NORTHERN STATES POWER CO - FORM 10-Q

NORTHERN STATES POWER CO - FORM 10-Q - October 31, 2016

Attached files

Attached files

NORTHERN STATES POWER CO Reports

file	filename
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO	nspmex9901q32016.htm
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO	nspmex3201q32016.htm
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO	nspmex3102q32016.htm
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO	nspmex3101q32016.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended Sept. 30, 2016



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

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)



Minnesota		41-1967505
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

414 Nicollet Mall
Minneapolis, Minnesota		55401
(Address of principal executive offices)		(Zip Code)

(612) 330-5500

(Registrant’s telephone number, including area code)

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

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

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



Large accelerated filer ¨	Accelerated filer ¨

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

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

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



Class		Outstanding at Oct. 31, 2016
Common Stock, $0.01 par value		1,000,000 shares

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

TABLE OF CONTENTS



PART I —	FINANCIAL INFORMATION

Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 4 —	Controls and Procedures	35

PART II —	OTHER INFORMATION

Item 1 —	Legal Proceedings	36
Item 1A —	Risk Factors	36
Item 4 —	Mine Safety Disclosures	36
Item 5 —	Other Information	36
Item 6 —	Exhibits	36

SIGNATURES		37

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

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

Table of Contents

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
	2016			2015			2016			2015
Operating revenues
Electric, non-affiliates	$	1,161,259		$	1,072,207		$	2,973,350		$	2,835,528
Electric, affiliates	121,315			116,136			359,338			358,841
Natural gas	55,519			53,354			314,020			408,060
Other	7,286			7,143			21,404			20,867
Total operating revenues	1,345,379			1,248,840			3,668,112			3,623,296

Operating expenses
Electric fuel and purchased power	435,560			433,993			1,148,818			1,217,192
Cost of natural gas sold and transported	19,105			16,742			163,608			255,350
Cost of sales — other	4,898			4,563			14,185			13,357
Operating and maintenance expenses	315,298			290,865			954,334			916,427
Conservation program expenses	23,926			17,573			67,424			49,662
Depreciation and amortization	149,408			119,630			442,649			353,950
Taxes (other than income taxes)	49,763			54,784			186,100			177,103
Loss on Monticello life cycle management/extended power uprate project	—			—			—			124,226
Total operating expenses	997,958			938,150			2,977,118			3,107,267

Operating income	347,421			310,690			690,994			516,029

Other (expense) income, net	(439		)	(296		)	1,834			1,389
Allowance for funds used during construction — equity	7,983			7,456			21,011			19,070

Interest charges and financing costs
Interest charges — includes other financing costs of $1,822, $1,706, $5,325, and $4,953, respectively	57,859			53,152			168,010			154,008
Allowance for funds used during construction — debt	(3,591		)	(3,428		)	(9,575		)	(9,182		)
Total interest charges and financing costs	54,268			49,724			158,435			144,826

Income before income taxes	300,697			268,126			555,404			391,662
Income taxes	94,145			92,577			176,047			135,008
Net income	$	206,552		$	175,549		$	379,357		$	256,654

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2016			2015			2016		2015
Net income	$	206,552		$	175,549		$	379,357	$	256,654

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $15, $(4), $45 and $(11) respectively	19			(7		)	57		(19		)

Derivative instruments:
Net fair value increase (decrease), net of tax of $(1), $(16), $3 and $(13), respectively	(1		)	(23		)	5		(20		)
Reclassification of losses to net income, net of tax of $162, $157, $467 and $449, respectively	213			215			657		637
	212			192			662		617
Marketable securities:
Net fair value decrease, net of tax of $0, $(1), $0 and $0, respectively	—			(2		)	—		—

Other comprehensive income	231			183			719		598
Comprehensive income	$	206,783		$	175,732		$	380,076	$	257,252

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Nine Months Ended Sept. 30,
	2016			2015
Operating activities
Net income	$	379,357		$	256,654
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	447,284			358,210
Nuclear fuel amortization	89,475			82,627
Deferred income taxes	129,410			150,686
Amortization of investment tax credits	(1,260		)	(1,299		)
Allowance for equity funds used during construction	(21,011		)	(19,070		)
Loss on Monticello life cycle management/extended power uprate project	—			124,226
Net realized and unrealized hedging and derivative transactions	2,873			12,981
Changes in operating assets and liabilities:
Accounts receivable	(46,294		)	37,538
Accrued unbilled revenues	26,660			58,740
Inventories	5,709			(55,075		)
Other current assets	24,431			44,458
Accounts payable	19,736			(37,645		)
Net regulatory assets and liabilities	57,452			18,491
Other current liabilities	(3,947		)	71,837
Pension and other employee benefit obligations	(42,447		)	(28,789		)
Change in other noncurrent assets	(8,862		)	(157		)
Change in other noncurrent liabilities	(17,084		)	(20,965		)
Net cash provided by operating activities	1,041,482			1,053,448

Investing activities
Utility capital/construction expenditures	(833,845		)	(907,315		)
Allowance for equity funds used during construction	21,011			19,070
Proceeds from insurance recoveries	—			27,237
Purchases investment securities	(349,717		)	(773,260		)
Proceeds from the sale of investment securities	327,378			753,924
Investments in utility money pool arrangement	(492,000		)	(187,900		)
Repayments from utility money pool arrangement	441,000			169,900
Other, net	(1,262		)	(501		)
Net cash used in investing activities	(887,435		)	(898,845		)

Financing activities
Repayments of short-term borrowings, net	(223,000		)	(142,000		)
Borrowings under utility money pool arrangement	424,000			213,500
Repayments under utility money pool arrangement	(424,000		)	(213,500		)
Proceeds from issuance of long-term debt	342,570			588,003
Repayments of long-term debt	(11		)	(250,013		)
Capital contributions from parent	96,628			125,957
Dividends paid to parent	(306,209		)	(198,759		)
Net cash (used in) provided by financing activities	(90,022		)	123,188

Net change in cash and cash equivalents	64,025			277,791
Cash and cash equivalents at beginning of period	42,605			40,597
Cash and cash equivalents at end of period	$	106,630		$	318,388

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(169,382	)	$	(155,931	)
Cash (paid) received for income taxes, net	(14,279		)	53,021
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	72,889		$	101,075

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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



	Sept. 30, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	106,630		$	42,605
Accounts receivable, net	335,531			292,806
Accounts receivable from affiliates	22,149			32,850
Investments in utility money pool arrangement	51,000			—
Accrued unbilled revenues	200,442			227,102
Inventories	338,328			343,916
Regulatory assets	178,597			187,793
Derivative instruments	30,912			18,941
Deferred income taxes	75,962			15,577
Prepayments and other	57,379			89,559
Total current assets	1,396,930			1,251,149

Property, plant and equipment, net	13,049,393			12,807,338

Other assets
Nuclear decommissioning fund and other investments	1,859,677			1,758,208
Regulatory assets	1,196,752			1,159,217
Derivative instruments	25,597			22,334
Other	10,409			1,385
Total other assets	3,092,435			2,941,144
Total assets	$	17,538,758		$	16,999,631

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	10		$	11
Short-term debt	—			223,000
Accounts payable	338,312			350,660
Accounts payable to affiliates	53,905			59,785
Regulatory liabilities	70,471			43,920
Taxes accrued	250,776			225,361
Accrued interest	51,588			66,979
Dividends payable to parent	89,684			73,498
Derivative instruments	16,312			17,211
Customer deposits	108,977			94,388
Other	142,496			177,795
Total current liabilities	1,122,531			1,332,608

Deferred credits and other liabilities
Deferred income taxes	2,780,595			2,572,087
Deferred investment tax credits	24,578			25,838
Regulatory liabilities	490,553			491,887
Asset retirement obligations	2,417,292			2,331,092
Derivative instruments	121,116			128,213
Pension and employee benefit obligations	297,005			339,663
Other	136,417			114,768
Total deferred credits and other liabilities	6,267,556			6,003,548

Commitments and contingencies
Capitalization
Long-term debt	4,842,126			4,496,410
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at Sept. 30, 2016 and Dec. 31, 2015, respectively	10			10
Additional paid in capital	3,405,609			3,323,810
Retained earnings	1,921,288			1,864,326
Accumulated other comprehensive loss	(20,362		)	(21,081		)
Total common stockholder’s equity	5,306,545			5,167,065
Total liabilities and equity	$	17,538,758		$	16,999,631

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of Sept. 30, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2016 and 2015; and its cash flows for the nine months ended Sept. 30, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2016 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2015 balance sheet information has been derived from the audited 2015 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2015. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2015, filed with the SEC on Feb. 22, 2016. Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.


1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2015, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

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

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, NSP-Minnesota does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Minnesota is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.

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Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. NSP-Minnesota is currently evaluating the impact of adopting ASU 2016-02 on its consolidated financial statements.

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. NSP-Minnesota does not expect the implementation of ASU 2016-09 to have a material impact on its consolidated financial statements.

Recently Adopted

Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. NSP-Minnesota implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation did not have a significant impact on its consolidated financial statements.

Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. NSP-Minnesota implemented the new guidance as required on Jan. 1, 2016, and as a result, $36.9 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $37.7 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a net asset value (NAV) methodology in the fair value hierarchy. NSP-Minnesota implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.


3.	Selected Balance Sheet Data



(Thousands of Dollars)	Sept. 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	354,286		$	313,556
Less allowance for bad debts	(18,755		)	(20,750		)
	$	335,531		$	292,806



(Thousands of Dollars)	Sept. 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	215,055	$	200,888
Fuel	84,535		104,499
Natural gas	38,738		38,529
	$	338,328	$	343,916

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(Thousands of Dollars)	Sept. 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	16,558,194		$	16,256,887
Natural gas plant	1,272,660			1,248,408
Common and other property	638,221			624,409
Construction work in progress	856,415			545,535
Total property, plant and equipment	19,325,490			18,675,239
Less accumulated depreciation	(6,592,740		)	(6,251,498		)
Nuclear fuel	2,469,772			2,447,251
Less accumulated amortization	(2,153,129		)	(2,063,654		)
	$	13,049,393		$	12,807,338


4.	Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

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

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Sept. 30, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, the 2013 through 2014 claims, and the anticipated claim for 2015. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in June 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’s proposed adjustment of the carryback claims. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

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

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

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



(Millions of Dollars)	Sept. 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	21.0	$	20.1
Unrecognized tax benefit — Temporary tax positions	40.1		35.3
Total unrecognized tax benefit	$	61.1	$	55.4

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



(Millions of Dollars)	Sept. 30, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(18.7	)	$	(15.2	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Minnesota audit progresses, and other state audits resume. As the IRS Appeals and IRS and Minnesota audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $32 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2016 or Dec. 31, 2015.


5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 and in Note 5 to NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

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



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

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

Settlement Agreement

In August 2016, NSP-Minnesota reached a settlement with the Minnesota Department of Commerce (DOC), Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group, the Suburban Rate Authority, the City of Minneapolis, the Industrial, Commercial, and Institutional Group, and the Energy CENTS Coalition, which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC.

Key terms of the settlement are listed below:


•	The agreement reflects a four-year period covering 2016-2019;


•	The stated revenue increases in the table below are based on the DOC’s sales forecast;


•	Annual sales true-up to weather-normalized actuals all years, all classes:


•	2016 weather-normalized actuals used to set final 2016 rates, no cap;


•	2016-2019 full decoupling for decoupled classes (residential, non-demand metered commercial) with 3 percent cap; and


•	2017-2019 annual true-up for non-decoupled classes with 3 percent cap.


•	An ROE of 9.2 percent and an equity ratio of 52.5 percent;


•	The nuclear related costs in this rate case will not be considered provisional;


•	Continued use of all existing riders during the four-year term, however no new riders or legislative additions would be utilized during the four-year term;


•	Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019; and


•	A four-year stay out provision for rate cases.

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Compliance steps recommended by the settling parties to implement the settlement:


•	A property tax true-up mechanism for 2017-2019; and


•	A capital expenditure true-up mechanism for 2016-2019.



(Millions of Dollars, incremental)	2016		2017		2018		2019		Total
Settlement revenues ^(a)	$	74.99	$	59.86	$	—	$	50.12	$	184.97
NSP-Minnesota’s sales forecast ^(b)	37.40		—		—		—		37.40
Total rate impact	$	112.39	$	59.86	$	—	$	50.12	$	222.37


^(a)	The settlement revenue increase reflects an increase of 2.47 percent in 2016; 1.97 percent in 2017; 0 percent in 2018 and 1.65 percent in 2019.


^(b)	The table reflects the estimated rate impact of this agreement, using NSP-Minnesota’s original sales forecast as filed in the Minnesota rate case. The settlement agreement includes a provision to true-up estimated sales to the actual sales for 2016.

The revised schedule for the Minnesota rate case is listed below:


•	Administrative law judge (ALJ) report — March 3, 2017; and


•	MPUC decision — June 2017.

A current liability that is consistent with the settlement and represents NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of Sept. 30, 2016.

NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider — In August 2016, the MPUC approved NSP-Minnesota’s request to recover approximately $15.5 million in natural gas infrastructure costs through the GUIC Rider, based on NSP-Minnesota’s proposed capital structure and a ROE of 9.64 percent. Recovery was approved for the 15-month period from January 2016 to March 2017.

Annual Automatic Adjustment (AAA) of Charges — In June 2016, the DOC recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. The DOC’s recommendation could impact replacement power cost recovery for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction during the AAA fiscal year ended June 30, 2015. NSP-Minnesota expects a MPUC decision in mid-2017.

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello life cycle management (LCM)/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

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

In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent, which the FERC upheld in an order issued on Sept. 28, 2016. This ROE is applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE is 10.82 percent, which includes a previously approved 50 basis point adder for RTO membership.

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In February 2015, a second complaint seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent prior to any adder was filed, which the FERC set for hearings, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. On June 30, 2016, the ALJ recommended a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow range. A FERC decision is expected in 2017.

As of Sept. 30, 2016, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the FERC order, as well as a current liability representing the best estimate of the final ROE for the second 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, 2015, and in Note 6 to NSP-Minnesota’s Quarterly Reports on the Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Purchased Power Agreements (PPAs)

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

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

Guarantees

Under NSP-Minnesota’s railcar lease agreement, accounted for as an operating lease, NSP-Minnesota guarantees the lessor proceeds from sale of the leased assets at the end of the lease term will at least equal the guaranteed residual value. The guarantee issued by NSP-Minnesota 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, 2016		Dec. 31, 2015
Guarantee issued and outstanding	$	4.8	$	4.8

Environmental Contingencies

Fargo, N.D. Manufactured Gas Plant (MGP) Site — In May 2015, underground pipes, tars and impacted soils were discovered in 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 at that time and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). Based on the investigation that concluded in the third quarter of 2016, NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed, subject to further input from the North Dakota Department of Health, the City of Fargo, N.D., current property owners and other stakeholders.

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NSP-Minnesota has initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until November 2016 to allow NSP-Minnesota time to investigate site conditions. NSP-Minnesota intends to seek an additional stay of the litigation.

As of Sept. 30, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $12.2 million and $2.7 million, respectively, for the Fargo MGP Site, with the increase due to the remediation activities proposed by NSP-Minnesota. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer costs associated with the Fargo MGP Site, resulting in deferral of all investigation and response costs with the exception of 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to the liability recognized include obtaining access and approvals from stakeholders to perform the proposed remediation and the potential for contributions from entities that may be identified as potentially responsible parties.

Environmental Requirements

Water and Waste

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

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

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO₂) and nitrogen oxide (NOx) from utilities in the eastern half of the United States, including Minnesota using an emissions trading program.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone National Ambient Air Quality Standard (NAAQS) and the 1997 and 2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. The EPA adopted a final rule in September 2016 for the ozone season emission budget for NOx which did not impact NSP-Minnesota.

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

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Legal Contingencies

NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.


7.	Borrowings and Other Financing Instruments

Short-Term Borrowings

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



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

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



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

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2016 and Dec. 31, 2015, there were $11 million and $18 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.

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Credit Facility — In order to use its commercial paper program, NSP-Minnesota must have a credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available credit facility capacity. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

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



Credit Facility ^(a)		Drawn ^(b)		Available
$	500	$	11	$	489


^(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, 2016 and Dec. 31, 2015.

Amended Credit Agreements - In June 2016, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $500 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:


•	The maturity extended from October 2019 to June 2021.


•	The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.


•	The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

NSP-Minnesota has the right to request an extension of the revolving credit facility termination date for two additional one-year periods, subject to majority bank group approval.

Long-Term Borrowings

In May 2016, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046.


8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and 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 measurement date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

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

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

Specific valuation methods include the following:

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

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Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using a NAV methodology, which takes into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for 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. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

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

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

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

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

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

Unrealized gains for the nuclear decommissioning fund were $355.3 million and $328.8 million at Sept. 30, 2016 and Dec. 31, 2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $65.8 million and $100.2 million at Sept. 30, 2016 and Dec. 31, 2015, respectively.

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



	Sept. 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	15,055	$	15,055	$	—	$	—	$	—	$	15,055
Commingled funds:
Non U.S. equities	254,362		—		—		—		245,481		245,481
Emerging market debt funds	92,472		—		—		—		101,387		101,387
Commodity funds	99,771		—		—		—		82,139		82,139
Private equity investments	130,848		—		—		—		178,768		178,768
Real estate	121,271		—		—		—		174,552		174,552
Other commingled funds	151,048		—		—		—		159,230		159,230
Debt securities:
Government securities	34,853		—		35,723		—		—		35,723
U.S. corporate bonds	95,828		—		93,981		—		—		93,981
International corporate bonds	19,877		—		19,860		—		—		19,860
Municipal bonds	13,906		—		14,638		—		—		14,638
Asset-backed securities	2,847		—		2,948		—		—		2,948
Mortgage-backed securities	10,118		—		10,582		—		—		10,582
Equity securities:
U.S. equities	270,137		455,035		—		—		—		455,035
Non U.S. equities	213,291		225,782		—		—		—		225,782
Total	$	1,525,684	$	695,872	$	177,732	$	—	$	941,557	$	1,815,161


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


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

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	Dec. 31, 2015
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	27,484	$	27,484	$	—	$	—	$	—	$	27,484
Commingled funds:
Non U.S. equities	259,114		—		—		—		231,122		231,122
Emerging market debt funds	88,987		—		—		—		88,467		88,467
Commodity funds	99,771		—		—		—		77,338		77,338
Private equity investments	105,965		—		—		—		157,528		157,528
Real estate	115,019		—		—		—		165,190		165,190
Other commingled funds	150,877		—		—		—		164,389		164,389
Debt securities:
Government securities	24,444		—		21,356		—		—		21,356
U.S. corporate bonds	73,061		—		65,276		—		—		65,276
International corporate bonds	13,726		—		12,801		—		—		12,801
Municipal bonds	49,255		—		51,589		—		—		51,589
Asset-backed securities	2,837		—		2,830		—		—		2,830
Mortgage-backed securities	11,444		—		11,621		—		—		11,621
Equity securities:
U.S. equities	273,106		432,495		—		—		—		432,495
Non U.S. equities	200,509		214,664		—		—		—		214,664
Total	$	1,495,599	$	674,643	$	165,473	$	—	$	884,034	$	1,724,150


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


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

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

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



	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	—	$	10,583	$	971	$	24,169	$	35,723
U.S. corporate bonds	257		28,245		59,451		6,028		93,981
International corporate bonds	—		5,043		11,606		3,211		19,860
Municipal bonds	—		210		5,773		8,655		14,638
Asset-backed securities	—		—		2,948		—		2,948
Mortgage-backed securities	—		—		—		10,582		10,582
Debt securities	$	257	$	44,081	$	80,749	$	52,645	$	177,732

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Rabbi Trusts

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



	Sept. 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trust ^(a)
Cash equivalents	$	7,449	$	7,449	$	—	$	—	$	7,449
Mutual funds	1,594		1,867		—		—		$	1,867
Total	$	9,043	$	9,316	$	—	$	—	$	9,316


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

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

Derivative Instruments Fair Value Measurements

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

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

At Sept. 30, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges, as applicable.

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

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

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

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

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

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


^(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, 2016 and 2015 on accumulated other comprehensive loss, regulatory assets and liabilities and income:




	Three Months Ended Sept. 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	350	^(a)	$	—		$	—
Vehicle fuel and other commodity	(2		)	—			25		^(b)	—			—
Total	$	(2	)	$	—		$	375		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	1,808	^(c)
Electric commodity	—			15,301			—			2,044		^(d)	—
Natural gas commodity	—			(792		)	—			—			—
Total	$	—		$	14,509		$	—		$	2,044		$	1,808




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

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	Three Months Ended Sept. 30, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax 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)			Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	353	^(a)	$	—		$	—
Vehicle fuel and other commodity	(39		)	—			19		^(b)	—			—
Total	$	(39	)	$	—		$	372		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	(3,460	)	^(c)
Electric commodity	—			(1,666		)	—			2,157		^(d)	—
Natural gas commodity	—			(802		)	—			—			—
Total	$	—		$	(2,468	)	$	—		$	2,157		$	(3,460	)




	Nine Months Ended Sept. 30, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax 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)			Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	1,037	^(a)	$	—		$	—
Vehicle fuel and other commodity	(33		)	—			49		^(b)	—			—
Total	$	(33	)	$	—		$	1,086		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	(6,087	)	^(c)
Electric commodity	—			(13,889		)	—			13,677		^(d)	—
Natural gas commodity	—			(785		)	—			2,751		^(e)	(3,008		)	^(e)
Total	$	—		$	(14,674	)	$	—		$	16,428		$	(9,095	)


^(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, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — NSP-Minnesota monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions. Given this assessment, as well as an assessment of the impact of NSP-Minnesota’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

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NSP-Minnesota employs additional credit risk control mechanisms, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

NSP-Minnesota’s most significant concentrations of credit risk are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At Sept. 30, 2016, five of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $20.5 million or 25 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Four of the 10 most significant counterparties, comprising $15.1 million or 18 percent of this credit exposure, were not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. The remaining most significant counterparty, comprising $0.6 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on ratings from internal analysis. Nine of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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

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

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



	Sept. 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	2,614	$	8,182	$	—	$	10,796	$	(5,754	)	$	5,042
Electric commodity	—		—		25,177		25,177		(718		)	24,459
Natural gas commodity	—		865		—		865		—			865
Total current derivative assets	$	2,614	$	9,047	$	25,177	$	36,838	$	(6,472	)	30,366
PPAs ^(a)												546
Current derivative instruments												$	30,912
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	501	$	32,524	$	—	$	33,025	$	(8,306	)	$	24,719
Total noncurrent derivative assets	$	501	$	32,524	$	—	$	33,025	$	(8,306	)	24,719
PPAs ^(a)												878
Noncurrent derivative instruments												$	25,597

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	Sept. 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	22	$	—	$	22	$	—		$	22
Other derivative instruments:
Commodity trading	2,562		5,532		—		8,094		(5,841		)	2,253
Electric commodity	—		—		718		718		(718		)	—
Total current derivative liabilities	$	2,562	$	5,554	$	718	$	8,834	$	(6,559	)	2,275
PPAs ^(a)												14,037
Current derivative instruments												$	16,312
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	538	$	24,102	$	—	$	24,640	$	(11,005	)	$	13,635
Total noncurrent derivative liabilities	$	538	$	24,102	$	—	$	24,640	$	(11,005	)	13,635
PPAs ^(a)												107,481
Noncurrent derivative instruments												$	121,116

^(a)

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

^(b)

NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2016. At Sept. 30, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $2.8 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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



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

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

^(a)

^(b)

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

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



	Three Months Ended Sept. 30
(Thousands of Dollars)	2016			2015
Balance at July 1	$	23,488		$	35,363
Purchases	—			78
Settlements	(26,192		)	(12,807		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	—			121
Gains recognized as regulatory assets and liabilities	27,163			1,068
Balance at Sept. 30	$	24,459		$	23,823

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	12,969		$	40,271
Purchases	27,870			41,103
Settlements	(38,300		)	(31,652		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings ^(a)	(2		)	1,401
Gains (losses) recognized as regulatory assets and liabilities	21,922			(27,300		)
Balance at Sept. 30	$	24,459		$	23,823


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

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

Fair Value of Long-Term Debt

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



	Sept. 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion ^(a)	$	4,842,136	$	5,687,944	$	4,496,421	$	4,917,080


^(a)	Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Sept. 30, 2016 and Dec. 31, 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


9.	Other (Expense) Income, Net

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



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2016			2015			2016			2015
Interest income (expense)	$	510		$	(226	)	$	3,975		$	3,198
Other nonoperating (expense) income	(23		)	55			248			147
Insurance policy expense	(926		)	(125		)	(2,389		)	(1,956		)
Other (expense) income, net	$	(439	)	$	(296	)	$	1,834		$	1,389


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.

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



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2016
Operating revenues ^(a)(b)	$	1,282,574	$	55,519		$	7,286	$	—		$	1,345,379
Intersegment revenues	118		189			—		(307		)	—
Total revenues	$	1,282,692	$	55,708		$	7,286	$	(307	)	$	1,345,379
Net income (loss)	$	217,674	$	(14,900	)	$	3,778	$	—		$	206,552



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2015
Operating revenues ^(a)(b)	$	1,188,343	$	53,354		$	7,143	$	—		$	1,248,840
Intersegment revenues	226		107			—		(333		)	—
Total revenues	$	1,188,569	$	53,461		$	7,143	$	(333	)	$	1,248,840
Net income (loss)	$	180,256	$	(6,731	)	$	2,024	$	—		$	175,549


^(a)	Operating revenues include $121 million and $116 million of affiliate electric revenue for the three months ended Sept. 30, 2016 and 2015, respectively.


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



(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



(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2015
Operating revenues ^(a)(b)	$	3,194,369		$	408,060	$	20,867		$	—		$	3,623,296
Intersegment revenues	612			623		—			(1,235		)	—
Total revenues	$	3,194,981		$	408,683	$	20,867		$	(1,235	)	$	3,623,296
Net income (loss)	$	241,354	^(c)	$	17,119	$	(1,819	)	$	—		$	256,654


^(a)	Operating revenues include $359 million of affiliate electric revenue for the nine months ended Sept. 30, 2016 and 2015.


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


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

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11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost



	Three Months Ended Sept. 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,077		$	7,889		$	31		$	40
Interest cost	11,358			10,804			981			953
Expected return on plan assets	(15,236		)	(15,708		)	(43		)	(30		)
Amortization of prior service cost (credit)	234			234			(759		)	(759		)
Amortization of net loss	9,194			11,548			401			523
Net periodic benefit cost	12,627			14,767			611			727
Costs not recognized due to the effects of regulation	(5,295		)	(7,390		)	—			—
Net benefit cost recognized for financial reporting	$	7,332		$	7,377		$	611		$	727




	Nine Months Ended Sept. 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	21,231		$	23,667		$	93		$	120
Interest cost	34,074			32,411			2,943			2,860
Expected return on plan assets	(45,708		)	(47,123		)	(129		)	(90		)
Amortization of prior service cost (credit)	702			702			(2,277		)	(2,277		)
Amortization of net loss	27,582			34,644			1,203			1,569
Net periodic benefit cost	37,881			44,301			1,833			2,182
Costs not recognized due to the effects of regulation	(15,887		)	(23,075		)	—			—
Net benefit cost recognized for financial reporting	$	21,994		$	21,226		$	1,833		$	2,182

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


12.	Other Comprehensive Income

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



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

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	Three Months Ended Sept. 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at July 1	$	(19,484	)	$	107		$	(1,022	)	$	(20,399	)
Other comprehensive loss before reclassifications	(23		)	(2		)	—			(25		)
Losses (gains) reclassified from net accumulated other comprehensive loss	215			—			(7		)	208
Net current period other comprehensive income (loss)	192			(2		)	(7		)	183
Accumulated other comprehensive (loss) income at Sept. 30	$	(19,292	)	$	105		$	(1,029	)	$	(20,216	)



	Nine Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,090	)	$	105	$	(2,096	)	$	(21,081	)
Other comprehensive income before reclassifications	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	)



	Nine Months Ended Sept. 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(19,909	)	$	105	$	(1,010	)	$	(20,814	)
Other comprehensive loss before reclassifications	(20		)	—		—			(20		)
Losses (gains) reclassified from net accumulated other comprehensive loss	637			—		(19		)	618
Net current period other comprehensive income (loss)	617			—		(19		)	598
Accumulated other comprehensive (loss) income at Sept. 30	$	(19,292	)	$	105	$	(1,029	)	$	(20,216	)

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



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2016				Three Months Ended Sept. 30, 2015
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	350		^(a)	$	353		^(a)
Vehicle fuel derivatives	25			^(b)	19			^(b)
Total, pre-tax	375				372
Tax benefit	(162		)		(157		)
Total, net of tax	213				215
Defined benefit pension and postretirement losses (gains):
Amortization of net loss	83			^(c)	38			^(c)
Prior service credit	(49		)	^(c)	(49		)	^(c)
Total, pre-tax	34				(11		)
Tax (benefit) expense	(15		)		4
Total, net of tax	19				(7		)
Total amounts reclassified, net of tax	$	232			$	208

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	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2016				Nine Months Ended Sept. 30, 2015
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	1,042		^(a)	$	1,037		^(a)
Vehicle fuel derivatives	82			^(b)	49			^(b)
Total, pre-tax	1,124				1,086
Tax benefit	(467		)		(449		)
Total, net of tax	657				637
Defined benefit pension and postretirement losses (gains):
Amortization of net loss	249			^(c)	117			^(c)
Prior service credit	(147		)	^(c)	(147		)	^(c)
Total, pre-tax	102				(30		)
Tax (benefit) expense	(45		)		11
Total, net of tax	57				(19		)
Total amounts reclassified, net of tax	$	714			$	618


^(a)	Included in interest charges.


^(b)	Included in O&M expenses.


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

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

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

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.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including NSP-Minnesota’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016 June 30, 2016), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.

Results of Operations

NSP-Minnesota’s net income was approximately $379.4 million for the nine months ended Sept. 30, 2016, compared with approximately $256.7 million for the same period in 2015. The impact of the 2015 Monticello LCM/EPU project loss along with higher electric revenues, primarily due to an interim electric rate increase in Minnesota (subject to refund), and non-fuel riders were partially offset by higher depreciation, O&M expenses, interest charges and property taxes. See Note 5 to the consolidated financial statements for further discussion of the Monticello LCM/EPU project loss.

Electric Revenues and Margin

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



	Nine Months Ended Sept. 30
(Millions of Dollars)	2016			2015
Electric revenues	$	3,333		$	3,194
Electric fuel and purchased power	(1,149		)	(1,217		)
Electric margin	$	2,184		$	1,977

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

Electric Revenues



(Millions of Dollars)	2016 vs. 2015
Retail rate increases ^(a)	$	109
Non-fuel riders	27
Trading	27
Transmission revenue	22
Conservation program revenue (offset by expenses)	14
Estimated impact of weather	13
Conservation incentive	6
Fuel and purchased power cost recovery	(77		)
Decoupling - Minnesota	(7		)
Other, net	5
Total increase in electric revenues	$	139

Electric Margin



(Millions of Dollars)	2016 vs. 2015
Retail rate increases ^(a)	$	109
Non-fuel riders	27
Interchange revenues from NSP-Wisconsin	22
Conservation program revenue (offset by expenses)	14
Estimated impact of weather	13
Conservation incentive	6
Transmission revenue, net of costs	3
Decoupling - Minnesota	(7		)
Other, net	20
Total increase in electric margin	$	207


^(a)	Increase is primarily due to interim rates in Minnesota (subject to and net of estimated provision for refund). See Note 5 to the consolidated financial statements.

Natural Gas Revenues and Margin

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



	Nine Months Ended Sept. 30
(Millions of Dollars)	2016			2015
Natural gas revenues	$	314		$	408
Cost of natural gas sold and transported	(164		)	(255		)
Natural gas margin	$	150		$	153

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

Natural Gas Revenues



(Millions of Dollars)	2016 vs. 2015
Purchased natural gas adjustment clause recovery	$	(95	)
Estimated impact of weather	(6		)
Conservation program revenue (offset by expenses)	4
Infrastructure rider	3
Total decrease in natural gas revenues	$	(94	)

Natural Gas Margin



(Millions of Dollars)	2016 vs. 2015
Estimated impact of weather	$	(6	)
Conservation program revenue (offset by expenses)	4
Infrastructure rider	3
Other, net	(4		)
Total decrease in natural gas margin	$	(3	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $37.9 million, or 4.1 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was primarily due to additional maintenance activities as well as interchange agreement billings with NSP-Wisconsin related to projects placed in service, which were partially offset by lower nuclear costs.

Conservation Program Expenses — Conservation program expenses increased $17.8 million for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was primarily attributable to more customer participation in the programs which has led to additional customer rebates and increased program implementation costs. Higher conservation program expenses are generally offset by higher revenues.

Depreciation and Amortization — Depreciation and amortization expense increased $88.7 million, or 25.1 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was primarily attributable to capital investments, including Pleasant Valley and Border Wind Farms, reduction of the excess depreciation reserve in Minnesota and the full amortization of the DOE settlement in 2015.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $9.0 million, or 5.1 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was due to higher property taxes primarily in Minnesota, excluding the impact of the proposed settlement agreement in the Minnesota 2016 multi-year electric rate case.

Interest Charges — Interest charges increased $14.0 million, or 9.1 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was related to higher long-term debt levels to fund capital investment, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $41.0 million for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase in income tax expense was primarily due to higher pre-tax earnings in 2016 partially offset by an increase in wind production tax credits and research and experimentation credits in 2016. The ETR was 31.7 percent for the nine months ended Sept. 30, 2016, compared with 34.5 percent for the same period in 2015. The lower ETR in 2016 is primarily due to the adjustments referenced above.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1. of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015, 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, 2016 and June 30, 2016, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

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

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

Specific terms of the proposal include:


•	The addition of 1,800 MW of wind and 1,400 MW of solar between 2016-2030, including approximately 650 MW of solar from NSP-Minnesota’s community solar gardens program by 2020;


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


•	Partial replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site to coincide with the Unit 1 retirement;


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


•	Operation of the Monticello and PI nuclear plants through their current license periods in the early 2030’s - and a commitment to provide additional information regarding forecasted cost increases at PI through end of licensed life if the MPUC wishes to further explore alternatives to operating PI through its current license periods.

In October 2016, the MPUC verbally approved NSP-Minnesota’s plan, with modifications as follows:


•	The acquisition of at least 1,000 MW of wind by 2019, with additional acquisitions dependent on considerations such as price, bidder qualifications, rate impact, transmission availability and location;


•	The acquisition of 650 MW of solar before 2021 through the community solar gardens program or other acquisitions - and pursuit of additional, cost-effective solar resources if it is in the best interests of its customers;


•	Determination of the proper mix of purchased power and Company-owned renewable resources shall be made during the resource acquisition process;


•	Retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026, and a finding that more likely than not, there will be a need for approximately 750 MW of capacity coinciding with the retirement of Sherco Unit 1 in 2026;


•	Authorization for NSP-Minnesota to file a petition for a certificate of need to select the resource that best meets the system resource and local reliability needs associated with the retirement of Sherco Unit 1 in 2026;


•	Acquisition of no less than 400 MW of additional demand response by 2023; and


•	Submission of NSP-Minnesota’s next Resource Plan by February 2019.

The MPUC’s order on NSP-Minnesota’s Resource Plan is expected in late 2016.

Request for Proposal (RFP) — In September 2016, NSP-Minnesota issued a RFP for 1,500 MW of wind generation to be in service by 2020. The RFP requests both PPAs and Build-Own-Transfer proposals. NSP-Minnesota intends to compare self-build options to the RFP bids to ensure that all resource additions are cost-competitive.

In October 2016, NSP-Minnesota submitted a petition for approval to the MPUC of a 750 MW self-build wind farm portfolio. RFP bids were received in October 2016 and will be evaluated in conjunction with the self-build proposal.

An overview of the anticipated RFP schedule is as follows:


•	Project proposal selection and negotiation will occur from November 2016 to March 2017;


•	An NSP-Minnesota recommendation for proposed wind additions to the MPUC in the first quarter of 2017; and


•	MPUC approval is expected by July 2017.

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Minnesota Solar — Minnesota legislation requires 1.5 percent of a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. Of the 1.5 percent, 10 percent must come from systems sized 20 kilowatts or less. NSP-Minnesota anticipates it will meet its compliance requirements through large and small scale solar additions.

NSP-Minnesota also offers customer solar programs: a solar production incentive program for rooftop solar, called Solar*Rewards®, and a community solar garden program that provides bill credits to participating subscribers, called Solar*Rewards® Community®. Additionally, the DOC offers the “Made in Minnesota” program, providing incentives for the installation of small solar systems that were manufactured in-state, which generates renewable energy credits for utilities including NSP-Minnesota.

In August 2015, the MPUC issued an order regarding the Solar*Rewards Community program, limiting the size of solar installations eligible to participate in the program. The order was appealed to the Minnesota Court of Appeals, which affirmed the MPUC’s decision. The decision was subsequently appealed to the Minnesota Supreme Court, which denied the appeal in September 2016, terminating the case.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. See Note 12 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 for further discussion regarding the nuclear generating plants. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1. of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2015, and Nuclear Power Operations included in Item 2 of NSP-Minnesota’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated herein by reference.

Summary of Recent Federal Regulatory Developments

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. In April 2016, the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations. These changes include requirements around use of automatic or remote-controlled shut-off valves; testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations.

NSP-Minnesota continues to analyze the proposed rule changes as they relate to costs, current operations and financial results. PHMSA has indicated that they intend for the rules to go into effect in late 2017 or early 2018.

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

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2015 and Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

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FERC Order, New ROE Policy — The FERC has adopted a new two-step ROE methodology for electric utilities. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. There are two ROE complaints against the MISO TOs, which include NSP-Minnesota and NSP-Wisconsin. In September 2016, the FERC issued an order in the first MISO ROE complaint which upheld the initial decision made by the ALJ in December 2015. The second complaint is pending FERC action after issuance of an initial decision by the ALJ in June 2016. FERC is not expected to issue an order in the second litigated MISO ROE complaint proceeding until 2017. See Note 5 to the consolidated financial statements for discussion of the MISO ROE Complaints.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, NSP-Minnesota and NSP-Wisconsin filed changes to their transmission formula rates to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings were intended to ensure that NSP-Minnesota and NSP-Wisconsin are in compliance with IRS rules and may continue to use accelerated tax depreciation. In December 2015, the FERC partially accepted the proposed NSP-Minnesota and NSP-Wisconsin transmission formula rate changes, but rejected changes regarding the treatment of ADIT in the formula rate true-up. In September 2016, FERC issued an order clarifying that NSP-Minnesota and NSP-Wisconsin may incorporate ADIT true-up provisions in their formula rate. However, submission of a new tariff change filing is required to implement the change. NSP-Minnesota and NSP-Wisconsin expect to file a change to their transmission formula rate in the fourth quarter of 2016 and will request a Jan. 1, 2016 effective date.

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

In January 2016, the FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provides a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period (February 2014 to January 2016) and $16 million annually prospectively starting Feb. 1, 2016, subject to a true-up. In January 2016, SPP filed a proposal regarding distribution of the MISO revenues to SPP members, including SPS. In March 2016, the FERC issued an order rejecting one component of the SPP filing, accepting the remainder of the SPP tariff proposal subject to refund. In August 2016, MISO and other parties filed a settlement regarding the April 2014 MISO tariff change filing to recover SPP JOA charges in MISO rates. The settlement is pending FERC approval. NSP-Minnesota and NSP-Wisconsin expect to be able to recover any resulting MISO charges in retail rates. The JOA revenue allocated to SPS under the filed SPP proposal was not expected to be material.

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, 2016, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

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

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Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

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

Item 1A — RISK FACTORS

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

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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)).
10.01*+	Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to Form 10-Q of Xcel Energy dated Oct. 28, 2016 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2016 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

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



		Northern States Power Company (a Minnesota corporation)

Oct. 31, 2016	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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

Sept. 30, 2016

Dec. 31, 2015

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel