NORTHERN STATES POWER CO - FORM 10-Q

NORTHERN STATES POWER CO - FORM 10-Q - October 30, 2015

Attached files

Attached files

NORTHERN STATES POWER CO Reports

file	filename
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO	nspmex3102q32015.htm
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO	nspmex3101q32015.htm
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO	nspmex9901q32015.htm
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO	nspmex3201q32015.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, 2015



¨	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. 30, 2015
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	31
Item 4 —	Controls and Procedures	36

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	37

SIGNATURES		38

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
	2015			2014			2015			2014
Operating revenues
Electric, non-affiliates	$	1,072,207		$	1,004,863		$	2,835,528		$	2,835,737
Electric, affiliates	116,136			116,192			358,841			354,515
Natural gas	53,354			62,339			408,060			528,252
Other	7,143			6,819			20,867			20,794
Total operating revenues	1,248,840			1,190,213			3,623,296			3,739,298

Operating expenses
Electric fuel and purchased power	433,993			411,621			1,217,192			1,264,834
Cost of natural gas sold and transported	16,742			31,416			255,350			368,724
Cost of sales — other	4,563			4,435			13,357			12,736
Operating and maintenance expenses	290,865			296,707			916,427			902,808
Conservation program expenses	17,573			32,589			49,662			99,497
Depreciation and amortization	119,630			102,841			353,950			303,932
Taxes (other than income taxes)	54,784			57,859			177,103			175,034
Loss on Monticello life cycle management/extended power uprate project	—			—			124,226			—
Total operating expenses	938,150			937,468			3,107,267			3,127,565

Operating income	310,690			252,745			516,029			611,733

Other (expense) income, net	(296		)	(484		)	1,389			1,049
Allowance for funds used during construction — equity	7,456			6,296			19,070			17,555

Interest charges and financing costs
Interest charges — includes other financing costs of $1,706, $1,651, $4,953 and $4,863, respectively	53,152			51,183			154,008			147,724
Allowance for funds used during construction — debt	(3,428		)	(2,808		)	(9,182		)	(7,993		)
Total interest charges and financing costs	49,724			48,375			144,826			139,731

Income before income taxes	268,126			210,182			391,662			490,606
Income taxes	92,577			75,713			135,008			172,507
Net income	$	175,549		$	134,469		$	256,654		$	318,099

See Notes to Consolidated Financial Statements

Table of Contents

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2015			2014			2015			2014
Net income	$	175,549		$	134,469		$	256,654		$	318,099

Other comprehensive income

Pension and retiree medical benefits:
Amortization of (gains) losses included in net periodic benefit cost, net of tax of $(4), $5, $(11) and $13, respectively	(7		)	5			(19		)	16

Derivative instruments:
Net fair value decrease, net of tax of $(16), $(17), $(13), and $(13), respectively	(23		)	(25		)	(20		)	(19		)
Reclassification of losses to net income, net of tax of $157, $154, $449 and $425, respectively	215			187			637			580
	192			162			617			561
Marketable securities:
Net fair value (decrease) increase, net of tax of $(1), $1, $0, and $27, respectively	(2		)	2			—			39

Other comprehensive income	183			169			598			616
Comprehensive income	$	175,732		$	134,638		$	257,252		$	318,715

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
	2015			2014
Operating activities
Net income	$	256,654		$	318,099
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	358,210			308,058
Nuclear fuel amortization	82,627			92,278
Deferred income taxes	150,686			141,331
Amortization of investment tax credits	(1,299		)	(1,368		)
Allowance for equity funds used during construction	(19,070		)	(17,555		)
Loss on Monticello life cycle management/extended power uprate project	124,226			—
Net realized and unrealized hedging and derivative transactions	12,981			3,667
Changes in operating assets and liabilities:
Accounts receivable	37,538			(50,666		)
Accrued unbilled revenues	58,740			62,776
Inventories	(55,075		)	(19,841		)
Other current assets	44,458			(10,669		)
Accounts payable	(37,645		)	(73,307		)
Net regulatory assets and liabilities	18,491			95,605
Other current liabilities	71,837			51,371
Pension and other employee benefit obligations	(28,789		)	(46,727		)
Change in other noncurrent assets	(157		)	34,138
Change in other noncurrent liabilities	(20,965		)	(16,190		)
Net cash provided by operating activities	1,053,448			871,000

Investing activities
Utility capital/construction expenditures	(907,315		)	(864,501		)
Allowance for equity funds used during construction	19,070			17,555
Proceeds from insurance recoveries	27,237			6,000
Purchases of investments in external decommissioning fund	(773,260		)	(499,493		)
Proceeds from the sale of investments in external decommissioning fund	753,924			494,554
Investments in utility money pool arrangement	(187,900		)	(397,000		)
Repayments from utility money pool arrangement	169,900			389,000
Other, net	(501		)	(893		)
Net cash used in investing activities	(898,845		)	(854,778		)

Financing activities
Repayments of short-term borrowings, net	(142,000		)	(131,000		)
Borrowings under utility money pool arrangement	213,500			333,000
Repayments under utility money pool arrangement	(213,500		)	(367,000		)
Proceeds from issuance of long-term debt	588,003			295,356
Repayments of long-term debt	(250,013		)	—
Capital contributions from parent	125,957			95,028
Dividends paid to parent	(198,759		)	(192,241		)
Net cash (used in) provided by financing activities	123,188			33,143

Net change in cash and cash equivalents	277,791			49,365
Cash and cash equivalents at beginning of period	40,597			42,920
Cash and cash equivalents at end of period	$	318,388		$	92,285

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(155,931	)	$	(151,002	)
Cash received (paid) for income taxes, net	53,021			(16,087		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	101,075		$	206,549

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, 2015			Dec. 31, 2014
Assets
Current assets
Cash and cash equivalents	$	318,388		$	40,597
Accounts receivable, net	335,214			367,696
Accounts receivable from affiliates	18,989			24,067
Investments in utility money pool arrangement	18,000			—
Accrued unbilled revenues	192,847			251,587
Inventories	345,483			290,287
Regulatory assets	193,868			235,487
Derivative instruments	30,872			60,164
Deferred income taxes	108,245			76,016
Prepayments and other	72,678			142,443
Total current assets	1,634,584			1,488,344

Property, plant and equipment, net	11,961,454			11,661,620

Other assets
Nuclear decommissioning fund and other investments	1,713,046			1,735,316
Regulatory assets	1,143,417			1,051,834
Derivative instruments	23,608			15,434
Other	39,334			34,768
Total other assets	2,919,405			2,837,352
Total assets	$	16,515,443		$	15,987,316

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	11		$	250,013
Short-term debt	—			142,000
Accounts payable	354,211			470,507
Accounts payable to affiliates	47,856			50,545
Regulatory liabilities	86,261			171,608
Taxes accrued	211,789			198,509
Accrued interest	46,524			61,339
Dividends payable to parent	60,382			77,802
Derivative instruments	17,230			12,294
Other	294,267			217,215
Total current liabilities	1,118,531			1,651,832

Deferred credits and other liabilities
Deferred income taxes	2,607,472			2,429,143
Deferred investment tax credits	26,268			27,567
Regulatory liabilities	483,829			451,783
Asset retirement obligations	2,274,857			2,186,174
Derivative instruments	131,302			135,036
Pension and employee benefit obligations	311,811			340,774
Other	126,148			123,165
Total deferred credits and other liabilities	5,961,687			5,693,642

Commitments and contingencies
Capitalization
Long-term debt	4,533,857			3,938,669
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively	10			10
Additional paid in capital	3,083,936			2,961,654
Retained earnings	1,837,638			1,762,323
Accumulated other comprehensive loss	(20,216		)	(20,814		)
Total common stockholder’s equity	4,901,368			4,703,173
Total liabilities and equity	$	16,515,443		$	15,987,316

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, 2015 and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2015 and 2014; and its cash flows for the nine months ended Sept. 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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, 2014, filed with the SEC on Feb. 20, 2015. 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, 2014, 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. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, 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.

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. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. NSP-Minnesota does not expect the implementation of ASU 2015-02 to have a material 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 amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, NSP-Minnesota does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

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 removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, NSP-Minnesota does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

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3.	Selected Balance Sheet Data



(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	355,295		$	390,633
Less allowance for bad debts	(20,081		)	(22,937		)
	$	335,214		$	367,696



(Thousands of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	200,309	$	157,376
Fuel	101,933		77,139
Natural gas	43,241		55,772
	$	345,483	$	290,287



(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	15,321,574		$	14,831,286
Natural gas plant	1,211,779			1,177,021
Common and other property	577,636			568,287
Construction work in progress	741,982			706,979
Total property, plant and equipment	17,852,971			17,283,573
Less accumulated depreciation	(6,266,646		)	(6,012,145		)
Nuclear fuel	2,414,986			2,347,422
Less accumulated amortization	(2,039,857		)	(1,957,230		)
	$	11,961,454		$	11,661,620


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, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2015, 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, 2015, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

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



(Millions of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	12.1	$	12.2
Unrecognized tax benefit — Temporary tax positions	23.0		18.2
Total unrecognized tax benefit	$	35.1	$	30.4

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



(Millions of Dollars)	Sept. 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(14.1	)	$	(10.8	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process and audit progress and state audits resume. As the IRS appeals process moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $4 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, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2015 or Dec. 31, 2014.


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, 2014 and in Note 5 to the consolidated financial statements included in NSP-Minnesota’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

Minnesota 2014 Multi-Year Electric Rate Case — In November 2013, NSP-Minnesota filed a two-year electric rate case with the MPUC. The rate case was based on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015. The NSP-Minnesota electric rate case initially reflected a requested increase in revenues of approximately $193 million, or 6.9 percent, in 2014 and an additional $98 million, or 3.5 percent, in 2015. The request included a proposed rate moderation plan for 2014 and 2015. In December 2013, the MPUC approved interim rates of $127 million, effective Jan. 3, 2014, subject to refund. In 2014, NSP-Minnesota revised its requested rate increase to $115.3 million for 2014 and to $106.0 million for 2015, for a total combined unadjusted increase of $221.3 million.

In May 2015, the MPUC ordered a 2014 rate increase and a 2015 step increase. The total increase was estimated to be $166.1 million, or 5.9 percent, consisting of $58.9 million and $125.2 million in 2014 and 2015, respectively, and an $18.0 million adjustment related to disallowance of certain Monticello Life Cycle Management (LCM)/Extended Power Uprate (EPU) costs. The MPUC also approved a three-year, decoupling pilot with a 3 percent cap on base revenue for the residential and small commercial and industrial classes, based on actual sales, effective Jan. 1, 2016. The decoupling mechanism would eliminate the impact of changes in electric sales due to conservation and weather variability for these classes.

In July 2015, the MPUC deliberated on requests for reconsideration of its order and determined the Monticello EPU project was not yet used-and-useful, as final approval related to the full EPU uprate condition had not been received from the Nuclear Regulatory Commission (NRC) as of June 30, 2015. As a result, $13.8 million was excluded from final rates. Monticello subsequently received final NRC compliance approval in July 2015. The MPUC also approved 2015 interim rates effective March 3, 2015 and stated that the 2014 interim rate refund obligation be netted against the 2015 interim rate revenue under-collections.

The MPUC’s decisions resulted in a total estimated 2014 and 2015 annual rate increase of $149.4 million or 5.3 percent.

