)	$	261		^(a)	$	342		^(a)
Vehicle fuel derivatives	(11		)	^(b)	25			^(b)	(29		)	^(b)	—			^(b)
Total, pre-tax	601				375				232				342
Tax benefit	(222		)		(162		)		(65		)		(139		)
Total, net of tax	379				213				167				203
Defined benefit pension and postretirement losses:
Amortization of net loss	109			^(c)	83			^(c)	125			^(c)	109			^(c)
Prior service credit	(49		)	^(c)	(49		)	^(c)	(49		)	^(c)	(49		)	^(c)
Total, pre-tax	60				34				76				60
Tax benefit	(21		)		(15		)		(23		)		(25		)
Total, net of tax	39				19				53				35
Marketable securities:
Realization of gains									(179		)		—
Total, pre-tax									(179		)		—
Tax expense									51				—
Total, net of tax									(128		)		—
Total amounts reclassified, net of tax	$	418			$	232			$	92			$	238

Amounts Reclassified from
Accumulated Other
Comprehensive Loss
(Thousands of Dollars) Nine Months Ended Sept. 30, 2017 Nine Months Ended Sept. 30, 2016
Losses (gains) on cash flow hedges:
Interest rate derivatives $ 1,304
^(a)
$ 1,042
^(a)
Vehicle fuel derivatives (16 )
^(b)
82
^(b)
Total, pre-tax 1,288
1,124

Tax benefit (502 ) (467 )
Total, net of tax 786
657

Defined benefit pension and postretirement losses:
Amortization of net loss 327
^(c)
249
^(c)
Prior service credit (147 )
^(c)
(147 )
^(c)
Total, pre-tax 180
102

Tax benefit (70 ) (45 )
Total, net of tax 110
57

Total amounts reclassified, net of tax $ 896
$ 714


^(a)	Included in interest charges.


^(b)	Included in O&M expenses.


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

13. Revenues

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

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

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

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

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

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



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



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

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements including the TCJA’s impact to NSP-Minnesota and its customers, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” ~~“should”~~“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, ~~2016~~2017 and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Non-GAAP Financial Measures

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

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

Results of Operations

NSP-Minnesota’s net income was approximately ~~$410.8~~$112 million for ~~2017 year-to-date,~~the first quarter of 2018, compared with approximately ~~$379.4~~$94 million for the same period of ~~2016.~~2017. The ~~year-to-date~~ increase in earnings, ~~reflects electric rate increases,~~driven by lower ~~ETR~~O&M expenses and ~~reduced O&M expenses. These positive factors were~~higher natural gas margins, was partially offset by higher depreciation ~~expense and higher property taxes.~~expense.

Electric Revenues and Margin

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


	Nine Months Ended Sept. 30						Three Months Ended March 31
(Millions of Dollars)	2017			2016			2018			2017
Electric revenues	$	3,450		$	3,333		$	1,089		$	1,079
Electric fuel and purchased power	(1,215		)	(1,149		)	(408		)	(396		)
Electric margin before impact of the TCJA							$	681		$	683
Impact of the TCJA (offset as a reduction in income tax expense)							(27		)	—
Electric margin	$	2,235		$	2,184		$	654		$	683

The following tables summarize the components of the changes in electric revenues and electric margin for the ~~nine~~three months ended ~~Sept. 30:~~March 31:

Electric Revenues

(Millions of Dollars) 2017 vs. 2016
Retail rate increases (Minnesota) $ 39
Trading 34
Non-fuel riders 30
Decoupling (weather portion - Minnesota) 24
Conservation program revenue, offset by expenses 20
Estimated impact of weather (24 )
Wholesale transmission revenue (14 )
Conservation incentive (10 )
Other, net 18
Total increase in electric revenues $ 117



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

Electric Margin

(Millions of Dollars) 2017 vs. 2016
Retail rate increases (Minnesota) $ 39
Non-fuel riders 30
Decoupling (weather portion - Minnesota) 24
Conservation program revenue, offset by expenses 20
Wholesale transmission revenue, net of costs (28 )
Estimated impact of weather (24 )
Conservation incentive (10 )
Total increase in electric margin $ 51



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

Natural Gas Revenues and Margin

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


	Nine Months Ended Sept. 30						Three Months Ended March 31
(Millions of Dollars)	2017			2016			2018			2017
Natural gas revenues	$	357		$	314		$	244		$	221
Cost of natural gas sold and transported	(199		)	(164		)	(155		)	(143		)
Natural gas margin before impact of the TCJA							$	89		$	78
Impact of the TCJA (offset as a reduction in income tax expense)							(3		)	—
Natural gas margin	$	158		$	150		$	86		$	78

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the ~~nine~~three months ended ~~Sept. 30:~~March 31:

Natural Gas Revenues


(Millions of Dollars)	2017 vs. 2016			2018 vs. 2017
Purchased natural gas adjustment clause recovery	$	34		$	11
Estimated impact of weather				7
Conservation program revenue, offset by expenses	4			2
Retail sales growth, excluding weather impact	3
Infrastructure and integrity riders	3
Other, net	(1		)	3
Total increase in natural gas revenues before impact of the TCJA				$	23
Impact of the TCJA (offset as a reduction in income tax expense)				(3		)
Total increase in natural gas revenues	$	43		$	20

Natural Gas Margin


(Millions of Dollars)	2017 vs. 2016			2018 vs. 2017
Estimated impact of weather				$	7
Conservation program revenue, offset by expenses	$	4		2
Retail sales growth, excluding weather impact	3
Infrastructure and integrity riders	3
Other, net	(2		)	2
Total increase in natural gas margin before impact of the TCJA				$	11
Impact of the TCJA (offset as a reduction in income tax expense)				(3		)
Total increase in natural gas margin	$	8		$	8

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased ~~$45.0~~$16 million, or ~~4.7~~5.3 percent, for ~~2017 year-to-date.~~the first quarter of 2018, largely reflecting expense timing. The ~~decrease primarily relates to the timing of maintenance activities and the overhauls at various generation facilities and reduced expense for nuclear refueling outages, as~~significant changes are summarized in the table below:


(Millions of Dollars)	2017 vs. 2016			2018 vs. 2017
Nuclear plant operations and amortization				$	(10	)
Employee benefits expense				(7		)
Plant generation costs	$	(19	)	(2		)
Nuclear plant operations and amortization	(17		)
Transmission costs	(6		)
Electric distribution costs	(3		)
Employee benefits expense	4
Other, net	(4		)	3
Total decrease in O&M expenses	$	(45	)	$	(16	)

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

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

Conservation Program Expenses — Conservation program expenses ~~increased $24.8~~decreased $2 million, or 5.2 percent, for ~~2017 year-to-date.~~the first quarter of 2018. The ~~increase~~decrease was due to ~~higher~~lower recovery rates, ~~and~~partially offset by additional customer participation in electric conservation programs. Conservation expenses are generally recovered ~~in major jurisdictions~~ 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 ~~$79.4~~$9 million, or ~~17.9~~5.4 percent, for ~~2017 year-to-date.~~the first quarter of 2018. The increase was primarily ~~due~~attributable to capital investments ~~including the Courtenay Wind Farm and prior year amortization of the excess depreciation reserve.~~

~~Taxes (Other than Income Taxes)~~ ~~— Taxes (other than income taxes) increased $5.9 million, or 3.2 percent for 2017 year-to-date.~~ ~~The increase was primarily~~ due to ~~higher property taxes.~~

~~Interest Charges~~ — Interest charges increased $4.5 million, or 2.7 percent, for 2017 year-to-date. The increase was related to higher debt levels to fund capital investments, partially offset by refinancings at lower interest rates.normal system expansion.

Income Taxes — Income tax expense decreased ~~$35.3~~$26 million for the first ~~nine months~~quarter of 2018 compared with the same period in 2017. The decrease was primarily driven by a lower federal tax rate due to ~~net tax benefits related to~~the TCJA, an increase in wind ~~production tax credits (PTCs)~~PTCs, which are largely flowed back to customers through electric margin, and an increase in plant-related regulatory differences related to ARAM. This was partially offset by the ~~resolution~~deferral of ~~IRS appeals/audits.~~the effects of ARAM. The ETR was ~~25.5~~10.2 percent for ~~2017 year-to-date,~~the first quarter of 2018 compared with ~~31.7~~29.3 percent for the same period in ~~2016.~~2017. The lower ETR in ~~2017 was~~2018 is primarily due to the ~~adjustments~~items referenced above.

~~The wind PTCs largely flow back to customers through electric margin.~~

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2016 and Public Utility Regulation included in Item 2 of NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30,~~ 2017 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

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

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

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

These wind projects ~~(with the exception of the Dakota Range project) would qualify for 100 percent of the PTC and~~ are expected to provide ~~billions of dollars of~~significant savings to NSP-Minnesota’s customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with various commission approved resource ~~plans.~~

~~The following table details these wind projects:~~

Project Name Capacity (MW) State Estimated Year of Completion Ownership/PPA Regulatory Status
Freeborn 200
MN/IA 2020 NSP-Minnesota Approved by MPUC
Blazing Star 1 200
MN 2019 NSP-Minnesota Approved by MPUC
Blazing Star 2 200
MN 2020 NSP-Minnesota Approved by MPUC
Lake Benton 100
MN 2019 NSP-Minnesota Approved by MPUC
Foxtail 150
ND 2019 NSP-Minnesota Approved by MPUC
Crowned Ridge 300
SD 2019 NSP-Minnesota Approved by MPUC
Dakota Range 300
SD 2021 NSP-Minnesota Pending MPUC Approval
Total Ownership 1,450

Crowned Ridge 300
SD 2019 PPA Approved by MPUC
Clean Energy 1 100
ND 2019 PPA Approved by MPUC
Total PPA 400

Total Wind Capacity 1,850

~~PPA Terminations and Amendments~~ — In June and July 2017, NSP-Minnesota filed requests with the MPUC and/or the NDPSC for several initiatives including changes to four PPAs to reduce future costs for customers. These actions include the following:

The termination of a PPA with Benson Power LLC (Benson) for its 55 MW biomass facility in Benson, Minn., including the purchase and closure of the facility. The purchase of the Benson biomass facility requires FERC approval, which was requested in August 2017. The transaction would result in payments of $95 million to terminate the PPA and acquire the facility, as well as additional expenditures of approximately $26 million to temporarily operate then close the facility.

The termination of a PPA with Laurentian Energy Authority I, LLC (Laurentian) for its 35 MW of biomass facilities in Hibbing and Virginia, Minn. The termination of the Laurentian PPA would result in $108.5 million of contract cancellation payments over six years.

The remaining two requested PPA changes involve a PPA extension for a 34 MW waste-to-energy facility at a price reflective of current market conditions and termination of another 12 MW waste-to-energy PPA.

NSP-Minnesota has requested recovery of all costs associated with these changes through the Fuel Clause Adjustment (FCA), including a return on NSP-Minnesota’s total investment in the Benson transaction over the remaining life of the current PPA through 2028. NSP-Minnesota and NSP-Wisconsin will jointly request FERC approval to modify the Interchange Agreement to share a portion of the cost with NSP-Wisconsin. If approved, these actions together are intended to provide approximately $653 million in net cost savings to NSP System customers over the next 10 years.

~~Jurisdictional Cost Recovery Allocation~~ — In December 2016, NSP-Minnesota filed a resource treatment framework with the NDPSC and MPUC. The filing proposed a framework to allow NSP-Minnesota’s operations in North Dakota and Minnesota to gradually become more independent of one another with respect to future generation resource selection while also identifying a path for cost sharing of current resources. NSP-Minnesota’s filing identified two options: a legal separation, creating a separate North Dakota operating company; or a pseudo-separation, which maintains the current corporate structure but directly assigns the costs and benefits of each resource to the jurisdiction that supports itplans.The annual costs for a legal separation and pseudo-separation are estimated to be approximately $3 million and $1 million, respectively. A one-time cost of approximately $10 million would also be incurred to establish a North Dakota operating company under legal separation. Costs are not expected to be incurred until 2020 and are anticipated to be recoverable through rates. The filing proposed a procedural schedule that considers an order in mid-2018. In October 2017, NDPSC staff filed testimony recommending no change to the current system of proxy pricing and policy-based disallowances claiming there is a likelihood of overall increased costs and potential loss of resource diversity. NSP-Minnesota’s rebuttal testimony is due Nov. 15, 2017 and hearings are scheduled in January 2018.

~~CapX2020~~Minnesota State Right-Of-First Refusal (ROFR) Statute Complaint — In September 2017, LSP Transmission Holdings, LLC (LSP Transmission) filed a complaint in the U.S. District Court for the District of Minnesota (Minnesota District Court) against the Minnesota Attorney General, the MPUC and the DOC. The ~~estimated cost of the five major CapX2020 transmission projects listed below~~complaint was ~~approximately $2 billion.~~in response to MISO assigning NSP-Minnesota and ~~NSP-Wisconsin were responsible for approximately $1.04 billion of the total investment and the majority of this investment has occurred. The projects are as follows:~~

~~Hampton, Minn.~~ITC Midwest, LLC to ~~Rochester, Minn. to La Crosse, Wis. 161/345 kilovolt (KV) transmission lines— The final 161 KV and 345 KV segments of the project went into service in January 2016 and September 2016, respectively;~~

~~Brookings County, S.D. to Hampton, Minn. 345 KV transmission line— The project was placed in service in March 2015;~~

~~Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line — The project was placed in service in September 2012;~~

~~Monticello, Minn. to Fargo, N.D. 345 KV transmission line— The final portion of the project was placed in service in April 2015; and~~

~~Big Stone South to Brookings County, S.D.~~jointly own a new 345 KV transmission line —from near Mankato, Minn. to Winnebago, Minn. The line was estimated by MISO to cost $103 million. The project was ~~placed in service in September 2017.~~

assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota ~~FCA~~ ~~— In October 2017,~~state ROFR statute. The complaint challenges the ~~MPUC voted to change the process in which utilities seek fuel cost recovery under the FCA in Minnesota. Each month, utilities collect amounts equal to the baseline cost of energy set at the start~~constitutionality of the ~~plan year, as well as issue refunds or billings for~~state ROFR statute and is seeking declaratory judgment that the ~~difference relative to~~statute violates the baseline costs. Under the new process, monthly variations to the baseline costs will be tracked and netted over a 12-month period. Subsequently, utilities can seek recovery of any overage. The MPUC has requested additional compliance filings from all utilities outlining the details and timingCommerce Clause of the ~~proposed process.~~ U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In April 2018, the Antitrust Division of the United States Department of Justice, filed a statement in support of LSP Transmission’s position that the statute is unconstitutional. The matter is pending before the Minnesota District Court. The timing and outcome of the litigation is uncertain.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. ~~NSP-Minnesota’s next triennial nuclear decommissioning filing is expected to be submitted in the fourth quarter of 2017.~~ See Note 12 of NSP-Minnesota’s Annual

Report on Form 10-K for the year ended Dec. 31, ~~2016~~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, ~~2016 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, 2017 and June 30,~~ 2017, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated herein by reference.

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 1258 percent of its ~~2017~~2018 and approximately 5924 percent of its ~~2018~~2019 enriched nuclear material requirements from sources that could be impacted by current political/world events, ~~in Ukraine and sanctions against~~ including those related to Ukraine/Russia. Alternate potential sources are expected to provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply to ensure that plant availability and reliability will not be negatively impacted in the near-term. Long-term, through 2024, NSP-Minnesota is scheduled to take delivery of approximately 3135 percent of its average enriched nuclear material requirements from ~~sources that could be impacted by events in Ukraine and extended sanctions against Russia.~~these sources. NSP-Minnesota is closely following the progression of these events and will periodically assess if further actions are required to assure a secure supply of enriched nuclear material.

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

Summary of Recent Federal Regulatory Developments

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, ~~2016 and Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30,~~ 2017. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

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

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

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 ~~includes~~include NSP-Minnesota and NSP-Wisconsin. In April 2017, the D.C. Circuit vacated and remanded the June 2014 ROE order. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for the NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. The FERC has yet to act on the D.C. Circuit’s decision. See Note 5 to the consolidated financial statements for discussion of the D.C. Circuit’s decision and the impact on the MISO ROE Complaints.

~~Department of Energy (DOE) Grid Resiliency Notice of Proposed Rule (NOPR)~~ — In September 2017, the DOE requested the FERC consider and adopt a Grid Resiliency and Pricing Rule to address threats to the U.S. electrical grid. The proposed DOE rule expands upon an August 2017 DOE grid study on the resiliency of the grid. Under the proposed rule, coal and nuclear generation facilities would qualify for full recovery of their costs, which includes a fair rate of return, if they meet the following criteria:

~~Are located within a FERC-approved organized wholesale market operated by an RTO or Independent System Operator;~~

~~Have 90 days of on-site fuel storage;~~

~~Provide essential energy and ancillary reliability services to the grid;~~

~~Are in compliance with all environmental mandates; and~~

~~Are not subject to cost-of-service regulation by any state or local authority.~~

If implemented as written, the coal and nuclear generation owned by NSP-Minnesota and NSP-Wisconsin are not expected to be eligible for wholesale cost recovery from MISO because the generation is subject to state cost-of-service regulation. This rule could impact utilities in MISO subject to cost-of-service regulation if they have to compensate other generation facilities who qualify for full recovery of their costs under the rule. Xcel Energy is evaluating the DOE proposal and plans to engage in the FERC stakeholder process. The FERC has indicated that they plan to take action within 60 days, as requested by the DOE. It is unclear how the FERC will respond to the DOE’s NOPR.

~~Minnesota State Right-Of-First Refusal (ROFR) Statute Complaint~~ —In September 2017, LSP Transmission Holdings, LLC filed a complaint in the U.S. District Court in Minnesota against the Minnesota Attorney General, the MPUC and the DOC. The complaint was in response to NSP-Minnesota and ITC Midwest, LLC being assigned by MISO to jointly own a new 345 kilovolt transmission line that is planned to run from NSP-Minnesota’s Wilmarth Substation near Mankato, Minn. to ITC Midwest’s Huntley Substation in Minnesota south of Winnebago, Minn. The line is estimated 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 challenges the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies are expected to answer the complaint in November 2017. NSP-Minnesota expects to intervene in the case. The timing and outcome of the litigation is uncertain.

~~North American Electric Reliability Corporation (NERC) Supply Chain Standards~~ — In September 2017, NERC filed supply chain cyber security reliability standards with the FERC. These standards consider the FERC’s directives to address supply chain cyber security risk management for industrial control system hardware, software, computing and network services associated with electric grid operations. The proposed reliability standards focus on security objectives including software integrity and authenticity, vendor remote access protections, information system planning and vendor risk management. It is uncertain when the FERC will take action to approve or remand the proposed reliability standards. If approved by the FERC, the proposed reliability standards will become effective on the first calendar quarter that is 18 months after the effective date of the approval. NSP-Minnesota is in the process of developing plans in accordance with the requirements of the standards. The additional cost for compliance is anticipated to be recoverable through wholesale and retail rates.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of ~~Sept. 30, 2017,~~March 31, 2018, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

In 2016, NSP-Minnesota implemented the general ledger modules, as well as initiated deployment of work management systems modules, of a new enterprise resource planning system to improve certain financial and related transaction processes. NSP-Minnesota is continuing to implement additional modules including the conversion of existing work management systems to this same system during 2017. In connection with this ongoing implementation, NSP-Minnesota is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. NSP-Minnesota does not believe that this implementation will have an adverse effect on its internal control over financial reporting.

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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, ~~2016,~~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

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



3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern States Power Co. (a Minnesota corporation) as Amended and Restated on Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 000-31387)).
4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from Northern States Power Company to Harris Trust and Savings Bank, as Trustee, providing for the issuance of ~~Sept. 1, 2017 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor trustee, creating $600 million principal amount of 3.60 percent~~ First Mortgage Bonds ~~Series due Sept. 15, 2047~~ (Exhibit ~~4.01~~4(b)(3) to Form ~~8-K dated Sept. 13, 2017~~S-3 of Xcel Energy, filed April 18, 2018 (file no. ~~001-31387)~~333-224333)).
~~10.1~~4.02*+	~~Fourth Amendment to~~Indenture, dated July 1, 1999, between Northern States Power Company and Norwest Bank Minnesota, National Association, as Trustee, providing for the ~~Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)~~issuance of Sr. Debt Securities (Exhibit ~~10.1~~4(b)(7) to Form ~~10-Q~~S-3 of Xcel Energy, ~~for the quarter ended Sept. 30, 2017~~filed April 18, 2018 (file no. ~~001-03034)~~333-224333)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended ~~Sept. 30, 2017~~March 31, 2018 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Consolidated Financial Statements, and (vi) document and entity information.

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.~~April 27, ~~2017~~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)

3633



(Millions of Dollars, Incremental)	2016		2017		2018		2019			Total
Revenues	$	74.99	$	59.86	$	—	$	50.12		$	184.97
NSP-Minnesota’s sales true-up	59.95		—		—		(0.20		)	59.75
Total rate impact	$	134.94	$	59.86	$	—	$	49.92		$	244.72




	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



	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) income 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) income at Sept. 30	$	(17,374	)	$	105	$	(2,570	)	$	(19,839	)



(Millions of Dollars)	2017 vs. 2016
Retail rate increases (Minnesota)	$	39
Trading	34
Non-fuel riders	30
Decoupling (weather portion - Minnesota)	24
Conservation program revenue, offset by expenses	20
Estimated impact of weather	(24		)
Wholesale transmission revenue	(14		)
Conservation incentive	(10		)
Other, net	18
Total increase in electric revenues	$	117



Project Name	Capacity (MW)	State	Estimated Year of Completion	Ownership/PPA	Regulatory Status
Freeborn	200	MN/IA	2020	NSP-Minnesota	Approved by MPUC
Blazing Star 1	200	MN	2019	NSP-Minnesota	Approved by MPUC
Blazing Star 2	200	MN	2020	NSP-Minnesota	Approved by MPUC
Lake Benton	100	MN	2019	NSP-Minnesota	Approved by MPUC
Foxtail	150	ND	2019	NSP-Minnesota	Approved by MPUC
Crowned Ridge	300	SD	2019	NSP-Minnesota	Approved by MPUC
Dakota Range	300	SD	2021	NSP-Minnesota	Pending MPUC Approval
Total Ownership	1,450

Crowned Ridge	300	SD	2019	PPA	Approved by MPUC
Clean Energy 1	100	ND	2019	PPA	Approved by MPUC
Total PPA	400
Total Wind Capacity	1,850