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The following table outlines the impact of the MPUC’s July decision:



(Millions of Dollars)	MPUC July Decision
2014 and 2015 step increase - based on MPUC May order	$	166.1
Reconsideration/clarification adjustments:
2015 Monticello EPU used-and-useful adjustment	(13.8		)
2014 property tax final true-up	(3.1		)
Other, net	0.2
Total 2014 and 2015 step increase	$	149.4
Impact of interim rate effective March 3, 2015	(3.6		)
Estimated revenue impact	$	145.8

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

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014. As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC.

2016 Transmission Cost Recovery (TCR) Rate Filing — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. The 2016 TCR rider filing includes an option to keep within the TCR rider approximately $59.1 million of revenue requirements associated with two CapX2020 projects completed in 2015 or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. If the MPUC opts to maintain the projects in the rider, the TCR rider revenue requirements would increase to $78.3 million.

Pending Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

South Dakota Infrastructure Rider — In October 2015, NSP-Minnesota filed its 2016 infrastructure rider filing with the SDPUC, requesting approval for recovery of $10.3 million in 2016 revenue requirements for rates effective Jan. 1, 2016. As part of the South Dakota 2015 electric rate case, the infrastructure rider was refreshed with new projects and was also expanded as a mechanism to allow for possible recovery of other investments related to generation, transmission, and distribution. A SDPUC decision is expected in the fourth quarter of 2015.

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 certain MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.

Subsequently, the FERC issued and upheld an order adopting a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

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The ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent. The FERC staff recommended a ROE of 8.68 percent. The MISO TOs recommended a ROE not less than 10.8 percent. An administrative law judge (ALJ) initial decision is anticipated to be issued by November 2015 and a FERC order is expected to be issued no earlier than 2016.

Certain MISO TOs requested FERC approval of a 50 basis point RTO membership ROE adder, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. Certain intervenors sought rehearing of the FERC order granting the ROE adder; FERC action is pending.

Certain intervenors filed a second complaint in February 2015 to reduce the MISO region ROE to 8.67 percent, prior to an adder. A hearing has been set, and a refund effective date of Feb. 12, 2015 was established. The complainants and intervenors filed direct testimony in September 2015 recommending ROEs between 8.72 percent and 9.13 percent. The MISO TOs filed answering testimony on Oct. 20, 2015, recommending a ROE of not less than 10.75 percent. FERC staff is expected to file testimony in November 2015, and a hearing is scheduled for February 2016. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. Currently, the ROE refund obligation initiated under the November 2013 complaint is effective through May 2016. The MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints. NSP-Minnesota and NSP-Wisconsin sought rehearing of the FERC's decision not to order changes to the ROE used by non-jurisdictional MISO transmission owners (more than 20 municipal, cooperative and other utilities who are not respondents to the ROE complaints), which equals the ROE presently used by the jurisdictional MISO TOs. FERC action is pending.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of Sept. 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System.


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, 2014 and in Notes 5 and 6 to the consolidated financial statements included in NSP-Minnesota’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015, and June 30, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Purchased Power Agreements (PPAs)

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

NSP-Minnesota had approximately 1,069 MW of capacity under long-term PPAs as of Sept. 30, 2015 and Dec. 31, 2014, with entities that have been determined to be variable interest entities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2028.

Guarantees

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

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



(Millions of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Guarantees issued and outstanding	$	4.8	$	4.8

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Environmental Contingencies

Fargo, N.D. Manufactured Gas Plant (MGP) Site — In May 2015, in connection with a city water main replacement and street improvement project in Fargo, N.D., underground pipes, tars and impacted soils, which may be related to a former MGP site operated by NSP-Minnesota or a prior company, were discovered. After initial reports and discussions with the City of Fargo and the North Dakota Department of Health, NSP-Minnesota removed the impacted soils and other materials from the project area. NSP-Minnesota is undertaking further investigation of the location of the historic MGP site and nearby properties. At this time, NSP-Minnesota’s investigation of the site is considered preliminary as information is still being gathered.

As of Sept. 30, 2015, NSP-Minnesota had recorded a liability of $1.4 million related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as potentially responsible parties. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In July 2015, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for approval to initially defer the portion of investigation and response costs allocable to the North Dakota jurisdiction.

Environmental Requirements

Water

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 2015, the Environmental Protection Agency (EPA) issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. NSP-Minnesota is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. NSP-Minnesota believes that compliance costs would be recoverable through regulatory mechanisms.

Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings.

Air

Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90-day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA's state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which NSP-Minnesota operates. Until NSP-Minnesota has reviewed the final rule and has more information about state implementation plans (SIPs), NSP-Minnesota cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. NSP-Minnesota believes that compliance costs will be recoverable through regulatory mechanisms.

GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. The final rule was published in October 2015. NSP-Minnesota does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

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GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule was published in October 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if NSP-Minnesota were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule.

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

In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect.

In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015.

NSP-Minnesota can operate within its CSAPR emission allowance allocations. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, NSP-Minnesota had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. NSP-Minnesota also retired two coal units at the Black Dog plant. In June 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. NSP-Minnesota believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

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

In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO₂. The MPCA concluded selective catalytic reductions (SCRs) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million. NSP-Minnesota anticipates these costs will be fully recoverable in rates.

The MPCA supplemented its SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 SIP. In June 2012, the EPA approved the SIP for EGUs and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the SIP, but avoided characterizing them as BART limits.

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In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit). NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. In October 2014, the Eighth Circuit set a briefing schedule that was completed in February 2015. The Eighth Circuit heard arguments in September 2015 and a decision is anticipated in early 2016. If this litigation ultimately results in further EPA proceedings concerning the SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

Reasonably Attributable Visibility Impairment (RAVI) — RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the U.S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to determine whether there is RAVI-type impairment in these parks and identify the potential source of the impairment. If the EPA finds that Sherco Units 1 and 2 cause or contribute to RAVI in the national parks, the EPA would then evaluate whether the level of controls required by the MPCA is appropriate. The EPA has stated it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.

In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota (Minnesota District Court) by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The District Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the Eighth Circuit, which on July 23, 2014, reversed the District Court and found that NSP-Minnesota has standing and a right to intervene.

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

As required by the CAA, the EPA published notice of the proposed settlement in the Federal Register. The EPA reviewed the public comments in July 2015 and notified the Minnesota District Court that the settlement agreement is final. The EPA has seven months to recommend and adopt a rule which will set the agreed-upon SO₂emissions. In October 2015, the EPA proposed a rule that would set the agreed-upon SO₂ emission limits, which public comments due in November 2015. NSP-Minnesota does not anticipate the costs of compliance with the proposed settlement will have a material impact on the results of operations, financial position or cash flows.

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

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan for the respective areas 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 would be evaluated in the next designation phase, ending December 2017. NSP-Minnesota cannot evaluate the impacts of this ruling until the designation of nonattainment areas is made and any required state plans are developed.

Revisions to the NAAQS for Ozone — In October 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In areas where NSP-Minnesota operates, current monitored air quality concentrations comply with the new standard in the Twin Cities Metropolitan Area in Minnesota. In documents issued with the new standard, the EPA projects the Twin Cities Metropolitan Area will meet the new standard. Therefore, NSP-Minnesota 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.

Employment, Tort and Commercial Litigation

Biomass Fuel Handling Reimbursement — NSP-Minnesota has a PPA through which it procures energy from Benson Power, LLC (Benson Power), as assignee of Fibrominn, LLC. Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Benson Power's generation facility. Benson Power also sought additional cost reimbursement for certain transportation, handling and other costs incurred since 2007 totaling approximately $20 million. In August 2015, a settlement was reached regarding this dispute. No loss was recorded related to the terms of the settlement agreement.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contracts between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the Court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013. In January 2014, the United States proposed, and NSP-Minnesota accepted, an extension to the settlement agreement which will allow NSP-Minnesota to recover spent fuel storage costs through 2016. The extension does not address costs for spent fuel storage after 2016; such costs could be the subject of future litigation. In December 2014, NSP-Minnesota received a settlement payment of $32.8 million. NSP-Minnesota has received a total of $214.7 million of settlement proceeds as of Sept. 30, 2015. In May 2015, NSP-Minnesota submitted a claim for an additional $13.2 million, and the DOE subsequently determined that NSP-Minnesota is entitled to reimbursement of $13.1 million. Payment of this amount is expected by the end of 2015. Amounts received from the installments, except for approved reductions such as legal costs, will be subsequently returned to customers through a reduction of future rate increases or credited through another regulatory mechanism.

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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, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	6			12
Maximum amount outstanding	69			150
Weighted average interest rate, computed on a daily basis	0.57		%	0.21		%
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, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	500		$	500
Amount outstanding at period end	—			142
Average amount outstanding	46			111
Maximum amount outstanding	157			397
Weighted average interest rate, computed on a daily basis	0.39		%	0.26		%
Weighted average interest rate at period end	N/A			0.53

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, 2015 and Dec. 31, 2014, there were $24 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

At Sept. 30, 2015, NSP-Minnesota had the following committed credit facility available (in millions of dollars):



Credit Facility ^(a)		Drawn ^(b)		Available
$	500	$	24	$	476


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


^(b)	Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at Sept. 30, 2015 and Dec. 31, 2014.

Long-Term Borrowings

In August 2015, NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045.

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8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

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

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

Specific valuation methods include the following:

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

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 net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on NSP-Minnesota’s evaluation of its redemption rights, fair value measurements for private equity and real estate investments have been assigned a Level 3.

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 purchased from MISO, PJM Interconnection, LLC, Electric Reliability Council of Texas, Southwest Power Pool, Inc. and New York Independent System Operator, generally referred to as financial transmission rights (FTRs). FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

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

Non-Derivative Instruments Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

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

Unrealized gains for the nuclear decommissioning fund were $298.4 million and $312.1 million at Sept. 30, 2015 and Dec. 31, 2014, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $87.3 million and $74.1 million at Sept. 30, 2015 and Dec. 31, 2014, 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, 2015 and Dec. 31, 2014:



	Sept. 30, 2015
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	33,681	$	33,681	$	—	$	—	$	33,681
Commingled funds	351,676		—		381,230		—		381,230
International equity funds	217,003		—		188,853		—		188,853
Private equity investments	98,133		—		—		145,695		145,695
Real estate	49,151		—		—		71,976		71,976
Debt securities:
Government securities	24,557		—		21,423		—		21,423
U.S. corporate bonds	70,311		—		61,874		—		61,874
International corporate bonds	14,099		—		13,059		—		13,059
Municipal bonds	210,728		—		215,014		—		215,014
Asset-backed securities	2,834		—		2,836		—		2,836
Mortgage-backed securities	11,734		—		12,077		—		12,077
Equity securities:
Common stock	386,176		533,431		—		—		533,431
Total	$	1,470,083	$	567,112	$	896,366	$	217,671	$	1,681,149


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $31.9 million of miscellaneous investments.

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	Dec. 31, 2014
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	24,184	$	24,184	$	—	$	—	$	24,184
Commingled funds	470,013		—		465,615		—		465,615
International equity funds	80,454		—		78,721		—		78,721
Private equity investments	73,936		—		—		101,237		101,237
Real estate	43,859		—		—		64,249		64,249
Debt securities:
Government securities	30,674		—		28,808		—		28,808
U.S. corporate bonds	81,463		—		77,562		—		77,562
International corporate bonds	16,950		—		16,341		—		16,341
Municipal bonds	242,282		—		249,201		—		249,201
Asset-backed securities	9,131		—		9,250		—		9,250
Mortgage-backed securities	23,225		—		23,895		—		23,895
Equity securities:
Common stock	369,751		564,858		—		—		564,858
Total	$	1,465,922	$	589,042	$	949,393	$	165,486	$	1,703,921


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $31.4 million of miscellaneous investments.

The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2015 and 2014:



(Thousands of Dollars)	July 1, 2015		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		Sept. 30, 2015
Private equity investments	$	133,993	$	3,066	$	—		$	8,636	$	145,695
Real estate	70,834		1,501		(1,719		)	1,360		71,976
Total	$	204,827	$	4,567	$	(1,719	)	$	9,996	$	217,671



(Thousands of Dollars)	July 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		Sept. 30, 2014
Private equity investments	$	81,123	$	11,125	$	—		$	4,756	$	97,004
Real estate	65,658		1,530		(5,876		)	2,661		63,973
Total	$	146,781	$	12,655	$	(5,876	)	$	7,417	$	160,977



(Thousands of Dollars)	Jan. 1, 2015		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		Sept. 30, 2015
Private equity investments	$	101,237	$	24,197	$	—		$	20,261	$	145,695
Real estate	64,249		9,633		(4,341		)	2,435		71,976
Total	$	165,486	$	33,830	$	(4,341	)	$	22,696	$	217,671

(Thousands of Dollars)	Jan. 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		Sept. 30, 2014
Private equity investments	$	62,696	$	22,078	$	—		$	12,230	$	97,004
Real estate	57,368		5,386		(5,876		)	7,095		63,973
Total	$	120,064	$	27,464	$	(5,876	)	$	19,325	$	160,977


^(a)	Gains are deferred as a component of the regulatory assets for nuclear decommissioning.

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The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 2015:



	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	$	—	$	—	$	—	$	21,423		$	21,423
U.S. corporate bonds	—		15,398		51,317		(4,841		)	61,874
International corporate bonds	—		2,976		9,109		974			13,059
Municipal bonds	1,260		27,500		44,594		141,660			215,014
Asset-backed securities	—		—		2,836		—			2,836
Mortgage-backed securities	—		—		—		12,077			12,077
Debt securities	$	1,260	$	45,874	$	107,856	$	171,293		$	326,283

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, 2015, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges, as applicable.

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

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

At Sept. 30, 2015, 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, 2015 and 2014.

At Sept. 30, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenue, 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, 2015 and Dec. 31, 2014:


^(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, 2015 and 2014 on accumulated other comprehensive loss, regulatory assets and liabilities and income:




	Three Months Ended Sept. 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains) 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 Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains) 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	)

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	Three Months Ended Sept. 30, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains) 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	$	—		$	—		$	350		^(a)	$	—		$	—
Vehicle fuel and other commodity	(42		)	—			(9		)	^(b)	—			—
Total	$	(42	)	$	—		$	341			$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—		$	(1,656	)	^(c)
Electric commodity	—			(2,212		)	—				5,457		^(d)	—
Natural gas commodity	—			(303		)	—				—			—
Total	$	—		$	(2,515	)	$	—			$	5,457		$	(1,656	)



	Nine Months Ended Sept. 30, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	1,038		^(a)	$	—			$	—
Vehicle fuel and other commodity	(32		)	—			(33		)	^(b)	—				—
Total	$	(32	)	$	—		$	1,005			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—			$	1,266		^(c)
Electric commodity	—			(13,660		)	—				(18,930		)	^(d)	—
Natural gas commodity	—			7,105			—				(9,306		)	^(e)	(580		)	^(e)
Other commodity	—			—			—				—				643			^(c)
Total	$	—		$	(6,555	)	$	—			$	(28,236	)		$	1,329


^(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, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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

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

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At Sept. 30, 2015, five of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $22.6 million or 30 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 $10.2 million or 14 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. Another of these significant counterparties, comprising $5.8 million or 8 percent of this credit exposure, had credit quality less than investment grade, based on NSP-Minnesota's internal analysis. All 10 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. If the credit ratings of Xcel Energy Inc.'s utility subsidiaries were downgraded below investment grade, derivative instruments reflected in a $8.9 million gross liability position on the consolidated balance sheet at Sept. 30, 2015 would have required Xcel Energy Inc.'s utility subsidiaries to post collateral or settle applicable outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $0.1 million. At Dec. 31, 2014, 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, 2015 and Dec. 31, 2014.

Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2015:



	Sept. 30, 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	$	—	$	9,140	$	4,307	$	13,447	$	(5,150	)	$	8,297
Electric commodity	—		—		21,121		21,121		(127		)	20,994
Natural gas commodity	—		1,102		—		1,102		—			1,102
Total current derivative assets	$	—	$	10,242	$	25,428	$	35,670	$	(5,277	)	30,393
PPAs ^(a)												479
Current derivative instruments												$	30,872
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	29,523	$	—	$	29,523	$	(7,411	)	$	22,112
Total noncurrent derivative assets	$	—	$	29,523	$	—	$	29,523	$	(7,411	)	22,112
PPAs ^(a)												1,496
Noncurrent derivative instruments												$	23,608

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	Sept. 30, 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	$	—	$	86	$	—	$	86	$	—		$	86
Other derivative instruments:
Commodity trading	—		6,461		1,478		7,939		(5,592		)	2,347
Electric commodity	—		—		127		127		(127		)	—
Natural gas commodity	—		683		—		683		—			683
Total current derivative liabilities	$	—	$	7,230	$	1,605	$	8,835	$	(5,719	)	3,116
PPAs ^(a)												14,114
Current derivative instruments												$	17,230
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	20	$	—	$	20	$	—		$	20
Other derivative instruments:
Commodity trading	—		20,789		—		20,789		(11,097		)	9,692
Total noncurrent derivative liabilities	$	—	$	20,809	$	—	$	20,809	$	(11,097	)	9,712
PPAs ^(a)												121,590
Noncurrent derivative instruments												$	131,302

^(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, 2015. At Sept. 30, 2015, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.1 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents 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, 2014:



	Dec. 31, 2014
	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	$	—	$	14,326	$	4,732	$	19,058	$	(3,240	)	$	15,818
Electric commodity	—		—		37,051		37,051		(1,512		)	35,539
Natural gas commodity	—		295		—		295		(4		)	291
Total current derivative assets	$	—	$	14,621	$	41,783	$	56,404	$	(4,756	)	51,648
PPAs ^(a)												8,516
Current derivative instruments												$	60,164
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	17,617	$	—	$	17,617	$	(4,151	)	$	13,466
Total noncurrent derivative assets	$	—	$	17,617	$	—	$	17,617	$	(4,151	)	13,466
PPAs ^(a)												1,968
Noncurrent derivative instruments												$	15,434

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	Dec. 31, 2014
	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	$	—	$	65	$	—	$	65	$	—		$	65
Other derivative instruments:
Commodity trading	—		7,974		—		7,974		(7,974		)	—
Electric commodity	—		—		1,512		1,512		(1,512		)	—
Total current derivative liabilities	$	—	$	8,039	$	1,512	$	9,551	$	(9,486	)	65
PPAs ^(a)												12,229
Current derivative instruments												$	12,294
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	56	$	—	$	56	$	—		$	56
Other derivative instruments:
Commodity trading	—		6,890		—		6,890		(6,033		)	857
Total noncurrent derivative liabilities	$	—	$	6,946	$	—	$	6,946	$	(6,033	)	913
PPAs ^(a)												134,123
Noncurrent derivative instruments												$	135,036

^(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, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $6.6 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2015 and 2014:



	Three Months Ended Sept. 30
(Thousands of Dollars)	2015			2014
Balance at July 1	$	35,363		$	71,452
Purchases	78			1,159
Settlements	(12,807		)	(11,685		)
Transfers out of Level 3	—			(1,093		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	121			1,480
Gains (losses) recognized as regulatory assets and liabilities	1,068			(9,920		)
Balance at Sept. 30	$	23,823		$	51,393

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2015			2014
Balance at Jan. 1	$	40,271		$	31,727
Purchases	41,103			82,848
Settlements	(31,652		)	(84,449		)
Transfers out of Level 3	—			(1,093		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	1,401			8,917
(Losses) gains recognized as regulatory assets and liabilities	(27,300		)	13,443
Balance at Sept. 30	$	23,823		$	51,393


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

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2015. The transfer of amounts from Level 3 to Level 2 in the three and nine months ended Sept. 30, 2014 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

Fair Value of Long-Term Debt

As of Sept. 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:



	Sept. 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,533,868	$	4,998,559	$	4,188,682	$	4,803,735

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, 2015 and Dec. 31, 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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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)	2015			2014			2015			2014
Interest (expense) income	$	(226	)	$	247		$	3,198		$	4,001
Other nonoperating income	55			25			147			431
Insurance policy expense	(125		)	(756		)	(1,956		)	(3,383		)
Other (expense) income, net	$	(296	)	$	(484	)	$	1,389		$	1,049


10.	Segment Information

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

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


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


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


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

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

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



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
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

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2014
Operating revenues ^(a)(b)	$	1,121,055	$	62,339		$	6,819	$	—		$	1,190,213
Intersegment revenues	284		143			—		(427		)	—
Total revenues	$	1,121,339	$	62,482		$	6,819	$	(427	)	$	1,190,213
Net income (loss)	$	134,969	$	(5,545	)	$	5,045	$	—		$	134,469


^(a)	Operating revenues include $116 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014.


^(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended Sept. 30, 2015 and 2014.



(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



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2014
Operating revenues ^(a)(b)(c)	$	3,190,252	$	528,252	$	20,794	$	—		$	3,739,298
Intersegment revenues	700		639		—		(1,339		)	—
Total revenues	$	3,190,952	$	528,891	$	20,794	$	(1,339	)	$	3,739,298
Net income	$	284,035	$	21,555	$	12,509	$	—		$	318,099


^(a)	Operating revenues include $359 million and $355 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014, respectively.


^(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the nine months ended Sept. 30, 2015 and 2014.


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


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost



	Three Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,889		$	7,425		$	40		$	47
Interest cost	10,804			11,827			953			1,248
Expected return on plan assets	(15,708		)	(15,730		)	(30		)	(75		)
Amortization of prior service cost (credit)	234			234			(759		)	(759		)
Amortization of net loss	11,548			11,196			523			854
Net periodic benefit cost	14,767			14,952			727			1,315
Costs not recognized due to the effects of regulation	(7,390		)	(7,312		)	—			—
Net benefit cost recognized for financial reporting	$	7,377		$	7,640		$	727		$	1,315

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	Nine Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	23,667		$	22,275		$	120		$	140
Interest cost	32,411			35,481			2,860			3,745
Expected return on plan assets	(47,123		)	(47,190		)	(90		)	(226		)
Amortization of prior service cost (credit)	702			702			(2,277		)	(2,277		)
Amortization of net loss	34,644			33,588			1,569			2,562
Net periodic benefit cost	44,301			44,856			2,182			3,944
Costs not recognized due to the effects of regulation	(23,075		)	(22,383		)	—			—
Net benefit cost recognized for financial reporting	$	21,226		$	22,473		$	2,182		$	3,944

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $32.7 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2015.


12.	Other Comprehensive Income

Changes in accumulated other comprehensive income (loss), net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:



	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	)




	Three Months Ended Sept. 30, 2014
(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	$	(20,210	)	$	110	$	(1,182	)	$	(21,282	)
Other comprehensive (loss) income before reclassifications	(25		)	2		—			(23		)
Losses reclassified from net accumulated other comprehensive loss	187			—		5			192
Net current period other comprehensive income	162			2		5			169
Accumulated other comprehensive (loss) income at Sept. 30	$	(20,048	)	$	112	$	(1,177	)	$	(21,113	)




	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	)

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	Nine Months Ended Sept. 30, 2014
(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	$	(20,609	)	$	73	$	(1,193	)	$	(21,729	)
Other comprehensive (loss) income before reclassifications	(19		)	39		—			20
Losses reclassified from net accumulated other comprehensive loss	580			—		16			596
Net current period other comprehensive income	561			39		16			616
Accumulated other comprehensive (loss) income at Sept. 30	$	(20,048	)	$	112	$	(1,177	)	$	(21,113	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:




	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2015				Three Months Ended Sept. 30, 2014
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	353		^(a)	$	350		^(a)
Vehicle fuel derivatives	19			^(b)	(9		)	^(b)
Total, pre-tax	372				341
Tax benefit	(157		)		(154		)
Total, net of tax	215				187
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	38			^(c)	59			^(c)
Prior service credit	(49		)	^(c)	(49		)	^(c)
Total, pre-tax	(11		)		10
Tax expense (benefit)	4				(5		)
Total, net of tax	(7		)		5
Total amounts reclassified, net of tax	$	208			$	192



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015				Nine Months Ended Sept. 30, 2014
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	1,037		^(a)	$	1,038		^(a)
Vehicle fuel derivatives	49			^(b)	(33		)	^(b)
Total, pre-tax	1,086				1,005
Tax benefit	(449		)		(425		)
Total, net of tax	637				580
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	117			^(c)	175			^(c)
Prior service credit	(147		)	^(c)	(146		)	^(c)
Total, pre-tax	(30		)		29
Tax expense (benefit)	11				(13		)
Total, net of tax	(19		)		16
Total amounts reclassified, net of tax	$	618			$	596


^(a)	Included in interest charges.


^(b)	Included in O&M expenses.


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

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including NSP-Minnesota's Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2014 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership; or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.

Results of Operations

NSP-Minnesota’s net income was approximately $256.7 million for the nine months ended Sept. 30, 2015, compared with approximately $318.1 million for the same period in 2014. The impact of the Monticello LCM/EPU project loss, higher depreciation, higher O&M expenses, lower gas margins, higher interest charges, unfavorable weather and weather normalized sales-decline were partially offset by higher revenue attributable to electric rate cases in Minnesota, North Dakota and South Dakota.

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)	2015			2014
Electric revenues	$	3,194		$	3,190
Electric fuel and purchased power	(1,217		)	(1,265		)
Electric margin	$	1,977		$	1,925

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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)	2015 vs. 2014
Retail rate increases ^(a)	$	85
Transmission Revenue	18
Non-fuel riders	14
Fuel and purchased power recovery	(49		)
Conservation program revenue (offset by expenses)	(42		)
Trading	(17		)
Estimated impact of weather	(15		)
Other, net	10
Total increase in electric revenues	$	4

Electric Margin



(Millions of Dollars)	2015 vs. 2014
Retail rate increases ^(a)	$	85
Non-fuel riders	14
Conservation program revenue (offset by expenses)	(42		)
Estimated impact of weather	(15		)
Other, net	10
Total increase in electric margin	$	52


^(a)	The retail rate increases are due to rate proceedings in Minnesota, South Dakota and North Dakota. 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)	2015			2014
Natural gas revenues	$	408		$	528
Cost of natural gas sold and transported	(255		)	(369		)
Natural gas margin	$	153		$	159

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)	2015 vs. 2014
Purchased natural gas adjustment clause recovery	$	(106	)
Estimated impact of weather	(11		)
Conservation program revenue (offset by expenses)	(8		)
Non-fuel riders	8
Other, net	(3		)
Total decrease in natural gas revenues	$	(120	)

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Natural Gas Margin



(Millions of Dollars)	2015 vs. 2014
Estimated impact of weather	$	(11	)
Conservation program revenue (offset by expenses)	(8		)
Non-fuel riders	8
Other, net	5
Total decrease in natural gas margin	$	(6	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $13.6 million, or 1.5 percent, for the nine months ended Sept. 30, 2015. The increase in O&M expenses is primarily due to interchange billings with NSP-Wisconsin related to the timing of transmission projects as well as the timing of planned maintenance and overhauls at NSP-Minnesota's generation facilities, partially offset by decreases in nuclear expenses primarily due to reduced costs driven by operational initiatives and efficiencies. The following table summarizes the changes in O&M expenses:



(Millions of Dollars)	2015 vs. 2014
Interchange billings with NSP-Wisconsin	$	11
Electric and gas distribution costs	5
Plant generation costs	4
Labor and contract labor	4
Nuclear plant operations and amortization	(7		)
Other, net	(3		)
Total increase in O&M expenses	$	14

Conservation Program Expenses — Conservation program expenses decreased $49.8 million for the nine months ended Sept. 30, 2015. The decrease was primarily attributable to lower electric and gas recovery rates. Lower conservation program expenses are generally offset by lower revenues.

Depreciation and Amortization — Depreciation and amortization expense increased $50.0 million, or 16.5 percent, for the nine months ended Sept. 30, 2015. The increase was primarily attributed to lower amortization of the excess depreciation reserve in Minnesota and normal system expansion, partially offset by Minnesota’s amortization of the DOE settlement.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $2.1 million, or 1.2 percent, for the nine months ended Sept. 30, 2015. The increase was due to higher property taxes primarily in Minnesota.

AFUDC, Equity and Debt — AFUDC increased $2.7 million for the nine months ended Sept. 30, 2015. The increase is primarily due to the expansion of Pleasant Valley Wind production facilities and other transmission facilities.

Interest Charges — Interest charges increased $6.3 million, or 4.3 percent, for the nine months ended Sept. 30, 2015. The increase was primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense decreased $37.5 million for the nine months ended Sept. 30, 2015 compared with the same period in 2014. The decrease in income tax expense was primarily due to lower pre-tax earnings in 2015. This was partially offset by the successful resolution of a 2010-2011 audit issue in 2014. The ETR was 34.5 percent for the nine months ended Sept. 30, 2015, compared with 35.2 percent for the same period in 2014. The lower ETR in 2015 is primarily due to a lower forecasted annual ETR, which is primarily due to increased wind production tax credits. This was partially offset by the successful resolution of a 2010-2011 audit issue in 2014.

Public Utility Regulation and Legislation

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, 2014, and Public Utility Regulation included in Item 2. of NSP-Minnesota's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

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Courtenay Wind Farm — In September 2015, NSP-Minnesota began construction of the Courtenay wind farm, a 200 MW NSP-Minnesota owned project in North Dakota. In May 2015, NSP-Minnesota filed for expedited regulatory approval in Minnesota and North Dakota. In July and August 2015, the MPUC and NDPSC, respectively, approved the Courtenay wind farm with recovery up to $300 million of capital costs. The project costs were requested to be recovered through the Minnesota renewable energy standard rider and the North Dakota renewable energy rider.

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

On Oct. 2, 2015, NSP-Minnesota filed revisions to the Plan. The revised proposal addressed stakeholder recommendations as well as the final Clean Power Plan (CPP) recently issued by the EPA. The revised Plan is based on four primary elements: (1) accelerate the transition from coal energy to renewables, (2) preserve regional system reliability, (3) pursue energy efficiency gains and grid modernization, and (4) ensure customer benefits. The provisions included in the Plan would allow for a 60 percent reduction in carbon emissions from 2005 levels by 2030 and will result in 63 percent of NSP System energy being carbon-free by 2030. Specific terms of the proposal include:


•	The addition of 800 MW of wind and 400 MW of utility scale solar to the pre-2020 time-frame;


•	The addition of 1000 MW wind and 1000 MW utility scale solar between 2020-2030;


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


•	The addition of a 230 MW (approximate capacity, actual size to be determined) natural gas combustion turbine in North Dakota by 2025;


•	Replacement of Sherco coal generation with a 780 MW (approximate capacity, actual size to be determined) natural gas combined cycle unit at the Sherco site no later than 2026; and


•	Operation of the Monticello and PI nuclear plants through their current license periods in the early 2030's.

NSP-Minnesota believes this will provide substantial opportunities for the ownership of replacement and renewable generation. The Plan is currently being reviewed by the MPUC.

CapX2020 — The estimated cost of the five major CapX2020 transmission projects listed below is $2 billion. NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total investment. As of Sept. 30, 2015, Xcel Energy has invested $975.5 million of its $1.1 billion share of the five CapX2020 transmission projects. The projects are as follows:


•	Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 161/345 Kilovolt (KV) transmission line — The project is expected to go into service in the fall of 2016, although segments are being placed in service as they are completed. The first 345 KV segment was energized in September 2015 and stretches from the North Rochester Substation in Minn. to the Briggs Road Substation in Wis.


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


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


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


•	Big Stone South to Brookings County, S.D. 345 KV transmission line — Construction on the line began in September 2015, with completion anticipated in 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 plans to add additional large-scale solar to its system by the end of 2016.

NSP-Minnesota also offers small 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 Department of Commerce offers the Made in Minnesota incentive program for small solar using products made in-state, which generates renewable energy credits for utilities including NSP-Minnesota.

During 2015, NSP-Minnesota sought policy guidance from the MPUC regarding the price and size of Solar*Rewards Community projects. The program was intended for projects one MW or less. Many proposals, however, were sized between 10 and 50 MW. 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, more closely aligning the program with its original intent. The MPUC decision limits projects to five MW or less through Sept. 25, 2015. Subsequently, projects must be one MW or less. In October 2015, the MPUC denied requests for reconsideration of the project size limitation.

Minnesota Legislation — In June 2015, the Minnesota governor signed the Jobs and Energy bill into law. Several approved mechanisms may provide additional options and opportunities in future rate cases, including the duration of future multi-year plans (MYPs) and more certainty regarding recovery of costs and the impact to customers. This bill provides:


•	Increased flexibility for utilities to submit a MYP of up to five years;


•	The potential for full capital recovery for all proposed years;


•	O&M cost recovery based on an index;


•	Distribution costs that facilitate grid modernization are eligible for rider recovery;


•	Natural gas extension costs for unserved areas can be socialized and are eligible for rider recovery;


•	Recovery of plant closure costs, should the MPUC order early plant closure, such as in a resource plan; and


•	Allows implementation of interim rates for the first and second years of the MYP.

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, 2014 for further discussion regarding the nuclear generating plants.

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

At Dec. 31, 2014, Monticello was in Column 3 (degraded cornerstone) with all green performance indicators, a yellow finding related to flood control and a potentially greater than green finding related to plant security. In March 2015, Monticello was upgraded from Column 3 to Column 2 (regulatory response) based on the results of an NRC inspection in late 2014 to close out the flood control finding. The NRC conducted an inspection on the security finding in July 2015. Based on the results of the NRC inspection, Monticello was upgraded to Column 1 on Oct. 1, 2015.

As of Oct. 1, 2015, Monticello and PI Units 1 and 2 were in Column 1 (licensee response) with all green performance indicators and no greater than green findings or violations. Plants in Column 1 are subject to only a pre-defined set of basic NRC inspections.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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 — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In March, 2015, FERC upheld the new ROE methodology and denied rehearing. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any of the litigated ROE complaint proceedings until 2016. See Note 5 to the consolidated financial statements for discussion of the MISO ROE complaints.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Sept. 30, 2015, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Note 5 to the consolidated financial statements for 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, 2014, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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Item 6 — EXHIBITS

* Indicates incorporation by reference



3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern States Power Co. (a Minnesota corporation) as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 000-31387)).
4.01*	Supplemental Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300,000,000 principal amount of 2.20 percent First Mortgage Bonds, Series due Aug. 15, 2020 and $300,000,000 principal amount of 4.00 percent First Mortgage Bonds, Series due Aug. 15, 2045 (Exhibit 4.01 to Form 8-K of NSP-Minnesota dated Aug. 11, 2015 (file no. 001-31387)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2015 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. 30, 2015	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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

Sept. 30, 2015

Dec. 31, 2014

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel